NUREG-1801, Vol. 2, Rev. 1

Generic Aging Lessons

Learned (GALL) Report

Tabulation of Results

Manuscript Completed: September 2005

Date Published: September 2005

Division of Regulatory Improvement Programs

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001
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September 2005 iii NUREG-1801, Rev. 1

ABSTRACT

The Generic Aging Lessons Learned (GALL) report contains the staff's generic evaluation of the 

existing plant programs and documents the technical basis for determining where existing 

programs are adequate without modification and where existing programs should be augmented 

for the extended period of operation. The evaluation results documented in the GALL report 

indicate that many of the existing programs are adequate to manage the aging effects for 

particular structures or components for license renewal without change. The GALL report also 

contains recommendations on specific areas for which existing programs should be augmented 

for license renewal. An applicant may reference the GALL report in a license renewal 

application to demonstrate that the programs at the applicant’s facility correspond to those 

reviewed and approved in the GALL report and that no further staff review is required. The focus 

of the staff review is on the augmented existing programs for license renewal. The incorporation 

of the GALL report information into the NUREG-1800, “Standard Review Plan for Review of 

License Renewal Applications for Nuclear Power Plants,” as directed by the Commission, 

should improve the efficiency of the license renewal process.
NUREG-1801, Rev.1 iv September 2005

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TABLE OF CONTENTS

Abstract.............................................................................................................................. iii

List of Contributors – 2004-2005..................................................................................... xi

Abbreviations.................................................................................................................... xv

Introduction....................................................................................................................... 1

I. Application of ASME Code ..................................................................................... I-i

II. Containment Structures.......................................................................................... II-i

A Pressurized Water Reactor (PWR) Containments ...................................... II A-i

A1 Concrete Containments (Reinforced and Prestressed)...................... II A1-1

A2 Steel Containments ............................................................................. II A2-1

A3 Common Components ........................................................................ II A3-1

B Boiling Water Reactor (BWR) Containments............................................... II B-i

B1 Mark I Containments ........................................................................... II B1-1

B2 Mark II Containments .......................................................................... II B2-1

B3 Mark III Containments ......................................................................... II B3-1

B4 Common Components ........................................................................ II B4-1

III. Structures and Component Supports................................................................... III-i 

A Safety Related and Other Structures........................................................... III A-i

A1 Group 1 Structures (BWR Reactor Building, PWR Shield 

Building, Control Room/Building) ..................................................... III A1-1

A2 Group 2 Structures (BWR Reactor Building with Steel 

Superstructure)................................................................................. III A2-1

A3 Group 3 Structures (Auxiliary Bldg., Diesel Generator Bldg., 

Radwaste Bldg., Turbine Bldg., Switchgear Rm., AFW 

Pumphouse, Utility/Piping Tunnels Yard Structures such as 

AFW Pumphouse, Utility/Piping Tunnels, Security/Lighting 

Poles, Manholes, Duct Banks; SBO Structures such as 

Transmission Towers, Startup Towers Circuit Breaker 

Foundation, Electrical Enclosure).................................................... III A3-1

A4 Group 4 Structures (Containment Internal Structures, 

excluding Refueling Canal) .............................................................. III A4-1

A5 Group 5 Structures (Fuel Storage Facility, Refueling Canal) ............. III A5-1

A6 Group 6 Structures (Water-Control Structures).................................. III A6-1

A7 Group 7 Structures (Concrete Tanks and Missile Barriers)).............. III A7-1

A8 Group 8 Structures (Steel Tanks and Missile Barriers)...................... III A8-1

A9 Group 9 Structures (BWR Unit Vent Stack)........................................ III A9-1

B Component Supports ................................................................................... III B-i

B1 Supports for ASME Piping and Components...................................... III B1-1

B2 Supports for Cable Trays, Conduit, HVAC Ducts, TubeTrack®, 

Instrument Tubing, Non-ASME Piping and Components ............. III B2-1
NUREG-1801, Rev. 1 vi September 2005

III. Structures and Component Supports (continued)

B3 Anchorage of Racks, Panels, Cabinets, and Enclosures 

for Electrical Equipment and Instrumentation.................................. III B3-1

B4 Supports for Emergency Diesel Generator (EDG), 

HVAC System Components, and Other Miscellaneous 

Mechanical Equipment .................................................................... III B4-1

B5 Supports for Platforms, Pipe Whip Restraints, Jet Impingement 

Shields, Masonry Walls, and Other Miscellaneous Structures........ III B5-1

IV. Reactor Vessel, Internals, and Reactor Coolant System.................................... IV-i

A1 Reactor Vessel (BWR) ................................................................................ IV A1-1

A2 Reactor Vessel (PWR)................................................................................. IV A2-1

B1 Reactor Vessel Internals (BWR).................................................................. IV B1-1

B2 Reactor Vessel Internals (PWR) - Westinghouse........................................ IV B2-1

B3 Reactor Vessel Internals (PWR) - Combustion Engineering....................... IV B3-1

B4 Reactor Vessel Internals (PWR) - Babcock and Wilcox.............................. IV B4-1

C1 Reactor Coolant Pressure Boundary (BWR)............................................... IV C1-1

C2 Reactor Coolant System and Connected Lines (PWR)............................... IV C2-1

D1 Steam Generator (Recirculating) ................................................................. IV D1-1

D2 Steam Generator (Once-Through)............................................................... IV D2-1

E Common Miscellaneous Material/Environment Combinations.................... IV E-1

V. Engineered Safety Features................................................................................... V-i

A Containment Spray System (PWR)............................................................. V A-1

B Standby Gas Treatment System (BWR) .................................................... V B-1

C Containment Isolation Components............................................................. V C-1

D1 Emergency Core Cooling System (PWR).................................................... V D1-1

D2 Emergency Core Cooling System (BWR).................................................... V D2-1

E External Surfaces of Components and Miscellaneous Bolting.................... V E-1

F Common Miscellaneous Material/Environment Combinations................ V F-1

VI. Electrical Components............................................................................................ VI-i

A Equipment, Electrical Cables and Connections Not Subject to 10

CFR 50.49 Environmental Qualification Requirements......................... VI A-1

B Equipment Subject to 10 CFR 50.49 Environmental Qualification 

Requirements ......................................................................................... VI B-1

VII. Auxiliary Systems .................................................................................................... VII-i

A1 New Fuel Storage......................................................................................... VII A1-1

A2 Spent Fuel Storage....................................................................................... VII A2-1

A3 Spent Fuel Pool Cooling and Cleanup (PWR)............................................. VII A3-1

A4 Spent Fuel Pool Cooling and Cleanup (BWR)............................................. VII A4-1

A5 Suppression Pool Cleanup System (BWR)................................................. VII A5-1

B Overhead Heavy Load and Light Load (Related to Refueling) 

Handling Systems .................................................................................. VII B-1
September 2005 vii NUREG-1801, Rev. 1

VII. Auxiliary Systems (continued)

C1 Open-Cycle Cooling Water System (Service Water System)..................... VII C1-1

C2 Closed-Cycle Cooling Water System........................................................... VII C2-1

C3 Ultimate Heat Sink ....................................................................................... VII C3-1

D Compressed Air System............................................................................... VII D-1

E1 Chemical and Volume Control System (PWR)............................................ VII E1-1

E2 Standby Liquid Control System (BWR) ....................................................... VII E2-1

E3 Reactor Water Cleanup System (BWR) ...................................................... VII E3-1

E4 Shutdown Cooling System (Older BWR)..................................................... VII E4-1

F1 Control Room Area Ventilation System ....................................................... VII F1-1

F2 Auxiliary and Radwaste Area Ventilation System........................................ VII F2-1

F3 Primary Containment Heating and Ventilation System ............................... VII F3-1

F4 Diesel Generator Building Ventilation System ............................................ VII F4-1

G Fire Protection ............................................................................................. VII G-1

H1 Diesel Fuel Oil System................................................................................. VII H1-1

H2 Emergency Diesel Generator System ......................................................... VII H2-1

I External Surfaces of Components and Miscellaneous Bolting.................... VII I-1

J Common Miscellaneous Material/Environment Combinations.................... VII J-1

VIII. Steam and Power Conversion System ................................................................. VIII-i

A Steam Turbine System................................................................................. VIII A-1

B1 Main Steam System (PWR)......................................................................... VIII B1-1

B2 Main Steam System (BWR)......................................................................... VIII B2-1

C Extraction Steam System............................................................................. VIII C-1

D1 Feedwater System (PWR)............................................................................ VIII D1-1

D2 Feedwater System (BWR)............................................................................ VIII D2-1

E Condensate System..................................................................................... VIII E-1

F Steam Generator Blowdown System (PWR)............................................... VIII F-1

G Auxiliary Feedwater System (PWR)............................................................. VIII G-1

H External Surfaces of Components and Miscellaneous Bolting.................... VIII H-1

I Common Miscellaneous Material/Environment Combinations.................... VIII I-1

IX. Selected Definitions and Use of Terms For Structures, Components, 

Materials, Environments, Aging Effects, And Aging Mechanisms ................... IX-i

X. Time-Limited Aging Analyses [Evaluation of Aging Management 

Programs under 10 CFR 54.21(c)(1)(iii)]................................................................ X-i

X.M1 Metal Fatigue of Reactor Coolant Pressure Boundary ............................. X M-1

X.S1 Concrete Containment Tendon Prestress ................................................ X S-1

X.E1 Environmental Qualification (EQ) of Electric Components ....................... X E-1

XI. Aging Management Programs (AMPs).................................................................. XI-i

XI.M1 ASME Section XI Inservice Inspection, Subsections IWB, IWC, and 

IWD......................................................................................................... XI M-1

XI.M2 Water Chemistry......................................................................................... XI M-10

XI.M3 Reactor Head Closure Studs ..................................................................... XI M-16
NUREG-1801, Rev. 1 viii September 2005

XI. Aging Management Programs (AMPs) (continued)

XI.M4 BWR Vessel ID Attachment Welds............................................................ XI M-19

XI.M5 BWR Feedwater Nozzle............................................................................. XI M-22

XI.M6 BWR Control Rod Drive Return Line Nozzle............................................. XI M-24

XI.M7 BWR Stress Corrosion Cracking................................................................ XI M-26

XI.M8 BWR Penetrations...................................................................................... XI M-30

XI.M9 BWR Vessel Internals ................................................................................ XI M-34

XI.M10 Boric Acid Corrosion................................................................................... XI M-41

XI.M11 Nickel-Alloy Nozzles and Penetrations ..................................................... XI M-44

XI.M11A Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor 

Vessel Closure Heads of Pressurized Water Reactors...........................XI M-45

XI.M12 Thermal Aging Embrittlement of Cast Austenitic

Stainless Steel (CASS) .......................................................................... XI M-49

XI.M13 Thermal Aging and Neutron Irradiation Embrittlement 

of Cast Austenitic Stainless Steel (CASS)............................................. XI M-52

XI.M14 Loose Part Monitoring................................................................................ XI M-55

XI.M15 Neutron Noise Monitoring........................................................................... XI M-57

XI.M16 PWR Vessel Internals ................................................................................ XI M-60

XI.M17 Flow-Accelerated Corrosion....................................................................... XI M-61

XI.M18 Bolting Integrity........................................................................................... XI M-64

XI.M19 Steam Generator Tube Integrity................................................................. XI M-68

XI.M20 Open-Cycle Cooling Water System........................................................... XI M-72

XI.M21 Closed-Cycle Cooling Water System......................................................... XI M-75

XI.M22 Boraflex Monitoring..................................................................................... XI M-78

XI.M23 Inspection of Overhead Heavy Load and Light Load 

 (Related to Refueling) Handling Systems............................................. XI M-81

XI.M24 Compressed Air Monitoring........................................................................ XI M-83

XI.M25 BWR Reactor Water Cleanup System....................................................... XI M-86

XI.M26 Fire Protection ............................................................................................ XI M-89

XI.M27 Fire Water System...................................................................................... XI M-92

XI.M28 Buried Piping and Tanks Surveillance....................................................... XI M-95

XI.M29 Aboveground Steel Tanks.......................................................................... XI M-97

XI.M30 Fuel Oil Chemistry...................................................................................... XI M-99

XI.M31 Reactor Vessel Surveillance......................................................................XI M-102

XI.M32 One-Time Inspection..................................................................................XI M-105

XI.M33 Selective Leaching of Materials .................................................................XI M-109

XI.M34 Buried Piping and Tanks Inspection ..........................................................XI M-111

XI.M35 One-time Inspection of ASME Code Class 1 Small Bore-Piping ..............XI M-113

XI.M36 External Surfaces Monitoring ....................................................................XI M-115

XI.M37 Flux Thimble Tube Inspection ...................................................................XI M-118

XI.M38 Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components....................................XI M-121

XI.M39 Lubricating Oil Analysis..............................................................................XI M-123

XI.S1 ASME Section XI, Subsection IWE............................................................ XI S-1

XI.S2 ASME Section XI, Subsection IWL............................................................ XI S-6

XI.S3 ASME Section XI, Subsection IWF............................................................ XI S-10

XI.S4 10 CFR 50, Appendix J .............................................................................. XI S-14

XI.S5 Masonry Wall Program............................................................................... XI S-17

XI.S6 Structures Monitoring Program .................................................................. XI S-19 
September 2005 ix NUREG-1801, Rev. 1

XI. Aging Management Programs (AMPs) (continued)

XI.S7 RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants ............................................................................. XI S-22

XI.S8 Protective Coating Monitoring and Maintenance Program ......................... XI S-25

XI.E1 Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements ............................................. XI E-1

XI.E2 Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Used in 

Instrumentation Circuits ........................................................................... XI E-4

XI.E3 Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements ............................................. XI E-7

XI.E4 Metal Enclosed Bus...................................................................................... XI E-10

XI.E5 Fuse Holders ................................................................................................ XI E-13

XI.E6 Electrical Cable Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements ............................................. XI E-15

Appendix: Quality Assurance for Aging Management Programs.............................. A-i
NUREG-1801, Rev. 1 x September 2005

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September 2005 xi NUREG-1801, Rev. 1

LIST OF CONTRIBUTORS 

License Renewal and Environmental Programs Section of Division of Regulatory Improvement 

Programs, Office of Nuclear Reactor Regulation

P.T. Kuo Program Director

S. Lee Section Chief

S. West Section Chief

J. Zimmerman Section Chief

J. Dozier Team Leader

K. Chang Mechanical Engineering

K. Cozens Materials Engineering 

G. Cranston Reactor Systems Engineering

D. Guha Systems Engineering

M. Heath Mechanical Engineering

S. Hoffman Mechanical Engineering

A. Hull Materials Engineering

K. Hsu Materials Engineering

M. Lintz Mechanical Engineering

D. Merzke Mechanical Engineering

K. Naidu Reactor Engineering

J. Rajan Mechanical Engineering

R. Subbaratnam Mechanical Engineering

T. Terry Civil Engineering

L. Tran Electrical Engineering

P. Wen Electrical Engineering

Office of Nuclear Reactor Regulation

T. Chan Section Chief

S. Coffin Section Chief

S. Jones Section Chief

R. Jenkins Section Chief

L. Lund Section Chief

R. Karas Section Chief

K. Manoly Section Chief

M. Mitchell Section Chief

J. Nakoski Section Chief

D. Terao Section Chief

S. Weerakkody Section Chief

H. Ashar Structural Engineering

S. Bailey Mechanical Engineering

T. Cheng Structural Engineering

R. Davis Materials Engineering

B. Elliot Materials Engineering

J. Fair Mechanical Engineering

G. Georgiev Materials Engineering
NUREG-1801, Rev. 1 xii September 2005

LIST OF CONTRIBUTORS (continued)

A. Keim Materials Engineering

N. Iqbal Fire Protection Engineering

D. Jeng Structural Engineering

K. Karwoski Materials Engineering

C. Lauron Chemical Engineering

L. Lois Reactor Systems Engineering

Y. Li Mechanical Engineering

R. McNally Mechanical Engineering

J. Medoff Materials Engineering

D. Nguyen Electrical Engineering

A. Pal Electrical Engineering

K. Parczewski Chemical Engineering

J. Strnisha Mechanical Engineering

P. Shemanski Electrical Engineering

Office of Nuclear Regulatory Research

A. Hiser Section Chief

J. Vora Team Leader

J. Davis Materials Engineering

P. Kang Electrical Engineering

Parallax, Inc

A. Baione Team Leader

M. Bowman Mechanical Engineering

D. Jones Programming

K. Larsen Technical Editing

E. Patel Mechanical Engineering

F. Stetson Mechanical Engineering

C. Urland Mechanical Engineering

R. Wells License Engineering

G. Worku Mechanical Engineering

T. Kennedy Materials Engineering

Argonne National Laboratory

O. Chopra Team Leader

Y. Liu Team Leader

D. Diercks Materials Engineering

R. Fabian Quality Assurance

R. Foote Clerical Support

Z. Li Nuclear Engineering

D. Ma Mechanical Engineering

V. Shah Mechanical and Materials Engineering
September 2005 xiii NUREG-1801, Rev. 1

LIST OF CONTRIBUTORS (continued)

B. Shelton Reactor and Plant Systems Engineering

S. Tam Materials Engineering

Information Systems Laboratories

B. Gitnick Team Leader

B. Mrowca Systems Engineering

O. Mazzoni Electrical Engineering

M. Patterson Systems Engineering

R. Pond Materials Engineering

S. Traiforos Structural Engineering

C. Amoruso Technical Editing
NUREG-1801, Rev. 1 xiv September 2005

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September 2005 xv NUREG-1801, Rev. 1

ABBREVIATIONS

ACI American Concrete Institute

ADS automatic depressurization system

AFW auxiliary feedwater

ALARA as low as reasonably achievable

AMP aging management program

AMR aging management review

ANSI American National Standards Institute

ASCE American Society of Civil Engineers

ASME American Society of Mechanical Engineers

ASTM American Society for Testing and Materials

B&PV boiler and pressure vessel

B&W Babcock & Wilcox

BWR boiling water reactor

BWRVIP Boiling Water Reactor Vessel and Internals Project

CASS cast austenitic stainless steel

CB core barrel

CCCW closed-cycle cooling water

CE Combustion Engineering

CEA control element assembly

CEDM control element drive mechanism

CFR Code of Federal Regulations

CFS core flood system 

CLB current licensing basis

CRD control rod drive

CRDM control rod drive mechanism

CRDRL control rod drive return line

CRGT control rod guide tube

CVCS chemical and volume control system

DC direct current

DHR decay heat removal

DSCSS drywell and suppression chamber spray system

ECP electrochemical potential

EDG emergency diesel generator

EFPD effective full power day

EPRI Electric Power Research Institute

EQ environmental qualification

FAC flow-accelerated corrosion

FERC Federal Energy Regulatory Commission

FSAR Final Safety Analysis Report

FW feedwater

GALL Generic Aging Lessons Learned

GE General Electric

GL generic letter
NUREG-1801, Rev. 1 xvi September 2005

ABBREVIATIONS (continued)

HELBs high-energy line breaks

HP high pressure

HPCI high-pressure coolant injection

HPCS high-pressure core spray

HPSI high-pressure safety injection

HVAC heating, ventilation, and air conditioning

I&C instrumentation and control

IASCC irradiation assisted stress corrosion cracking

IC isolation condenser

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

IRM intermediate range monitor

ISI inservice inspection

ITG Issues Task Group

LER licensee event report

LG lower grid

LOCA loss of coolant accident

LP low pressure

LPCI low-pressure coolant injection

LPCS low-pressure core spray

LPM loose part monitoring 

LPRM low-power range monitor

LPSI low-pressure safety injection

LRT leak rate test

LWR light water reactor

MFW main feedwater

MIC microbiologically influenced corrosion

MS main steam

MSR moisture separator/reheater

MT magnetic particle testing

NDE nondestructive examination

NEI Nuclear Energy Institute

NFPA National Fire Protection Association

NPAR nuclear plant aging research

NPS nominal pipe size

NRC Nuclear Regulatory Commission

NRMS normalized root mean square
September 2005 xvii NUREG-1801, Rev. 1

ABBREVIATIONS (continued)

NSAC Nuclear Safety Analysis Center

NSSS nuclear steam supply system

NUMARC Nuclear Management and Resources Council

OCCW open-cycle cooling water

OD outside diameter

ODSCC outside diameter stress corrosion cracking

OM operation and maintenance

PT penetrant testing

PWR pressurized water reactor

PWSCC primary water stress corrosion cracking

QA quality assurance

RCCA rod control cluster assemblies

RCIC reactor core isolation cooling

RCP reactor coolant pump

RCPB reactor coolant pressure boundary

RCS reactor coolant system

RG Regulatory Guide

RHR residual heat removal

RICSIL rapid information communication services information letter

RMS root mean square

RWC reactor water cleanup

RWST refueling water storage tank

RWT refueling water tank

SAW submerged arc weld

SC suppression chamber

SCC stress corrosion cracking

SDC shutdown cooling

SFP spent fuel pool

SG steam generator

S/G standards and guides

SIL services information letter

SIT safety injection tank

SLC standby liquid control

SOER significant operating experience report

SRM source range monitor

SRM staff requirements memorandum

SRP-LR standard review plan for license renewal

SS stainless steel

SSC systems, structures, and components

TGSCC transgranular stress corrosion cracking

TLAA time-limited aging analysis
NUREG-1801, Rev. 1 xviii September 2005

ABBREVIATIONS (continued)

UCS Union of Concerned Scientists

UHS ultimate heat sink

USI unresolved safety issue

UT ultrasonic testing

UV ultraviolet
September 2005 1 NUREG-1801, Rev. 1

INTRODUCTION

The GALL Report, Volume 2 contains 11 chapters and an appendix. The majority of the 

chapters contain summary descriptions and tabulations of evaluations of aging management 

programs for a large number of structures and components in the various major plant systems 

in the light-water reactor nuclear power plants. The major plant systems include the containment 

structures (Chapter II), structures and component supports (Chapter III), reactor vessel, 

internals and reactor coolant system (Chapter IV), engineered safety features (Chapter V), 

electrical components (Chapter VI), auxiliary systems (Chapter VII), and steam and power 

conversion system (Chapter VIII). 

Also in Volume 2 of the GALL report, Chapter I addresses the application of the ASME Code for 

license renewal. Chapter IX contains definitions of a selection of standard terms used within the 

GALL report. Chapter X contains the time-limited aging analysis evaluation of aging 

management programs under 10 CFR 54.21(c)(1)(iii). Chapter XI contains the aging 

management programs for the structures and mechanical and electrical components. 

The Appendix of Volume 2 of the GALL report addresses quality assurance (QA) for aging 

management programs.

The evaluation process for the aging management programs and the application of the GALL 

report is described in the Summary, Volume 1, of the GALL report. 

Table Column Headings

The following describes the information presented in each column of tables 1 through 6 

contained in Volume 2 of this report.

Column 

Heading Description

Item Two items are listed in each row for this column. The first item is a unique row 

identifier which is coded to indicate the chapter, AMR subsystem and row 

number (i.e., VIII.B1-1 is the first row in the steam and power conversion 

system, main steam system table, row 1). The second identifier (shown in 

parentheses) is a unique chapter-specific identifier used in the AMR 

subsystem rows within a chapter, and is the related item used in tables 1 

through 6 of GALL Volume 1.

Tables 1A through 6A in GALL Volume 1 show the relationship between these

unique row identifiers and these unique chapter-specific identifiers.

Link For each row in the subsystem tables, this item identifies the corresponding 

row identifier from GALL Volume 2 revision 0, if the row was derived from the 

earlier version of this report. Otherwise, the item indicates a new row and to 

which AMR subsystem tables within the chapter it was added in this revision 

of the GALL Report.

Structure and 

or Component

Identifies the structure or components to which the row applies.

Material Identifies the material of construction. See Chapter IX of this report for further 

information.

Environment Identifies the environment applicable to this row. See Chapter IX of this report 

for further information.
NUREG-1801, Rev. 1 2 September 2005

Aging Effect/ 

Mechanism

Identifies the applicable aging effect and mechanism(s). See Chapter IX of 

Volume 2 for more information.

Aging 

Management 

Programs

Identifies the time limited aging analysis or aging management program found 

acceptable for properly managing the affects of aging. See Chapter X and XI 

of Volume 2.

Further 

Evaluation 

Recommended

Identifies whether further evaluation is needed.
September 2005 I-i NUREG-1801, Rev. 1

CHAPTER I

APPLICATION OF THE ASME CODE 
NUREG-1801, Rev. 1 I-ii September 2005

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September 2005 I-1 NUREG-1801, Rev. 1

APPLICATION OF THE ASME CODE

The American Society of Mechanical Engineers (ASME) codes were developed and are revised 

periodically by industry code committees composed of representatives of utilities, reactor 

designers, architect-engineers, component manufacturers, insurance companies, the 

U.S. Nuclear Regulatory Commission (NRC), and others. In 1971, NRC incorporated the ASME 

Boiler and Pressure Vessel Code into the regulations in 10 CFR 50.55a. [36 FR 11,423 (June 

12, 1971)]. 

The Statements of Consideration (SOC) for the final rule state:

“It has been generally recognized that, for boiling and pressurized water-cooled 

reactors, pressure vessels, piping, pumps, and valves which are part of the 

reactor coolant pressure boundary should, as a minimum, be designed, 

fabricated, inspected, and tested in accordance with the requirements of the 

applicable American Society of Mechanical Engineers (ASME) codes in effect at 

the time the equipment is purchased[.]”

The SOC also states:

“Because of the safety significance of uniform early compliance by the nuclear 

industry with the requirements of these ASME . . . codes and published code 

revisions, the Commission has adopted the following amendments to Part 50 and 

115, which require that certain components and systems of water-cooled 

reactors important to safety comply with these codes and appropriate revisions to 

the codes at the earliest feasible time.”

In addition, the SOC states:

“Compliance with the provisions of the amendments and the referenced codes is 

intended to insure a basic, sound quality level.”

The ASME code, based on the collective engineering judgment of the code committees, 

documents the conditions that must be monitored, the inspection techniques adequate to 

observe those conditions, the frequency of the inspections, and the acceptance criteria that the 

results of the inspections must meet in order to assure the integrity of the structures and 

components considered in the code. The NRC has adopted this engineering judgment with 

respect to selected portions of the ASME code, as incorporated in 10 CFR 50.55a.

The NRC has amended 10 CFR 50.55a periodically to incorporate later editions of the ASME 

code into the regulations, with modifications and limitations, as appropriate. The latest such 

amendment was in 2001 (including the 2002 and 2003 Addenda). For the purpose of license 

renewal, the staff has extensively evaluated the appropriate ASME Section XI programs based 

on the ten program elements described in Volume 1 of this report. Except where noted, the staff 

has determined that the ASME Section XI programs provide processes for identifying 

degradation that is attributable to applicable aging effects and are therefore acceptable for 

managing the effects of aging during the period of extended operation. Where warranted, the 

NRC staff indicates that certain parts of the code programs should be augmented to satisfy 

aging management requirements for license renewal. 
NUREG-1801, Rev. 1 I-2 September 2005

10 CFR 50.55a is revised periodically to adopt, by reference, new editions, and addenda of the 

ASME Code. Every 10 years applicants are required to revise the nuclear plant’s ISI program to 

incorporate the requirements specified in the current version of the 10 CFR 50.55a regulations. 

NRC SOC associated with the adoption of new editions and addenda of the ASME Code in 10 

CFR 50.55a discusses the adequacy of the newer edition and addendum as they relate to the 

GALL Report. The information contained in these SOCs may provide a reasonable basis for 

exceptions relating to use of editions or addenda of the ASME Code that are not the same as 

identified in the GALL Report.

The NRC Director of the Office of Nuclear Reactor Regulation may approve licensee proposed

alternatives to the ASME Code in accordance with the provisions of 10 CFR 50.55a(a)(3). 

These NRC approved ASME Code alternative requirements may have an associated 

applicability time limit. The applicability time limits associated with the approved alternatives do 

not extend beyond the current license term. If an applicant seeks relief from specific

requirements of 10 CFR 50.55a and Section XI of the ASME Code for the period of extended 

operation, the applicant will need to re-apply for relief through the 10 CFR 50.55a relief request 

process once the operating license for the facility has been renewed.
September 2005 II-i NUREG-1801, Rev. 1

CHAPTER II

CONTAINMENT STRUCTURES
NUREG-1801, Rev. 1 II-ii September 2005

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September 2005 II-iii NUREG-1801, Rev. 1

CONTAINMENT STRUCTURES

A. Pressurized Water Reactor (PWR) Containments

B. Boiling Water Reactor (BWR) Containments
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September 2005 II A-1 NUREG-1801, Rev. 1

PWR CONTAINMENTS

A1. Concrete Containments (Reinforced and Prestressed)

A2. Steel Containments

A3. Common Components
NUREG-1801, Rev. 1 II A-2 September 2005

This Page Intentionally Left Blank
September 2005 II A1-1 NUREG-1801, Rev. 1

A1. CONCRETE CONTAINMENTS (REINFORCED AND PRESTRESSED)

Systems, Structures, and Components

This section addresses the elements of pressurized water reactor (PWR) concrete containment 

structures. Concrete containment structures are divided into three elements: concrete, steel, 

and prestressing system.

System Interfaces

Functional interfaces include the primary containment heating and ventilation system (VII.F3), 

containment isolation system (V.C), and containment spray system (V.A). Physical interfaces 

exist with any structure, system, or component that either penetrates the containment wall, such 

as the main steam system (VIII.B1) and feedwater system (VIII.D1), or is supported by the 

containment structure, such as the polar crane (VII.B). The containment structure basemat 

typically provides support to the nuclear steam supply system (NSSS) components and 

containment internal structures.
NUREG-1801, Rev. 1 II A1-2 September 2005

II CONTAINMENT STRUCTURES

A1 Concrete Containments (Reinforced and Prestressed)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.A1-1

(C-08)

II.A1.1-h Concrete:

Dome; wall; 

basemat; ring 

girder; 

buttresses

Concrete Air – indoor 

uncontrolled or 

air – outdoor

Reduction of 

strength and 

modulus/ elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging management 

program

The implementation of 10 CFR 50.55a 

and ASME Section XI, Subsection IWL 

would not be able to identify the 

reduction of strength and modulus of 

elasticity due to elevated temperature. 

Thus, for any portions of concrete 

containment that exceed specified 

temperature limits, further evaluations 

are warranted. Subsection CC-3400 of 

ASME Section III, Division 2, specifies 

the concrete temperature limits for 

normal operation or any other long-term 

period. The temperatures shall not 

exceed 150°F except for local areas, 

such as around penetrations, which are 

not allowed to exceed 200°F. If 

significant equipment loads are 

supported by concrete at temperatures 

exceeding 150°F, an evaluation of the 

ability to withstand the postulated design 

loads is to be made.

Higher temperatures than given above 

may be allowed in the concrete if tests 

and/or calculations are provided to 

evaluate the reduction in strength and 

this reduction is applied to the design 

allowables.

Yes, if 

temperature 

limits are 

exceeded
September 2005 II A1-3 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

A1 Concrete Containments (Reinforced and Prestressed)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.A1-2

(C-01)

II.A1.1-a Concrete:

Dome; wall; 

basemat; ring 

girders; 

buttresses

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking/ 

freeze-thaw

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

loss of material (spalling, scaling) and 

surface cracking due to freeze-thaw.

Inaccessible Areas:

Evaluation is needed for plants that are 

located in moderate to severe 

weathering conditions (weathering index 

>100 day-inch/yr) (NUREG-1557). 

Documented evidence confirms that 

where the existing concrete had air 

content of 3% to 6%, subsequent 

inspection did not exhibit degradation 

related to freeze-thaw. Such inspections 

should be considered a part of the 

evaluation.

The weathering index for the continental 

US is shown in ASTM C33-90, Fig. 1.

Yes, for 

inaccessible 

areas of plants 

located in 

moderate to 

severe 

weathering 

conditions
NUREG-1801, Rev. 1 II A1-4 September 2005

II CONTAINMENT STRUCTURES

A1 Concrete Containments (Reinforced and Prestressed)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.A1-3

(C-04)

II.A1.1-d Concrete:

Dome; wall; 

basemat; ring 

girders; 

buttresses

Concrete Any Cracking due to 

expansion/ 

reaction with 

aggregates

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible Areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

surface cracking due to reaction with 

aggregates.

Inaccessible Areas:

As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates performed in 

accordance with ASTM C295-54 or 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregatereinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with ACI 

201.2R.Therefore, if these conditions are 

satisfied, aging management is not 

necessary.

Yes, if 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas
September 2005 II A1-5 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

A1 Concrete Containments (Reinforced and Prestressed)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.A1-4

(C-03)

II.A1.1-c Concrete:

Dome; wall; 

basemat; ring 

girders; 

buttresses

Concrete Ground 

water/soil or airindoor 

uncontrolled or 

air-outdoor

Increase in 

porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling)/ 

aggressive 

chemical attack

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”.

Accessible Areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

increase in porosity and permeability, 

surface cracking, or loss of material 

(spalling, scaling) due to aggressive 

chemical attack.

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 500 

ppm, or sulfates <1500 ppm, as a 

minimum, consider (1) Examination of 

the exposed portions of the below grade 

concrete, when excavated for any 

reason, and

(2) Periodic monitoring of below-grade 

water chemistry, including consideration 

of potential seasonal variations.

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant specific 

AMP accounting for the extent of the 

degradation experienced should be 

implemented to manage the concrete 

aging during the period of extended 

operation.

Yes, plantspecific if 

environment is 

aggressive
NUREG-1801, Rev. 1 II A1-6 September 2005

II CONTAINMENT STRUCTURES

A1 Concrete Containments (Reinforced and Prestressed)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.A1-5

(C-37)

II.A1.1-f Concrete:

Dome; wall; 

basemat; ring 

girders; 

buttresses

Concrete Soil Cracks and 

distortion due to 

increased stress 

levels from 

settlement

Chapter XI.S6, “Structures Monitoring 

Program”

If a de-watering system is relied upon for 

control of settlement, then the licensee is 

to ensure proper functioning of the dewatering system through the period of 

extended operation. 

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering

system is 

relied upon

II.A1-6

(C-02)

II.A1.1-b Concrete:

Dome; wall; 

basemat; ring 

girders; 

buttresses

Concrete Water – flowing Increase in 

porosity, 

permeability/ 

leaching of calcium 

hydroxide

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

increase in porosity, and permeability 

due to leaching of calcium hydroxide.

Inaccessible Areas:

An aging management program is not 

necessary, even if reinforced concrete is 

exposed to flowing water, if there is 

documented evidence that confirms the 

in-place concrete was constructed in 

accordance with the recommendations in 

ACI 201.2R-77.

Yes, if 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas
September 2005 II A1-7 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

A1 Concrete Containments (Reinforced and Prestressed)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.A1-7

(C-05)

II.A1.1-e Concrete:

Dome; wall; 

basemat; ring 

girders; 

buttresses; 

reinforcing 

steel

Concrete; 

steel

Air – indoor 

uncontrolled or 

air – outdoor

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling)/ corrosion 

of embedded steel

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”.

Accessible Areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

surface cracking, loss of bond, and loss 

of material (spalling, scaling) due to 

corrosion of embedded steel.

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 500 

ppm, or sulfates <1500 ppm, as a 

minimum, consider (1) Examination of 

the exposed portions of the below grade 

concrete, when excavated for any 

reason, and

(2) Periodic monitoring of below-grade 

water chemistry, including consideration 

of potential seasonal variations.

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant specific 

AMP accounting for the extent of the 

degradation experienced should be 

implemented to manage the concrete 

aging during the period of extended 

operation.

Yes, plantspecific if 

environment is 

aggressive
NUREG-1801, Rev. 1 II A1-8 September 2005

II CONTAINMENT STRUCTURES

A1 Concrete Containments (Reinforced and Prestressed)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.A1-8

(C-07)

II.A1.1-g Concrete:

Foundation; 

subfoundatio

n

Concrete; 

porous 

concrete

Water – flowing Reduction in 

foundation 

strength, cracking, 

differential 

settlement/ erosion 

of porous concrete 

subfoundation

Chapter XI.S6, “Structures Monitoring 

Program”

Erosion of cement from porous concrete 

subfoundations beneath containment 

basemats is described in IN 97-11. IN 

98-26 proposes Maintenance Rule 

Structures Monitoring for managing this 

aging effect, if applicable. If a dewatering system is relied upon for control 

of erosion of cement from porous 

concrete subfoundations, then the 

licensee is to ensure proper functioning 

of the de-watering system through the 

period of extended operation.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon

II.A1-9

(C-11)

II.A1.3-b Prestressing 

system:

Tendons

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of prestress/ 

relaxation; 

shrinkage; creep; 

elevated 

temperature

Loss of tendon prestress is a time-limited 

aging analysis (TLAA) to be evaluated 

for the period of extended operation.

See the Standard Review Plan, Section 

4.5, “Concrete Containment Tendon 

Prestress” for acceptable methods for 

meeting the requirements of 

10 CFR 54.21(c)(1)(i) and (ii). See 

Chapter X.S1 of this report for meeting 

the requirements of 

10 CFR 54.21(c)(1)(iii).

For periodic monitoring of prestress, see 

Chapter XI.S2.

Yes,

TLAA
September 2005 II A1-9 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

A1 Concrete Containments (Reinforced and Prestressed)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.A1-10

(C-10)

II.A1.3-a Prestressing 

system:

Tendons; 

anchorage 

components

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of material/ 

corrosion

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

No

II.A1-11

(C-09)

II.A1.2-a Steel 

elements:

Liner;

Liner 

anchors;

Integral 

attachments

Steel Air – indoor 

uncontrolled

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, “ASME Section XI, 

Subsection IWE”

For inaccessible areas (embedded 

containment steel shell or liner), loss of 

material due to corrosion is not 

significant if the following conditions are 

satisfied:

1. Concrete meeting the requirements of 

ACI 318 or 349 and the guidance of

201.2R was used for the containment 

concrete in contact with the embedded 

containment shell or liner. 

2. The concrete is monitored to ensure 

that it is free of penetrating cracks that 

provide a path for water seepage to the 

surface of the containment shell or liner. 

3. The moisture barrier, at the junction 

where the shell or liner becomes 

embedded, is subject to aging 

management activities in accordance 

with ASME Section XI, Subsection IWE 

requirements. 

4. Borated water spills and water 

ponding on the containment concrete 

floor are not common and when detected 

Yes, if 

corrosion is 

significant for 

inaccessible 

areas
NUREG-1801, Rev. 1 II A1-10 September 2005

II CONTAINMENT STRUCTURES

A1 Concrete Containments (Reinforced and Prestressed)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

are cleaned up in a timely manner.

If any of the above conditions cannot be 

satisfied, then a plant-specific aging 

management program for corrosion is 

necessary.

Chapter XI.S4, “10 CFR Part 50, 

Appendix J” 

No
September 2005 II A2-1 NUREG-1801, Rev. 1

A2. STEEL CONTAINMENTS

Systems, Structures, and Components

This section addresses the elements of pressurized water reactor (PWR) steel containment 

structures. Steel containment structures are divided into two elements: steel and concrete. 

System Interfaces

Functional interfaces include the primary containment heating and ventilation system (VII.F3), 

containment isolation system (V.C), and containment spray system (V.A). Physical interfaces 

exist with any structure, system, or component that either penetrates the containment wall, such 

as the main steam system (VIII.B1) and feedwater system (VIII.D1), or is supported by the 

containment structure, such as the polar crane (VII.B). The containment structure basemat 

typically provides support to the nuclear steam supply system (NSSS) components and 

containment internal structures.
NUREG-1801, Rev. 1 II A2-2 September 2005

II CONTAINMENT STRUCTURES

A2 Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.A2-1

(C-34)

II.A2.2-h Concrete:

Basemat

Concrete Air – indoor 

uncontrolled or 

air – outdoor

Reduction of 

strength and 

modulus/ 

elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging management 

program

The implementation of 10 CFR 50.55a 

and ASME Section XI, Subsection 

IWL would not be able to identify the 

reduction of strength and modulus due 

to elevated temperature. Thus, for any 

portions of concrete containment that 

exceed specified temperature limits, 

further evaluations are warranted. 

Subsection CC-3400 of ASME 

Section III, Division 2, specifies the 

concrete temperature limits for normal 

operation or any other long-term 

period. The temperatures shall not 

exceed 150°F except for local areas, 

such as around penetrations, which 

are not allowed to exceed 200°F. If 

significant equipment loads are 

supported by concrete at 

temperatures exceeding 150°F, an 

evaluation of the ability to withstand 

the postulated design loads is to be 

made.

Higher temperatures than given above 

may be allowed in the concrete if tests 

and/or calculations are provided to 

evaluate the reduction in strength and 

this reduction is applied to the design 

allowables.

Yes, if 

temperature 

limits are 

exceeded
September 2005 II A2-3 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

A2 Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.A2-2

(C-28)

II.A2.2-a Concrete:

Basemat

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking/ 

freeze-thaw

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

loss of material (spalling, scaling) and 

surface cracking due to freeze-thaw.

Inaccessible Areas:

Evaluation is needed for plants that 

are located in moderate to severe 

weathering conditions (weathering 

index >100 day-inch/yr) (NUREG1557). Documented evidence 

confirms that where the existing 

concrete had air content of 3% to 6%, 

subsequent inspection did not exhibit 

degradation related to freeze-thaw. 

Such inspections should be 

considered a part of the evaluation.

The weathering index for the 

continental US is shown in ASTM 

C33-90, Fig. 1.

Yes, for 

inaccessible 

areas of 

plants located 

in moderate to 

severe 

weathering 

conditions
NUREG-1801, Rev. 1 II A2-4 September 2005

II CONTAINMENT STRUCTURES

A2 Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.A2-3

(C-38)

II.A2.2-d Concrete:

Basemat

Concrete Any Cracking due to 

expansion/ 

reaction with 

aggregates

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”.

Accessible Areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

surface cracking due to reaction with 

aggregates.

Inaccessible Areas:

As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates 

performed in accordance with ASTM 

C295-54 or ASTM C227-50 can 

demonstrate that those aggregates do 

not react within reinforced concrete. 

For potentially reactive aggregates, 

aggregate-reinforced concrete 

reaction is not significant if the 

concrete was constructed in 

accordance with ACI 

201.2R.Therefore, if these conditions 

are satisfied, aging management is 

not necessary.

Yes, if 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas
September 2005 II A2-5 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

A2 Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.A2-4

(C-25)

II.A2.2-c Concrete:

Basemat

Concrete Ground 

water/soil

Increase in 

porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling)/ 

aggressive 

chemical attack

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”.

Accessible Areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

increase in porosity and permeability, 

surface cracking, or loss of material 

(spalling, scaling) due to aggressive 

chemical attack.

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 

500 ppm, or sulfates <1500 ppm, as a 

minimum, consider (1) Examination of 

the exposed portions of the below 

grade concrete, when excavated for 

any reason, and

(2) Periodic monitoring of below-grade 

water chemistry, including 

consideration of potential seasonal 

variations.

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the 

concrete aging during the period of 

extended operation.

Yes, plantspecific if 

environment is 

aggressive
NUREG-1801, Rev. 1 II A2-6 September 2005

II CONTAINMENT STRUCTURES

A2 Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.A2-5

(C-36)

II.A2.2-f Concrete:

Basemat

Concrete Soil Cracks and 

distortion due to 

increased stress 

levels from 

settlement

Chapter XI.S6, “Structures Monitoring 

Program”

If a de-watering system is relied upon 

for control of settlement, then the 

licensee is to ensure proper 

functioning of the de-watering system 

through the period of extended 

operation. 

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon

II.A2-6

(C-30)

II.A2.2-b Concrete:

Basemat

Concrete Water – flowing Increase in 

porosity, 

permeability/ 

leaching of 

calcium 

hydroxide

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

increase in porosity, and permeability 

due to leaching of calcium hydroxide.

Inaccessible Areas:

 An aging management program is not 

necessary, even if reinforced concrete 

is exposed to flowing water, if there is 

documented evidence that confirms 

the in-place concrete was constructed 

in accordance with the 

recommendations in ACI 201.2R.

Yes, if 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas
September 2005 II A2-7 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

A2 Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.A2-7

(C-43)

II.A2.2-e Concrete:

Basemat; 

reinforcing 

steel

Concrete; 

steel

Air – indoor 

uncontrolled or 

air – outdoor

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling)/ 

corrosion of 

embedded steel

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”.

Accessible Areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

surface cracking, loss of bond, and 

loss of material (spalling, scaling) due 

to corrosion of embedded steel.

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 

500 ppm, or sulfates <1500 ppm, as a 

minimum, consider (1) Examination of 

the exposed portions of the below 

grade concrete, when excavated for 

any reason, and

(2) Periodic monitoring of below-grade 

water chemistry, including 

consideration of potential seasonal 

variations.

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the 

concrete aging during the period of 

extended operation.

Yes, plantspecific if 

environment is 

aggressive
NUREG-1801, Rev. 1 II A2-8 September 2005

II CONTAINMENT STRUCTURES

A2 Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.A2-8

(C-07)

II.A2.2-g Concrete:

Foundation; 

subfoundatio

n

Concrete; 

porous 

concrete

Water – flowing Reduction in 

foundation 

strength, 

cracking, 

differential 

settlement/ 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Monitoring 

Program”

Erosion of cement from porous 

concrete subfoundations beneath 

containment basemats is described in 

IN 97-11. IN 98-26 proposes 

Maintenance Rule Structures 

Monitoring for managing this aging 

effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous 

concrete subfoundations, then the 

licensee is to ensure proper 

functioning of the de-watering system 

through the period of extended 

operation.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon

II.A2-9

(C-09)

II.A2.1-a Steel 

elements:

Liner;

Liner 

anchors;

Integral 

attachments

Steel Air – indoor 

uncontrolled

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, “ASME Section XI, 

Subsection IWE”

For inaccessible areas (embedded 

containment steel shell or liner), loss 

of material due to corrosion is not 

significant if the following conditions 

are satisfied:

1. Concrete meeting the requirements 

of ACI 318 or 349 and the guidance of 

201.2R was used for the containment 

concrete in contact with the 

embedded containment shell or liner. 

2. The concrete is monitored to 

ensure that it is free of penetrating 

Yes, if 

corrosion is 

significant for 

inaccessible 

areas
September 2005 II A2-9 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

A2 Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

cracks that provide a path for water 

seepage to the surface of the 

containment shell or liner. 

3. The moisture barrier, at the junction 

where the shell or liner becomes 

embedded, is subject to aging 

management activities in accordance 

with ASME Section XI, Subsection 

IWE requirements. 

4. Borated water spills and water 

ponding on the containment concrete 

floor are not common and when 

detected are cleaned up in a timely 

manner.

If any of the above conditions cannot 

be satisfied, then a plant-specific 

aging management program for 

corrosion is necessary.

Chapter XI.S4, “10 CFR Part 50, 

Appendix J” 

No
NUREG-1801, Rev. 1 II A2-10 September 2005

This Page Intentionally Left Blank
September 2005 II A3-1 NUREG-1801, Rev. 1

A3. COMMON COMPONENTS

Systems, Structures, and Components

This section addresses the common components of pressurized water reactor (PWR)

containments. The common components include penetration sleeves and bellows; dissimilar 

metal welds; personnel airlock; equipment hatch; seals, gaskets, and moisture barriers.

System Interfaces

Functional interfaces include the primary containment heating and ventilation system (VII.F3), 

containment isolation system (V.C), and containment spray system (V.A). Physical interfaces 

exist with any structure, system, or component that either penetrates the containment wall, such 

as the main steam system (VIII.B1) and feedwater system (VIII.D1), or is supported by the 

containment structure, such as the polar crane (VII.B). The containment structure basemat 

typically provides support to the nuclear steam supply system (NSSS) components and 

containment internal structures.
NUREG-1801, Rev.1 II A3-2 September 2005

II CONTAINMENT STRUCTURES

A3 Common Components

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.A3-1

(C-12)

II.A3.1-a Penetration 

sleeves

Steel; 

dissimilar 

metal welds

Air – indoor 

uncontrolled

or air – outdoor

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, “ASME Section XI, 

Subsection IWE,”

(Note: IWE examination category E-F, 

surface examination of dissimilar metal 

welds, is recommended)

Chapter XI.S4, “10 CFR Part 50, 

Appendix J” 

No

No 

II.A3-2

(C-15)

II.A3.1-d Penetration 

sleeves;

Penetration 

bellows

Stainless 

steel; 

dissimilar 

metal welds

Air – indoor 

uncontrolled or 

air – outdoor

Cracking/ stress 

corrosion 

cracking

Chapter XI.S1, “ASME Section XI, 

Subsection IWE” and Chapter XI.S4, 

“10 CFR Part 50, Appendix J”

Evaluation of 10 CFR 50.55a/ASME 

Section XI, Subsection IWE is 

augmented as follows:

(4) Detection of Aging Effects:

Transgranular Stress corrosion 

cracking (TGSCC) is a concern for 

dissimilar metal welds. In the case of 

bellows assemblies, SCC may cause 

aging effects particularly if the material 

is not shielded from a corrosive 

environment. ASME Section XI, 

Subsection IWE covers inspection of 

these items under examination 

categories E-B, E-F, and E-P (10 CFR 

Part 50, Appendix J pressure tests). 

10 CFR 50.55a identifies examination 

categories E-B and E-F as optional 

during the current term of operation. 

For the extended period of operation, 

Yes, detection 

of aging 

effects is to 

be evaluated
September 2005 II A3-3 NUREG-1801, Rev.1 

II CONTAINMENT STRUCTURES

A3 Common Components

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

Examination Categories E-B & E-F, 

and additional appropriate 

examinations to detect SCC in bellows 

assemblies and dissimilar metal welds 

are warranted to address this issue.

(10) Operating Experience:

IN 92-20 describes an instance of 

containment bellows cracking, resulting 

in loss of leak tightness.

II.A3-3

(C-14)

II.A3.1-c Penetration 

sleeves;

Penetration 

bellows

Steel; 

stainless 

steel; 

dissimilar 

metal welds

Air – indoor 

uncontrolled or 

air – outdoor

Cracking/ cyclic 

loading

(CLB fatigue 

analysis does 

not exist)

Chapter XI.S1, “ASME Section XI, 

Subsection IWE" and Chapter XI.S4, 

“10 CFR Part 50, Appendix J”

Evaluation of 10 CFR 50.55a/ASME 

Section XI, Subsection IWE is to be 

supplemented to consider the following:

(4) Detection of Aging Effects: VT-3 

visual inspection may not detect fine 

cracks.

Yes, detection 

of aging 

effects is to 

be evaluated

II.A3-4

(C-13)

II.A3.1-b Penetration 

sleeves;

Penetration 

bellows

Steel; 

stainless 

steel; 

dissimilar 

metal welds

Air – indoor 

uncontrolled or 

air – outdoor

Cumulative 

fatigue damage/ 

fatigue

(Only if CLB 

fatigue analysis 

exists)

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.6, 

“Containment Liner Plate and 

Penetration Fatigue Analysis” for 

acceptable methods for meeting the 

requirements of 10 CFR 54.21(c)(1).

Yes,

TLAA
NUREG-1801, Rev.1 II A3-4 September 2005

II CONTAINMENT STRUCTURES

A3 Common Components

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.A3-5

(C-17)

II.A3.2-b Personnel 

airlock, 

equipment 

hatch, CRD 

hatch:

Locks, 

hinges, and 

closure 

mechanisms

Steel Air – indoor 

uncontrolled

or air – outdoor

Loss of leak 

tightness/ 

mechanical 

wear of locks, 

hinges and 

closure 

mechanisms

Chapter XI.S4, “10 CFR Part 50, 

Appendix J” and

Plant Technical Specifications

No

II.A3-6

(C-16)

II.A3.2-a Personnel 

airlock,

equipment 

hatch, CRD 

hatch

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, “ASME Section XI, 

Subsection IWE,”

Chapter XI.S4, “10 CFR Part 50, 

Appendix J”

No

No

II.A3-7

(C-18)

II.A3.3-a Seals, 

gaskets, and 

moisture 

barriers 

(caulking, 

flashing, and 

other 

sealants)

Elastomers, 

rubber and 

other similar 

materials

Air – indoor 

uncontrolled or 

air – outdoor

Loss of sealing; 

Leakage 

through 

containment/ 

deterioration of 

seals, gaskets,

and moisture 

barriers 

(caulking, 

flashing, and 

other sealants)

Chapter XI.S1, “ASME Section XI, 

Subsection IWE”

Leak tightness will be monitored by 

10 CFR Part 50, Appendix J Leak Rate 

Tests for pressure boundary, seals and 

gaskets (including O-rings).

No
September 2005 II B-i NUREG-1801, Rev. 1

BWR CONTAINMENTS

B1. Mark I Containments

B2. Mark II Containments

B3. Mark III Containments

B4. Common Components
NUREG-1801, Rev. 1 II B-ii September 2005

This Page Intentionally Left Blank
September 2005 II B1-1 NUREG-1801, Rev. 1

B1. MARK I CONTAINMENTS

Systems, Structures, and Components

This section addresses the elements of boiling water reactor (BWR) Mark I containment 

structures. Steel containments are discussed in II.B1.1 and concrete containments are 

discussed in II.B1.2. 

System Interfaces

Functional interfaces include the primary containment heating and ventilation system (VII.F3), 

containment isolation system (V.C), and standby gas treatment system (V.B). Physical 

interfaces exist with any structure, system, or component that either penetrates the containment 

wall, such as the main steam system (VIII.B2) and feedwater system (VIII.D2), or is supported 

by the containment structure. The containment structure basemat may provide support to the 

NSSS components and containment internal structures.
NUREG-1801, Rev. 1 II B1-2 September 2005

II CONTAINMENT STRUCTURES

B1.1 Mark I Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B1.1-1

(C-23)

II.B1.1.1-e Steel elements:

Drywell head;

Downcomers

Steel Air – indoor 

uncontrolled

Fretting or 

lockup/ 

mechanical 

wear

Chapter XI.S1, “ASME Section XI, 

Subsection IWE”

No

II.B1.1-2

(C-19)

II.B1.1.1-a Steel elements:

Drywell; torus; 

drywell

head; 

embedded 

shell

and sand 

pocket 

regions;

drywell 

support skirt;

torus ring 

girder;

downcomers; 

ECCS

suction 

header

NOTE: 

Inspection of 

containment 

supports is 

addressed by 

ASME 

Section XI, 

Subsection 

Steel Air – indoor 

uncontrolled or 

treated water

Loss of 

material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, “ASME Section XI, 

Subsection IWE”

For inaccessible areas (embedded 

containment steel shell or liner), loss of 

material due to corrosion is not 

significant if the following conditions 

are satisfied:

Concrete meeting the specifications of 

ACI 318 or 349 and the guidance of 

201.2R was used for the containment 

concrete in contact with the embedded 

containment shell or liner. The concrete 

is monitored to ensure that it is free of 

penetrating cracks that provide a path 

for water seepage to the surface of the 

containment shell or liner. The moisture 

barrier, at the junction where the shell 

or liner becomes embedded, is subject 

to aging management activities in 

accordance with ASME Section XI, 

Subsection IWE requirements. Water 

ponding on the containment concrete 

floor are not common and when 

detected are cleaned up in a timely 

manner.

Yes, if 

corrosion is 

significant for 

inaccessible 

areas
September 2005 II B1-3 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B1.1 Mark I Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IWF (see 

III.B1.3) If any of the above conditions cannot 

be satisfied, then a plant-specific aging 

management program for corrosion is 

necessary.

Chapter XI.S4, “10 CFR Part 50, 

Appendix J” 

No

II.B1.1-3

(C-20)

II.B1.1.1-b Steel elements:

Torus;

Vent line;

Vent header;

Vent line 

bellows;

Downcomers 

Stainless 

steel; steel

Air – indoor 

uncontrolled

Cracking/ cyclic 

loading

(CLB fatigue 

analysis does 

not exist)

Chapter XI.S1, “ASME Section XI, 

Subsection IWE" and Chapter XI.S4, 

“10 CFR Part 50, Appendix J”

Evaluation of 10 CFR 50.55a/ ASME 

Section XI, Subsection IWE is 

augmented as follows:

(4) Detection of Aging Effects: VT-3 

visual inspection may not detect fine 

cracks.

Yes, detection 

of aging 

effects is to be 

evaluated

II.B1.1-4

(C-21)

II.B1.1.1-c Steel elements:

Torus;

Vent line;

Vent header;

Vent line 

bellows;

Downcomers 

Stainless 

steel; steel

Air – indoor 

uncontrolled

Cumulative 

fatigue damage/ 

fatigue

(Only if CLB 

fatigue analysis 

exists)

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period 

of extended operation. See the 

Standard Review Plan, Section 4.6, 

“Containment Liner Plate and 

Penetration Fatigue Analysis” for 

acceptable methods for meeting the 

requirements of 10 CFR 54.21(c)(1).

Yes,

TLAA
NUREG-1801, Rev. 1 II B1-4 September 2005

II CONTAINMENT STRUCTURES

B1.1 Mark I Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B1.1-5

(C-22)

II.B1.1.1-d Steel elements:

Vent line 

bellows

Stainless 

steel

Air – indoor 

uncontrolled

Cracking/ stress 

corrosion 

cracking

Chapter XI.S1, “ASME Section XI, 

Subsection IWE" and Chapter XI.S4, 

“10 CFR Part 50, Appendix J”

Evaluation of 10 CFR 50.55a/ASME 

Section XI, Subsection IWE is 

augmented as follows:

(4) Detection of Aging Effects: Stress 

corrosion cracking (SCC) is a concern 

for dissimilar metal welds. In the case 

of bellows assemblies, SCC may cause 

aging effects particularly if the material 

is not shielded from a corrosive 

environment. ASME Code 1995 

edition, with addenda through 1996, 

ASME Section XI, Subsection IWE 

covers inspection of these items under 

Examination Categories E-B, E-F, and 

E-P (10 CFR Part 50, Appendix J 

pressure tests). 10 CFR 50.55a 

identifies examination categories E-B 

and E-F as optional during the current 

term of operation. For the extended 

period of operation, Examination 

Categories E-B and E-F, and additional 

appropriate examinations to detect 

SCC in bellows assemblies and 

dissimilar metal welds are warranted to 

address this issue.

(10) Operating Experience: IN 92-20 

describes an instance of containment 

bellows cracking, resulting in loss of 

Yes, detection 

of aging 

effects is to be 

evaluated
September 2005 II B1-5 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B1.1 Mark I Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

leak tightness.
NUREG-1801, Rev. 1 II B1-6 September 2005

This Page Intentionally Left Blank
September 2005 II B1-7 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B1.2 Mark I Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B1.2-1

(C-06)

II.B1.2. Concrete 

elements; All

Concrete Soil Cracks and 

distortion due to 

increased stress 

levels from 

settlement

Chapter XI.S6, “Structures Monitoring 

Program”

If a de-watering system is relied upon 

for control of settlement, then the 

licensee is to ensure proper 

functioning of the de-watering system 

through the period of extended 

operation. 

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon
NUREG-1801, Rev. 1 II B1-8 September 2005

II CONTAINMENT STRUCTURES

B1.2 Mark I Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B1.2-2

(C-41)

II.B1.2. Concrete:

Basemat; 

reinforcing 

steel

Concrete; 

steel

Air – indoor 

uncontrolled or 

air – outdoor

Cracking, loss of 

bond, and loss of 

material 

(spalling, 

scaling)/ 

corrosion of 

embedded steel

Chapter XI.S2, “ASME Section XI, 

Subsection IWL.”

Accessible Areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

surface cracking, loss of bond, and 

loss of material (spalling, scaling) due 

to corrosion of embedded steel.

Inaccessible Areas:

For plants with non-aggressive 

ground water/soil; i.e., pH > 5.5, 

chlorides < 500 ppm, or sulfates 

<1500 ppm, as a minimum, consider 

(1) Examination of the exposed 

portions of the below grade concrete, 

when excavated for any reason, and

(2) Periodic monitoring of belowgrade water chemistry, including 

consideration of potential seasonal 

variations.

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the 

extent of the degradation experienced 

should be implemented to manage 

the concrete aging during the period 

of extended operation.

Yes, plantspecific if 

environment is 

aggressive
September 2005 II B1-9 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B1.2 Mark I Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B1.2-3

(C-35)

II.B1.2. Concrete:

Containment; 

wall; basemat

Concrete Air – indoor 

uncontrolled or 

air – outdoor

Reduction of 

strength and 

modulus/ 

elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging management 

program

The implementation of 

10 CFR 50.55a and ASME Section 

XI, Subsection IWL would not be able 

to identify the reduction of strength 

and modulus due to elevated 

temperature. Thus, for any portions of 

concrete containment that exceed 

specified temperature limits, further 

evaluations are warranted. 

Subsection CC-3400 of ASME 

Section III, Division 2, specifies the 

concrete temperature limits for normal 

operation or any other long-term 

period. The temperatures shall not 

exceed 150°F except for local areas, 

such as around penetrations, which 

are not allowed to exceed 200°F. If 

significant equipment loads are 

supported by concrete at 

temperatures exceeding 150°F, an 

evaluation of the ability to withstand 

the postulated design loads is to be 

made.

Higher temperatures than given 

above may be allowed in the concrete 

if tests and/or calculations are 

provided to evaluate the reduction in 

strength and this reduction is applied 

to the design allowables.

Yes, if 

temperature 

limits are 

exceeded
NUREG-1801, Rev. 1 II B1-10 September 2005

II CONTAINMENT STRUCTURES

B1.2 Mark I Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B1.2-4

(C-39)

II.B1.2. Concrete:

Containment; 

wall; basemat

Concrete Any Cracking due to 

expansion/ 

reaction with 

aggregates

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible Areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

surface cracking due to reaction with 

aggregates.

Inaccessible Areas:

As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates 

performed in accordance with ASTM 

C295-54 or ASTM C227-50 can 

demonstrate that those aggregates do 

not react within reinforced concrete. 

For potentially reactive aggregates, 

aggregate-reinforced concrete 

reaction is not significant if the 

concrete was constructed in 

accordance with ACI 201.2R. 

Therefore, if these conditions are 

satisfied, aging management is not 

necessary.

Yes, if 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas
September 2005 II B1-11 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B1.2 Mark I Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B1.2-5

(C-26)

II.B1.2. Concrete:

Containment; 

wall; basemat

Concrete Ground 

water/soil or 

air-indoor 

uncontrolled or 

air-outdoor

Increase in 

porosity and 

permeability, 

cracking, loss of 

material 

(spalling, 

scaling)/ 

aggressive 

chemical attack

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible Areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

increase in porosity and permeability, 

surface cracking, or loss of material 

(spalling, scaling) due to aggressive 

chemical attack.

Inaccessible Areas:

For plants with non-aggressive 

ground water/soil; i.e., pH > 5.5, 

chlorides < 500 ppm, or sulfates 

<1500 ppm, as a minimum, consider 

(1) Examination of the exposed 

portions of the below grade concrete, 

when excavated for any reason, and

(2) Periodic monitoring of belowgrade water chemistry, including 

consideration of potential seasonal 

variations.

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the 

extent of the degradation experienced 

should be implemented to manage 

the concrete aging during the period 

of extended operation.

Yes, plantspecific if 

environment is 

aggressive
NUREG-1801, Rev. 1 II B1-12 September 2005

II CONTAINMENT STRUCTURES

B1.2 Mark I Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B1.2-6

(C-31)

II.B1.2. Concrete:

Containment; 

wall; basemat

Concrete Water – flowing Increase in 

porosity, 

permeability/ 

leaching of 

calcium 

hydroxide

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

increase in porosity, and permeability 

due to leaching of calcium hydroxide.

Inaccessible Areas:

An aging management program is not 

necessary, even if reinforced concrete 

is exposed to flowing water, if there is 

documented evidence that confirms 

the in-place concrete was constructed 

in accordance with the 

recommendations in ACI 201.2R-77.

Yes, if 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas
September 2005 II B1-13 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B1.2 Mark I Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B1.2-7

(C-07)

II.B1.2. Concrete:

Foundation; 

subfoundation

Concrete; 

porous 

concrete

Water – flowing Reduction in 

foundation 

strength, 

cracking, 

differential 

settlement/ 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Monitoring 

Program”

Erosion of cement from porous 

concrete subfoundations beneath 

containment basemats is described in 

IN 97-11. IN 98-26 proposes 

Maintenance Rule Structures 

Monitoring for managing this aging 

effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous 

concrete subfoundations, then the 

licensee is to ensure proper 

functioning of the de-watering system 

through the period of extended 

operation.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon

II.B1.2-8

(C-46)

II.B1.2. Steel elements:

 Suppression 

chamber; 

drywell liner; 

drywell head; 

embedded 

shell; sand 

pocket region; 

support skirt; 

downcomer 

pipes; region 

shielded by 

diaphragm 

floor (as 

applicable)

Steel Air – indoor 

uncontrolled or 

treated water

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, “ASME Section XI, 

Subsection IWE”

For inaccessible areas (embedded 

containment steel shell or liner), loss 

of material due to corrosion is not 

significant if the following conditions 

are satisfied:

Concrete meeting the specifications 

of ACI 318 or 349 and the guidance of 

201.2R was used for the containment 

concrete in contact with the 

embedded containment shell or liner. 

The concrete is monitored to ensure 

that it is free of penetrating cracks 

Yes, if 

corrosion is 

significant for 

inaccessible 

areas
NUREG-1801, Rev. 1 II B1-14 September 2005

II CONTAINMENT STRUCTURES

B1.2 Mark I Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

NOTE: 

Inspection of 

containment 

supports is 

addressed by 

ASME 

Section XI, 

Subsection 

IWF (see 

III.B1.3) 

that provide a path for water seepage 

to the surface of the containment shell 

or liner. The moisture barrier, at the 

junction where the shell or liner 

becomes embedded, is subject to 

aging management activities in 

accordance with ASME Section XI, 

Subsection IWE requirements. Water 

ponding on the containment concrete 

floor are not common and when 

detected are cleaned up in a timely 

manner.

If any of the above conditions cannot 

be satisfied, then a plant-specific 

aging management program for 

corrosion is necessary.

Chapter XI.S4, “10 CFR Part 50, 

Appendix J”

No

II.B1.2-9

(C-23)

II.B1.2. Steel elements:

Drywell head;

Downcomers

Steel Air – indoor 

uncontrolled

Fretting or 

lockup/ 

mechanical wear

Chapter XI.S1, “ASME Section XI, 

Subsection IWE”

No

II.B1.2-10

(C-49)

II.B1.2. Steel elements:

Suppression 

chamber liner 

(interior 

surface)

Stainless 

steel; steel

Air – indoor 

uncontrolled or 

treated water

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, “ASME Section XI, 

Subsection IWE“ and Chapter XI.S4, 

“10 CFR Part 50, Appendix J"

No
September 2005 II B2-1 NUREG-1801, Rev. 1

B2. MARK II CONTAINMENTS

Systems, Structures, and Components

This section addresses the elements of boiling water reactor (BWR) Mark II containment 

structures. Mark II steel containments are discussed in II.B2.1. Mark II concrete containments 

are discussed in II.B2.2. 

System Interfaces

Functional interfaces include the primary containment heating and ventilation system (VII.F3), 

containment isolation system (V.C), and standby gas treatment system (V.B). Physical 

interfaces exist with any structure, system, or component that either penetrates the containment 

wall, such as the main steam system (VIII.B2) and feedwater system (VIII.D2), or is supported 

by the containment structure. The containment structure basemat may provide support to the 

NSSS components and containment internal structures.
NUREG-1801, Rev. 1 II B2-2 September 2005

II CONTAINMENT STRUCTURES

B2.1 Mark II Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B2.1-1

(C-46)

II.B2.1.1-a Steel elements:

 Suppression 

chamber; 

drywell liner; 

drywell head; 

embedded 

shell; sand 

pocket region; 

support skirt; 

downcomer 

pipes; region 

shielded by 

diaphragm 

floor (as 

applicable)

NOTE: 

Inspection of 

containment 

supports is 

addressed by 

ASME 

Section XI, 

Subsection 

IWF (see 

III.B1.3) 

Steel Air – indoor 

uncontrolled or 

treated water

Loss of 

material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, “ASME Section XI, 

Subsection IWE”

For inaccessible areas (embedded 

containment steel shell or liner), loss of 

material due to corrosion is not 

significant if the following conditions 

are satisfied:

Concrete meeting the specifications of 

ACI 318 or 349 and the guidance of 

201.2R was used for the containment 

concrete in contact with the embedded 

containment shell or liner. The concrete 

is monitored to ensure that it is free of 

penetrating cracks that provide a path 

for water seepage to the surface of the 

containment shell or liner. The moisture 

barrier, at the junction where the shell 

or liner becomes embedded, is subject 

to aging management activities in 

accordance with ASME Section XI, 

Subsection IWE requirements. Water 

ponding on the containment concrete 

floor are not common and when 

detected are cleaned up in a timely 

manner.

If any of the above conditions cannot 

be satisfied, then a plant-specific aging 

management program for corrosion is 

necessary.

Chapter XI.S4, “10 CFR Part 50, 

Yes, if 

corrosion is 

significant for 

inaccessible 

areas

No
September 2005 II B2-3 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B2.1 Mark II Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

Appendix J”

II.B2.1-2

(C-23)

II.B2.1.1-d Steel elements:

Drywell head;

Downcomers

Steel Air – indoor 

uncontrolled

Fretting or 

lockup/ 

mechanical 

wear

Chapter XI.S1, “ASME Section XI, 

Subsection IWE”

No

II.B2.1-3

(C-44)

II.B2.1.1-b Suppression 

pool shell; 

unbraced 

downcomers

Steel; 

stainless 

steel; 

dissimilar 

metal 

welds

Air – indoor 

uncontrolled

Cracking/ cyclic 

loading

(CLB fatigue 

analysis does 

not exist)

Chapter XI.S1, “ASME Section XI, 

Subsection IWE" and Chapter XI.S4, 

“10 CFR Part 50, Appendix J”

Evaluation of 10 CFR 50.55a/ASME 

Section XI, Subsection IWE is to be 

supplemented to consider the 

following:

(4) Detection of Aging Effects: VT-3 

visual inspection may not detect fine 

cracks.

Yes, detection 

of aging 

effects is to be 

evaluated

II.B2.1-4

(C-45)

II.B2.1.1-c Suppression 

pool shell; 

unbraced 

downcomers

Steel; 

stainless 

steel; 

dissimilar 

metal 

welds

Air – indoor 

uncontrolled

Cumulative 

fatigue damage/ 

fatigue

(Only if CLB 

fatigue analysis 

exists)

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period 

of extended operation. See the 

Standard Review Plan, Section 4.6, 

“Containment Liner Plate and 

Penetration Fatigue Analysis” for

acceptable methods for meeting the 

requirements of 10 CFR 54.21(c)(1).

Yes,

TLAA
NUREG-1801, Rev. 1 II B2-4 September 2005

This Page Intentionally Left Blank
September 2005 II B2-5 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B2.2 Mark II Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B2.2-1

(C-06)

II.B2.2.1-e Concrete 

elements; All

Concrete Soil Cracks and 

distortion due to 

increased stress 

levels from 

settlement

Chapter XI.S6, “Structures Monitoring 

Program”

If a de-watering system is relied upon 

for control of settlement, then the 

licensee is to ensure proper 

functioning of the de-watering system 

through the period of extended 

operation. 

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon
NUREG-1801, Rev. 1 II B2-6 September 2005

II CONTAINMENT STRUCTURES

B2.2 Mark II Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B2.2-2

(C-41)

II.B2.2.1-d Concrete:

Basemat; 

reinforcing 

steel

Concrete; 

steel

Air – indoor 

uncontrolled or 

air – outdoor

Cracking, loss of 

bond, and loss of 

material 

(spalling, 

scaling)/ 

corrosion of 

embedded steel

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible Areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

surface cracking, loss of bond, and 

loss of material (spalling, scaling) due 

to corrosion of embedded steel.

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 

500 ppm, or sulfates <1500 ppm, as a 

minimum, consider (1) Examination of 

the exposed portions of the below 

grade concrete, when excavated for 

any reason, and

(2) Periodic monitoring of below-grade 

water chemistry, including 

consideration of potential seasonal 

variations.

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the 

concrete aging during the period of 

extended operation.

Yes, plantspecific if 

environment 

is aggressive
September 2005 II B2-7 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B2.2 Mark II Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B2.2-3

(C-35)

II.B2.2.1-g Concrete:

Containment; 

wall; basemat

Concrete Air – indoor 

uncontrolled or 

air – outdoor

Reduction of 

strength and 

modulus/ 

elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging management 

program

The implementation of 10 CFR 50.55a 

and ASME Section XI, Subsection IWL 

would not be able to identify the 

reduction of strength and modulus due 

to elevated temperature. Thus, for any 

portions of concrete containment that 

exceed specified temperature limits, 

further evaluations are warranted. 

Subsection CC-3400 of ASME 

Section III, Division 2, specifies the 

concrete temperature limits for normal 

operation or any other long-term 

period. The temperatures shall not 

exceed 150°F except for local areas, 

such as around penetrations, which 

are not allowed to exceed 200°F. If 

significant equipment loads are 

supported by concrete at temperatures 

exceeding 150°F, an evaluation of the 

ability to withstand the postulated 

design loads is to be made.

Higher temperatures than given above 

may be allowed in the concrete if tests 

and/or calculations are provided to 

evaluate the reduction in strength and 

this reduction is applied to the design 

allowables.

Yes, if 

temperature 

limits are 

exceeded
NUREG-1801, Rev. 1 II B2-8 September 2005

II CONTAINMENT STRUCTURES

B2.2 Mark II Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B2.2-4

(C-39)

II.B2.2.1-c Concrete:

Containment; 

wall; basemat

Concrete Any Cracking due to 

expansion/ 

reaction with 

aggregates

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible Areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

surface cracking due to reaction with 

aggregates.

Inaccessible Areas:

As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates performed 

in accordance with ASTM C295-54 or 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregatereinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with ACI 

201.2R. Therefore, if these conditions 

are satisfied, aging management is not 

necessary.

Yes, if 

concrete was 

not 

constructed 

as stated for 

inaccessible 

areas
September 2005 II B2-9 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B2.2 Mark II Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B2.2-5

(C-26)

II.B2.2.1-b Concrete:

Containment; 

wall; basemat

Concrete Ground 

water/soil or 

air-indoor 

uncontrolled or 

air-outdoor

Increase in 

porosity and 

permeability, 

cracking, loss of 

material 

(spalling, 

scaling)/ 

aggressive 

chemical attack

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible Areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

increase in porosity and permeability, 

surface cracking, or loss of material 

(spalling, scaling) due to aggressive 

chemical attack.

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 

500 ppm, or sulfates <1500 ppm, as a 

minimum, consider (1) Examination of 

the exposed portions of the below 

grade concrete, when excavated for 

any reason, and

(2) Periodic monitoring of below-grade 

water chemistry, including 

consideration of potential seasonal 

variations.

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the 

concrete aging during the period of 

extended operation.

Yes, plantspecific if 

environment 

is aggressive
NUREG-1801, Rev. 1 II B2-10 September 2005

II CONTAINMENT STRUCTURES

B2.2 Mark II Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B2.2-6

(C-31)

II.B2.2.1-a Concrete:

Containment; 

wall; basemat

Concrete Water – flowing Increase in 

porosity, 

permeability/ 

leaching of 

calcium 

hydroxide

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

increase in porosity, and permeability 

due to leaching of calcium hydroxide.

Inaccessible Areas:

An aging management program is not 

necessary, even if reinforced concrete 

is exposed to flowing water, if there is 

documented evidence that confirms 

the in-place concrete was constructed 

in accordance with the 

recommendations in ACI 201.2R-77.

Yes, if 

concrete was 

not 

constructed 

as stated for 

inaccessible 

areas
September 2005 II B2-11 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B2.2 Mark II Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B2.2-7

(C-07)

II.B2.2.1-f Concrete:

Foundation; 

subfoundation

Concrete; 

porous 

concrete

Water – flowing Reduction in 

foundation 

strength, 

cracking, 

differential 

settlement/ 

erosion of 

porous concrete 

subfoundation

Chapter XI.S6, “Structures Monitoring 

Program”

Erosion of cement from porous 

concrete subfoundations beneath 

containment basemats is described in 

IN 97-11. IN 98-26 proposes 

Maintenance Rule Structures 

Monitoring for managing this aging 

effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous 

concrete subfoundations, then the 

licensee is to ensure proper 

functioning of the de-watering system 

through the period of extended 

operation.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon

II.B2.2-8

(C-11)

II.B2.2.3-b Prestressing 

system:

Tendons

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of 

prestress/ 

relaxation; 

shrinkage; 

creep; elevated 

temperature

Loss of tendon prestress is a timelimited aging analysis (TLAA) to be 

evaluated for the period of extended 

operation.

See the Standard Review Plan, 

Section 4.5, “Concrete Containment 

Tendon Prestress” for acceptable 

methods for meeting the requirements 

of 10 CFR 54.21(c)(1)(i) and (ii). See 

Chapter X.S1 of this report for meeting 

the requirements of 

10 CFR 54.21(c)(1)(iii).

For periodic monitoring of prestress, 

see Chapter XI.S2.

Yes,

TLAA
NUREG-1801, Rev. 1 II B2-12 September 2005

II CONTAINMENT STRUCTURES

B2.2 Mark II Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B2.2-9

(C-10)

II.B2.2.3-a Prestressing 

system:

Tendons; 

anchorage 

components

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of material/ 

corrosion

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

No

II.B2.2-10

(C-46)

II.B2.2.2-a Steel elements:

 Suppression 

chamber; 

drywell liner; 

drywell head; 

embedded 

shell; sand 

pocket region; 

support skirt; 

downcomer 

pipes; region 

shielded by 

diaphragm 

floor (as 

applicable)

NOTE: 

Inspection of 

containment 

supports is 

addressed by 

ASME 

Section XI, 

Subsection 

IWF (see 

III.B1.3) 

Steel Air – indoor 

uncontrolled or 

treated water

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, “ASME Section XI, 

Subsection IWE”

For inaccessible areas (embedded 

containment steel shell or liner), loss of 

material due to corrosion is not 

significant if the following conditions 

are satisfied:

Concrete meeting the specifications of 

ACI 318 or 349 and the guidance of 

201.2R was used for the containment 

concrete in contact with the embedded 

containment shell or liner. The 

concrete is monitored to ensure that it 

is free of penetrating cracks that 

provide a path for water seepage to 

the surface of the containment shell or 

liner. The moisture barrier, at the 

junction where the shell or liner 

becomes embedded, is subject to 

aging management activities in 

accordance with ASME Section XI, 

Subsection IWE requirements. Water 

ponding on the containment concrete 

floor are not common and when 

detected are cleaned up in a timely 

Yes, if 

corrosion is 

significant for 

inaccessible 

areas
September 2005 II B2-13 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B2.2 Mark II Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

manner.

If any of the above conditions cannot 

be satisfied, then a plant-specific aging 

management program for corrosion is 

necessary.

Chapter XI.S4, “10 CFR Part 50, 

Appendix J”

No

II.B2.2-11

(C-23)

II.B2.2.2-e Steel elements:

Drywell head;

Downcomers

Steel Air – indoor 

uncontrolled

Fretting or 

lockup/ 

mechanical wear

Chapter XI.S1, “ASME Section XI, 

Subsection IWE”

No

II.B2.2-12

(C-49)

II.B2.2.2-b Steel elements:

Suppression 

chamber liner 

(interior 

surface)

Stainless 

steel; steel

Air – indoor 

uncontrolled or 

treated water

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, “ASME Section XI, 

Subsection IWE“ and Chapter XI.S4, 

“10 CFR Part 50, Appendix J"

No

II.B2.2-13

(C-47)

II.B2.2.2-c Steel elements:

Vent header;

Downcomers 

Stainless 

steel; steel

Air – indoor 

uncontrolled

Cracking/ cyclic 

loading

(CLB fatigue 

analysis does 

not exist)

Chapter XI.S1, “ASME Section XI, 

Subsection IWE" and Chapter XI.S4, 

“10 CFR Part 50, Appendix J”

Evaluation of 10 CFR 50.55a/ASME 

Section XI, Subsection IWE is 

augmented as follows:

(4) Detection of Aging Effects: VT-3 

visual inspection may not detect fine 

cracks.

Yes, detection 

of aging 

effects is to be 

evaluated
NUREG-1801, Rev. 1 II B2-14 September 2005

II CONTAINMENT STRUCTURES

B2.2 Mark II Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B2.2-14

(C-48)

II.B2.2.2-d Steel elements:

Vent header;

Downcomers 

Stainless 

steel; steel

Air – indoor 

uncontrolled or 

treated water

Cumulative 

fatigue damage/ 

fatigue

(Only if CLB

fatigue analysis 

exists)

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period 

of extended operation. See the 

Standard Review Plan, Section 4.6, 

“Containment Liner Plate and 

Penetration Fatigue Analysis” for 

acceptable methods for meeting the 

requirements of 10 CFR 54.21(c)(1).

Yes,

TLAA
September 2005 II B3-1 NUREG-1801, Rev. 1

B3. MARK III CONTAINMENTS

B3.1 Steel Containments

B3.2 Concrete Containments
NUREG-1801, Rev. 1 II B3-2 September 2005

This Page Intentionally Left Blank
September 2005 II B3-3 NUREG-1801, Rev. 1

B3. MARK III CONTAINMENTS

Systems, Structures, and Components

This section addresses the elements of boiling water reactor (BWR) Mark III containment 

structures. Mark III steel containments are discussed in II.B3.1. Mark III concrete containments 

are discussed in II.B3.2.

System Interfaces

Functional interfaces include the primary containment heating and ventilation system (VII.F3), 

containment isolation system (V.C), and standby gas treatment system (V.B). Physical 

interfaces exist with any structure, system, or component that either penetrates the containment 

wall, such as the main steam system (VIII.B2) and feedwater system (VIII.D2), or is supported 

by the containment structure. The containment structure basemat may provide support to the 

NSSS components and containment internal structures.
NUREG-1801, Rev. 1 II B3-4 September 2005

II CONTAINMENT STRUCTURES

B3.1 Mark III Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B3.1-1

(C-25)

II.B3.1.2-b Concrete:

Basemat

Concrete Ground 

water/soil

Increase in 

porosity and 

permeability, 

cracking, loss of 

material 

(spalling, 

scaling)/ 

aggressive 

chemical attack

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible Areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

increase in porosity and permeability, 

surface cracking, or loss of material 

(spalling, scaling) due to aggressive 

chemical attack.

Inaccessible Areas:

For plants with non-aggressive 

ground water/soil; i.e., pH > 5.5, 

chlorides < 500 ppm, or sulfates 

<1500 ppm, as a minimum, consider 

(1) Examination of the exposed 

portions of the below grade concrete, 

when excavated for any reason, and

(2) Periodic monitoring of belowgrade water chemistry, including 

consideration of potential seasonal 

variations.

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the 

extent of the degradation experienced 

should be implemented to manage 

the concrete aging during the period 

of extended operation.

Yes, plantspecific if 

environment is 

aggressive
September 2005 II B3-5 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B3.1 Mark III Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B3.1-2

(C-36)

II.B3.1.2-e Concrete:

Basemat

Concrete Soil Cracks and 

distortion due to 

increased stress 

levels from 

settlement

Chapter XI.S6, “Structures Monitoring 

Program”

If a de-watering system is relied upon 

for control of settlement, then the 

licensee is to ensure proper 

functioning of the de-watering system 

through the period of extended 

operation. 

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon

II.B3.1-3

(C-30)

II.B3.1.2-a Concrete:

Basemat

Concrete Water – flowing Increase in 

porosity, 

permeability/ 

leaching of 

calcium 

hydroxide

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

increase in porosity, and permeability 

due to leaching of calcium hydroxide.

Inaccessible Areas:

 An aging management program is 

not necessary, even if reinforced 

concrete is exposed to flowing water, 

if there is documented evidence that 

confirms the in-place concrete was 

constructed in accordance with the 

recommendations in ACI 201.2R.

Yes, if 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas
NUREG-1801, Rev. 1 II B3-6 September 2005

II CONTAINMENT STRUCTURES

B3.1 Mark III Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B3.1-4

(C-50)

II.B3.1.2-g Concrete:

Basemat, 

concrete fill-in 

annulus

Concrete Air – indoor 

uncontrolled or 

air – outdoor

Reduction of 

strength and 

modulus/ 

elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging management 

program

The implementation of 

10 CFR 50.55a and ASME Section 

XI, Subsection IWL would not be able 

to identify the reduction of strength 

and modulus due to elevated 

temperature. Thus, for any portions of 

concrete containment that exceed 

specified temperature limits, further 

evaluations are warranted. 

Subsection CC-3400 of ASME 

Section III, Division 2, specifies the 

concrete temperature limits for normal 

operation or any other long-term 

period. The temperatures shall not 

exceed 150°F except for local areas, 

such as around penetrations, which 

are not allowed to exceed 200°F. If 

significant equipment loads are 

supported by concrete at 

temperatures exceeding 150°F, an 

evaluation of the ability to withstand 

the postulated design loads is to be 

made.

Higher temperatures than given 

above may be allowed in the concrete 

if tests and/or calculations are 

provided to evaluate the reduction in 

strength and this reduction is applied 

to the design allowables.

Yes, if 

temperature 

limits are 

exceeded
September 2005 II B3-7 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B3.1 Mark III Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B3.1-5

(C-51)

II.B3.1.2-c Concrete:

Basemat, 

concrete fill-in 

annulus

Concrete Any Cracking due to 

expansion/ 

reaction with 

aggregates

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible Areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

surface cracking due to reaction with 

aggregates.

Inaccessible Areas:

As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates 

performed in accordance with ASTM 

C295-54 or ASTM C227-50 can 

demonstrate that those aggregates 

do not react within reinforced 

concrete. For potentially reactive 

aggregates, aggregate-reinforced 

concrete reaction is not significant if 

the concrete was constructed in 

accordance with ACI 

201.2R.Therefore, if these conditions 

are satisfied, aging management is 

not necessary.

Yes, if 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas
NUREG-1801, Rev. 1 II B3-8 September 2005

II CONTAINMENT STRUCTURES

B3.1 Mark III Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B3.1-6

(C-43)

II.B3.1.2-d Concrete:

Basemat; 

reinforcing 

steel

Concrete; 

steel

Air – indoor 

uncontrolled or 

air – outdoor

Cracking, loss of 

bond, and loss of 

material 

(spalling, 

scaling)/ 

corrosion of 

embedded steel

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible Areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

surface cracking, loss of bond, and 

loss of material (spalling, scaling) due 

to corrosion of embedded steel.

Inaccessible Areas:

For plants with non-aggressive 

ground water/soil; i.e., pH > 5.5, 

chlorides < 500 ppm, or sulfates 

<1500 ppm, as a minimum, consider 

(1) Examination of the exposed 

portions of the below grade concrete, 

when excavated for any reason, and

(2) Periodic monitoring of belowgrade water chemistry, including 

consideration of potential seasonal 

variations.

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the 

extent of the degradation experienced 

should be implemented to manage 

the concrete aging during the period 

of extended operation.

Yes, plantspecific if 

environment is 

aggressive
September 2005 II B3-9 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B3.1 Mark III Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B3.1-7

(C-07)

II.B3.1.2-f Concrete:

Foundation; 

subfoundation

Concrete; 

porous 

concrete

Water – flowing Reduction in 

foundation 

strength, 

cracking, 

differential 

settlement/ 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Monitoring 

Program”

Erosion of cement from porous 

concrete subfoundations beneath 

containment basemats is described in 

IN 97-11. IN 98-26 proposes 

Maintenance Rule Structures 

Monitoring for managing this aging 

effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous 

concrete subfoundations, then the 

licensee is to ensure proper 

functioning of the de-watering system 

through the period of extended 

operation.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering

system is 

relied upon

II.B3.1-8

(C-19)

II.B3.1.1-a Steel elements:

Drywell; torus; 

drywell

head; 

embedded 

shell

and sand 

pocket 

regions;

drywell 

support skirt;

torus ring 

girder;

downcomers; 

ECCS

Steel Air – indoor 

uncontrolled or 

treated water

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, “ASME Section XI, 

Subsection IWE”

For inaccessible areas (embedded 

containment steel shell or liner), loss 

of material due to corrosion is not 

significant if the following conditions 

are satisfied:

Concrete meeting the specifications 

of ACI 318 or 349 and the guidance 

of 201.2R was used for the 

containment concrete in contact with 

the embedded containment shell or 

liner. The concrete is monitored to 

ensure that it is free of penetrating 

Yes, if 

corrosion is 

significant for 

inaccessible 

areas
NUREG-1801, Rev. 1 II B3-10 September 2005

II CONTAINMENT STRUCTURES

B3.1 Mark III Steel Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

suction 

header

NOTE: 

Inspection of 

containment 

supports is 

addressed by 

ASME 

Section XI, 

Subsection 

IWF (see 

III.B1.3) 

cracks that provide a path for water 

seepage to the surface of the 

containment shell or liner. The 

moisture barrier, at the junction where

the shell or liner becomes embedded, 

is subject to aging management 

activities in accordance with ASME 

Section XI, Subsection IWE 

requirements. Water ponding on the 

containment concrete floor are not 

common and when detected are 

cleaned up in a timely manner.

If any of the above conditions cannot 

be satisfied, then a plant-specific 

aging management program for 

corrosion is necessary.

Chapter XI.S4, “10 CFR Part 50, 

Appendix J” 

No

II.B3.1-9

(C-24)

II.B3.1.1-b Steel elements:

Suppression 

chamber shell 

(interior 

surface)

Stainless 

steel

Air – indoor 

uncontrolled

Cracking/ stress 

corrosion 

cracking

Chapter XI.S1, “ASME Section XI, 

Subsection IWE” and Chapter XI.S4, 

“10 CFR Part 50, Appendix J”

No
September 2005 II B3-11 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B3.2 Mark III Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B3.2-1

(C-06)

II.B3.2.1-f Concrete 

elements; All

Concrete Soil Cracks and 

distortion due to 

increased stress 

levels from 

settlement

Chapter XI.S6, “Structures Monitoring 

Program”

If a de-watering system is relied upon 

for control of settlement, then the 

licensee is to ensure proper 

functioning of the de-watering system 

through the period of extended 

operation. 

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon
NUREG-1801, Rev. 1 II B3-12 September 2005

II CONTAINMENT STRUCTURES

B3.2 Mark III Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B3.2-2

(C-33)

II.B3.2.1-h Concrete:

Dome; wall;

basemat

Concrete Air – indoor 

uncontrolled or 

air – outdoor

Reduction of 

strength and 

modulus/ 

elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging management 

program

The implementation of 10 CFR 50.55a 

and ASME Section XI, Subsection

IWL would not be able to identify the 

reduction of strength and modulus 

due to elevated temperature. Thus, 

for any portions of concrete 

containment that exceed specified 

temperature limits, further evaluations 

are warranted. Subsection CC-3400 

of ASME Section III, Division 2, 

specifies the concrete temperature 

limits for normal operation or any 

other long-term period. The 

temperatures shall not exceed 150°F 

except for local areas, such as around 

penetrations, which are not allowed to 

exceed 200°F. If significant equipment 

loads are supported by concrete at 

temperatures exceeding 150°F, an 

evaluation of the ability to withstand 

the postulated design loads is to be 

made.

Higher temperatures than given 

above may be allowed in the concrete 

if tests and/or calculations are 

provided to evaluate the reduction in 

strength and this reduction is applied 

to the design allowables.

Yes, if 

temperature 

limits are 

exceeded
September 2005 II B3-13 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B3.2 Mark III Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B3.2-3

(C-29)

II.B3.2.1-a Concrete:

Dome; wall; 

basemat

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking/ 

freeze-thaw

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

loss of material (spalling, scaling) and 

surface cracking due to freeze-thaw.

Inaccessible Areas:

Evaluation is needed for plants that 

are located in moderate to severe 

weathering conditions (weathering 

index >100 day-inch/yr) (NUREG1557). Documented evidence 

confirms that where the existing 

concrete had air content of 3% to 6%, 

subsequent inspection did not exhibit 

degradation related to freeze-thaw. 

Such inspections should be 

considered a part of the evaluation.

The weathering index for the 

continental US is shown in ASTM 

C33-90, Fig. 1.

Yes, for 

inaccessible 

areas of 

plants located 

in moderate to 

severe 

weathering 

conditions
NUREG-1801, Rev. 1 II B3-14 September 2005

II CONTAINMENT STRUCTURES

B3.2 Mark III Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B3.2-4

(C-40)

II.B3.2.1-d Concrete:

Dome; wall; 

basemat

Concrete Any Cracking due to 

expansion/ 

reaction with 

aggregates

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible Areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

surface cracking due to reaction with 

aggregates.

Inaccessible Areas:

As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates 

performed in accordance with ASTM 

C295-54 or ASTM C227-50 can 

demonstrate that those aggregates do 

not react within reinforced concrete. 

For potentially reactive aggregates, 

aggregate-reinforced concrete 

reaction is not significant if the 

concrete was constructed in 

accordance with ACI 

201.2R.Therefore, if these conditions 

are satisfied, aging management is 

not necessary.

Yes, if 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas
September 2005 II B3-15 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B3.2 Mark III Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B3.2-5

(C-27)

II.B3.2.1-c Concrete:

Dome; wall; 

basemat

Concrete Ground 

water/soil or 

air-indoor 

uncontrolled or 

air-outdoor

Increase in 

porosity and 

permeability, 

cracking, loss of 

material 

(spalling, 

scaling)/ 

aggressive 

chemical attack

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible Areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

increase in porosity and permeability, 

surface cracking, or loss of material 

(spalling, scaling) due to aggressive 

chemical attack.

Inaccessible Areas:

For plants with non-aggressive 

ground water/soil; i.e., pH > 5.5, 

chlorides < 500 ppm, or sulfates 

<1500 ppm, as a minimum, consider 

(1) Examination of the exposed 

portions of the below grade concrete, 

when excavated for any reason, and

(2) Periodic monitoring of below-grade 

water chemistry, including 

consideration of potential seasonal 

variations.

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the 

extent of the degradation experienced 

should be implemented to manage 

the concrete aging during the period 

of extended operation.

Yes, plantspecific if 

environment is 

aggressive
NUREG-1801, Rev. 1 II B3-16 September 2005

II CONTAINMENT STRUCTURES

B3.2 Mark III Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B3.2-6

(C-32)

II.B3.2.1-b Concrete:

Dome; wall; 

basemat

Concrete Water – flowing Increase in 

porosity, 

permeability/ 

leaching of 

calcium 

hydroxide

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

increase in porosity, and permeability 

due to leaching of calcium hydroxide.

Inaccessible Areas:

An aging management program is not 

necessary, even if reinforced concrete 

is exposed to flowing water, if there is 

documented evidence that confirms 

the in-place concrete was constructed 

in accordance with the 

recommendations in ACI 201.2R-77.

Yes, if 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas
September 2005 II B3-17 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B3.2 Mark III Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B3.2-7

(C-42)

II.B3.2.1-e Concrete:

Dome; wall; 

basemat; 

reinforcing 

steel

Concrete; 

steel

Air – indoor 

uncontrolled or 

air – outdoor

Cracking, loss of 

bond, and loss of 

material 

(spalling, 

scaling)/ 

corrosion of 

embedded steel

Chapter XI.S2, “ASME Section XI, 

Subsection IWL”

Accessible Areas:

Inspections performed in accordance 

with IWL will indicate the presence of 

surface cracking, loss of bond, and 

loss of material (spalling, scaling) due 

to corrosion of embedded steel.

Inaccessible Areas:

For plants with non-aggressive 

ground water/soil; i.e., pH > 5.5, 

chlorides < 500 ppm, or sulfates 

<1500 ppm, as a minimum, consider 

(1) Examination of the exposed 

portions of the below grade concrete, 

when excavated for any reason, and

(2) Periodic monitoring of below-grade 

water chemistry, including 

consideration of potential seasonal 

variations.

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have

experienced degradation, a plant 

specific AMP accounting for the 

extent of the degradation experienced 

should be implemented to manage 

the concrete aging during the period 

of extended operation.

Yes, plantspecific if 

environment is 

aggressive
NUREG-1801, Rev. 1 II B3-18 September 2005

II CONTAINMENT STRUCTURES

B3.2 Mark III Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B3.2-8

(C-07)

II.B3.2.1-g Concrete:

Foundation; 

subfoundatio

n

Concrete; 

porous 

concrete

Water – flowing Reduction in 

foundation 

strength, 

cracking, 

differential 

settlement/ 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Monitoring 

Program”

Erosion of cement from porous 

concrete subfoundations beneath 

containment basemats is described in 

IN 97-11. IN 98-26 proposes 

Maintenance Rule Structures 

Monitoring for managing this aging 

effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous 

concrete subfoundations, then the 

licensee is to ensure proper 

functioning of the de-watering system 

through the period of extended 

operation.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon

II.B3.2-9

(C-09)

II.B3.2.2-a Steel 

elements:

Liner;

Liner 

anchors;

Integral 

attachments

Steel Air – indoor 

uncontrolled

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, “ASME Section XI, 

Subsection IWE”

For inaccessible areas (embedded 

containment steel shell or liner), loss 

of material due to corrosion is not 

significant if the following conditions 

are satisfied:

1. Concrete meeting the requirements 

of ACI 318 or 349 and the guidance of 

201.2R was used for the containment 

concrete in contact with the 

embedded containment shell or liner. 

2. The concrete is monitored to 

ensure that it is free of penetrating 

Yes, if 

corrosion is 

significant for 

inaccessible 

areas
September 2005 II B3-19 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B3.2 Mark III Concrete Containments

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

cracks that provide a path for water 

seepage to the surface of the 

containment shell or liner. 

3. The moisture barrier, at the junction 

where the shell or liner becomes 

embedded, is subject to aging 

management activities in accordance 

with ASME Section XI, Subsection 

IWE requirements. 

4. Borated water spills and water 

ponding on the containment concrete 

floor are not common and when 

detected are cleaned up in a timely 

manner.

If any of the above conditions cannot 

be satisfied, then a plant-specific 

aging management program for 

corrosion is necessary.

Chapter XI.S4, “10 CFR Part 50, 

Appendix J” 

No

II.B3.2-10

(C-24)

II.B3.2.2-b Steel 

elements:

Suppression 

chamber shell 

(interior 

surface)

Stainless 

steel

Air – indoor 

uncontrolled

Cracking/ stress 

corrosion 

cracking

Chapter XI.S1, “ASME Section XI, 

Subsection IWE” and Chapter XI.S4, 

“10 CFR Part 50, Appendix J”

No
NUREG-1801, Rev. 1 II B3-20 September 2005

This Page Intentionally Left Blank
September 2005 II B4-1 NUREG-1801, Rev. 1

B4. COMMON COMPONENTS

Systems, Structures, and Components

This section addresses the common components of boiling water reactor (BWR) containments. 

The common components include penetration sleeves and bellows; dissimilar metal welds; 

personnel airlock; equipment hatch; CRD hatch; seals, gaskets, and moisture barriers.

System Interfaces

Functional interfaces include the primary containment heating and ventilation system (VII.F3), 

containment isolation system (V.C), and standby gas treatment system (V.B). Physical 

interfaces exist with any structure, system, or component that either penetrates the containment 

wall, such as the main steam system (VIII.B2) and feedwater system (VIII.D2), or is supported 

by the containment structure. The containment structure basemat may provide support to the 

NSSS components and containment internal structures.
NUREG-1801, Rev. 1 II B4-2 September 2005

II CONTAINMENT STRUCTURES

B4 Common Components

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B4-1

(C-12)

II.B4.1-a Penetration 

sleeves

Steel; 

dissimilar 

metal welds

Air – indoor 

uncontrolled

or air – outdoor

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, “ASME Section XI, 

Subsection IWE,”

(Note: IWE examination category E-F, 

surface examination of dissimilar metal 

welds, is recommended)

Chapter XI.S4, “10 CFR Part 50, 

Appendix J” 

No

No 
September 2005 II B4-3 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B4 Common Components

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B4-2

(C-15)

II.B4.1-d Penetration 

sleeves;

Penetration 

bellows

Stainless 

steel; 

dissimilar 

metal welds

Air – indoor 

uncontrolled or 

air – outdoor

Cracking/ stress 

corrosion 

cracking

Chapter XI.S1, “ASME Section XI, 

Subsection IWE” and Chapter XI.S4, 

“10 CFR Part 50, Appendix J”

Evaluation of 10 CFR 50.55a/ASME 

Section XI, Subsection IWE is 

augmented as follows:

(4) Detection of Aging Effects:

Transgranular Stress corrosion 

cracking (TGSCC) is a concern for 

dissimilar metal welds. In the case of 

bellows assemblies, SCC may cause 

aging effects particularly if the material 

is not shielded from a corrosive 

environment. ASME Section XI, 

Subsection IWE covers inspection of 

these items under examination 

categories E-B, E-F, and E-P (10 CFR 

Part 50, Appendix J pressure tests). 

10 CFR 50.55a identifies examination 

categories E-B and E-F as optional 

during the current term of operation. 

For the extended period of operation, 

Examination Categories E-B & E-F, and 

additional appropriate examinations to 

detect SCC in bellows assemblies and 

dissimilar metal welds are warranted to 

address this issue.

(10) Operating Experience:

IN 92-20 describes an instance of 

containment bellows cracking, resulting 

in loss of leak tightness.

Yes, detection 

of aging 

effects is to 

be evaluated
NUREG-1801, Rev. 1 II B4-4 September 2005

II CONTAINMENT STRUCTURES

B4 Common Components

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B4-3

(C-14)

II.B4.1-c Penetration 

sleeves;

Penetration 

bellows

Steel; 

stainless 

steel; 

dissimilar 

metal welds

Air – indoor 

uncontrolled or 

air – outdoor

Cracking/ cyclic 

loading

(CLB fatigue 

analysis does 

not exist)

Chapter XI.S1, “ASME Section XI, 

Subsection IWE" and Chapter XI.S4, 

“10 CFR Part 50, Appendix J”

Evaluation of 10 CFR 50.55a/ASME 

Section XI, Subsection IWE is to be 

supplemented to consider the following:

(4) Detection of Aging Effects: VT-3 

visual inspection may not detect fine 

cracks.

Yes, detection 

of aging 

effects is to 

be evaluated

II.B4-4

(C-13)

II.B4.1-b Penetration 

sleeves;

Penetration 

bellows

Steel; 

stainless 

steel; 

dissimilar 

metal welds

Air – indoor 

uncontrolled or 

air – outdoor

Cumulative 

fatigue damage/ 

fatigue

(Only if CLB 

fatigue analysis 

exists)

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.6, 

“Containment Liner Plate and 

Penetration Fatigue Analysis” for 

acceptable methods for meeting the 

requirements of 10 CFR 54.21(c)(1).

Yes,

TLAA

II.B4-5

(C-17)

II.B4.2-b Personnel 

airlock, 

equipment 

hatch, CRD 

hatch:

Locks, 

hinges, and 

closure 

mechanisms

Steel Air – indoor

uncontrolled

or air – outdoor

Loss of leak 

tightness/ 

mechanical wear 

of locks, hinges 

and closure 

mechanisms

Chapter XI.S4, “10 CFR Part 50, 

Appendix J” and

Plant Technical Specifications

No
September 2005 II B4-5 NUREG-1801, Rev. 1

II CONTAINMENT STRUCTURES

B4 Common Components

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

II.B4-6

(C-16)

II.B4.2-a Personnel 

airlock, 

equipment 

hatch, CRD 

hatch

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, “ASME Section XI, 

Subsection IWE,”

Chapter XI.S4, “10 CFR Part 50, 

Appendix J”

No

No

II.B4-7

(C-18)

II.B4.3-a Seals, 

gaskets, and 

moisture 

barriers 

(caulking, 

flashing, and 

other 

sealants)

Elastomers, 

rubber and 

other similar 

materials

Air – indoor 

uncontrolled or 

air – outdoor

Loss of sealing; 

Leakage through 

containment/ 

deterioration of 

seals, gaskets, 

and moisture 

barriers 

(caulking, 

flashing, and 

other sealants)

Chapter XI.S1, “ASME Section XI, 

Subsection IWE”

Leak tightness will be monitored by 

10 CFR Part 50, Appendix J Leak Rate 

Tests for pressure boundary, seals and 

gaskets (including O-rings).

No
NUREG-1801, Rev. 1 II B4-6 September 2005

This Page Intentionally Left Blank
September 2005 III-i NUREG-1801, Rev. 1

CHAPTER III

STRUCTURES AND COMPONENT SUPPORTS
NUREG-1801, Rev. 1 III-ii September 2005

This Page Intentionally Left Blank
September 2005 III-iii NUREG-1801, Rev. 1

STRUCTURES AND COMPONENT SUPPORTS

Chapter III A: Safety Related and Other Structures

Safety related structures are those structures defined pursuant to 10 CFR 54.4(a)(1) and the 

other structures are those defined pursuant to 10 CFR 54.4(a)(2) and 10 CFR 54.4(a)(3). 

Structures in this section are organized into nine groups and are discussed separately under 

subheadings A1 through A9.

Chapter III B: Component Supports

Component supports include supports for ASME piping and components; supports for cable 

trays, conduit, HVAC ducts, TubeTrack®, instrument tubing, non-ASME piping and 

components; anchorage of racks, panels, cabinets, and enclosures for electrical equipment 

and instrumentation; supports for emergency diesel generator (EDG) and HVAC system 

components; and supports for platforms, pipe whip restraints, jet impingement shields, 

masonry walls, and other miscellaneous structures.
NUREG-1801, Rev. 1 III-iv September 2005

DraftDraftNUREG-1801, Rev. 1 III A2-iv September 2005 

This Page Intentionally Left Blank
September 2005 III A-1 NUREG-1801, Rev. 1

III.A SAFETY RELATED AND OTHER STRUCTURES

A1. Group 1 Structures (BWR Reactor Bldg., PWR Shield Bldg., Control Rm./Bldg.)

A2. Group 2 Structures (BWR Reactor Bldg. with Steel Superstructure)

A3. Group 3 Structures (Auxiliary Bldg., Diesel Generator Bldg., Radwaste Bldg., Turbine 

Bldg., Switchgear Rm., Yard Structures such as AFW Pumphouse, Utility/Piping Tunnels, 

Security/Lighting Poles, Manholes, Duct Banks; SBO Structures such as Transmission 

Towers, Startup Towers Circuit Breaker Foundation, Electrical Enclosure)

A4. Group 4 Structures (Containment Internal Structures, excluding Refueling Canal)

A5. Group 5 Structures (Fuel Storage Facility, Refueling Canal)

A6. Group 6 Structures (Water-Control Structures)

A7. Group 7 Structures (Concrete Tanks and Missile Barriers)

A8. Group 8 Structures (Steel Tanks and Missile Barriers)

A9. Group 9 Structures (BWR Unit Vent Stack)
NUREG-1801, Rev. 1 III A-2 September 2005

DraftDraftNUREG-1801, Rev. 1 III A1-2 September 2005 

This Page Intentionally Left Blank
September 2005 III A1-1 NUREG-1801, Rev. 1

A1. GROUP 1 STRUCTURES (BWR REACTOR BLDG., PWR SHIELD BLDG., CONTROL 

RM./BLDG.)

Systems, Structures, and Components

This section addresses the elements of boiling water reactor (BWR) reactor building, 

pressurized water reactor (PWR) shield building, and control room/building. For this group, the 

applicable structural elements are concrete, steel, and masonry walls. The aging management 

review is presented for each applicable combination of structural element and aging effect.

System Interfaces

Physical interfaces exist with any system or component that either penetrates the structure wall 

or is supported by the structure wall, floor, and roof. The direct interface is through the system 

or component supports that are anchored to the structure. Structures also protect housed 

systems or components from internal and external design basis events. In the case of tanks, 

there is a functional interface with the associated system. Water-control structures are integral 

parts of the systems that provide plant cooling water and residual heat removal.
NUREG-1801, Rev. 1 III A1-2 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A1 Group 1 Structures (BWR Reactor Bldg., PWR Shield Bldg., Control Rm./Bldg.)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A1-1

(T-10)

III.A1.1-j Concrete:

All

Reinforced 

concrete

Air – indoor 

uncontrolled

Reduction of 

strength and 

modulus/ elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging management 

program

For any concrete elements that exceed 

specified temperature limits, further 

evaluations are warranted. Appendix A 

of ACI 349-85 specifies the concrete 

temperature limits for normal operation 

or any other long-term period. The 

temperatures shall not exceed 150°F 

except for local areas which are allowed 

to have increased temperatures not to 

exceed 200°F.

Yes, if 

temperature 

limits are 

exceeded
September 2005 III A1-3 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A1 Group 1 Structures (BWR Reactor Bldg., PWR Shield Bldg., Control Rm./Bldg.)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A1-2

(T-03)

III.A1.1-c Concrete:

All

Reinforced 

concrete

Any Cracking due to 

expansion/ 

reaction with 

aggregates

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible Areas:

Inspections/evaluations performed in 

accordance with the Structures 

Monitoring Program will indicate the 

presence of expansion and cracking due 

to reaction with aggregates.

Inaccessible Areas:

As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates performed 

in accordance with ASTM C295-54 or 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregatereinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with ACI

201.2R. Therefore, if these conditions 

are satisfied, aging management is not 

necessary.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas.
NUREG-1801, Rev. 1 III A1-4 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A1 Group 1 Structures (BWR Reactor Bldg., PWR Shield Bldg., Control Rm./Bldg.)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A1-3

(T-08)

III.A1.1-h Concrete:

All

Reinforced 

concrete

Soil Cracks and 

distortion due to 

increased stress 

levels from 

settlement

Chapter XI.S6, “Structures Monitoring 

Program”

If a de-watering system is relied upon for 

control of settlement, then the licensee 

is to ensure proper functioning of the dewatering system through the period of 

extended operation. 

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon
September 2005 III A1-5 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A1 Group 1 Structures (BWR Reactor Bldg., PWR Shield Bldg., Control Rm./Bldg.)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A1-4

(T-05)

III.A1.1-e Concrete:

Below-grade 

exterior; 

foundation

Reinforced 

concrete

Ground 

water/soil

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling)/ corrosion 

of embedded steel

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible Areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the cracking, loss of bond, 

or loss of material (spalling, scaling) due 

to corrosion of embedded steel.

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 500 

ppm, or sulfates <1500 ppm, as a 

minimum, consider

(1) Examination of the exposed portions 

of the below-grade concrete, when 

excavated for any reason, and 

(2) Periodic monitoring of below-grade 

water chemistry, including consideration 

of potential seasonal variations. 

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the concrete 

aging during the period of extended 

operation.

Yes, plantspecific if 

environment is 

aggressive
NUREG-1801, Rev. 1 III A1-6 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A1 Group 1 Structures (BWR Reactor Bldg., PWR Shield Bldg., Control Rm./Bldg.)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A1-5

(T-07)

III.A1.1-g Concrete:

Below-grade 

exterior; 

foundation

Reinforced 

concrete

Ground 

water/soil

Increase in 

porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling)/ 

aggressive 

chemical attack

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 500 

ppm, or sulfates <1500 ppm, as a 

minimum, consider

(1) Examination of the exposed portions 

of the below-grade concrete, when 

excavated for any reason, and 

(2) Periodic monitoring of below-grade 

water chemistry, including consideration 

of potential seasonal variations. 

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the concrete 

aging during the period of extended 

operation.

Yes, plantspecific if 

environment is 

aggressive
September 2005 III A1-7 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A1 Group 1 Structures (BWR Reactor Bldg., PWR Shield Bldg., Control Rm./Bldg.)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A1-6

(T-01)

III.A1.1-a Concrete:

Exterior 

above- and 

below-grade; 

foundation

Reinforced 

concrete

Air – outdoor Loss of material 

(spalling, scaling) 

and cracking/ 

freeze-thaw

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible Areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of loss of 

material (spalling, scaling) and cracking 

due to freeze-thaw.

Inaccessible Areas:

Evaluation is needed for plants that are 

located in moderate to severe 

weathering conditions (weathering index 

> 100 day-inch/yr) (NUREG-1557). 

Documented evidence to confirm that 

existing concrete has air content of 3% 

to 6% and water-to-cement ratio of 0.35-

0.45, and subsequent inspections did 

not exhibit degradation related to freezethaw, should be considered a part of the 

evaluation.

The weathering index for the continental 

US is shown in ASTM C33-90, Fig.1.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or for

inaccessible 

areas of plants 

located in 

moderate to 

severe 

weathering 

conditions
NUREG-1801, Rev. 1 III A1-8 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A1 Group 1 Structures (BWR Reactor Bldg., PWR Shield Bldg., Control Rm./Bldg.)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A1-7

(T-02)

III.A1.1-b Concrete:

Exterior 

above- and 

below-grade; 

foundation

Reinforced 

concrete

Water – flowing Increase in 

porosity and 

permeability, loss 

of strength/ 

leaching of calcium 

hydroxide

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of increase in 

porosity, and permeability due to 

leaching of calcium hydroxide.

Inaccessible Areas:

An aging management program is not 

necessary, even if reinforced concrete is 

exposed to flowing water, if there is 

documented evidence that confirms the 

in-place concrete was constructed in 

accordance with the recommendations 

in ACI 201.2R-77.

Yes, if 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas
September 2005 III A1-9 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A1 Group 1 Structures (BWR Reactor Bldg., PWR Shield Bldg., Control Rm./Bldg.)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A1-8

(T-09)

III.A1.1-i Concrete:

Foundation; 

subfoundation

Reinforced 

concrete;

Porous 

concrete

Water – flowing 

under foundation

Reduction in 

foundation 

strength, cracking, 

differential 

settlement/ erosion 

of porous concrete 

subfoundation

Chapter XI.S6, “Structures Monitoring 

Program”

Erosion of cement from porous concrete 

subfoundations beneath containment 

basemats is described in NRC IN 97-11. 

NRC IN 98-26 proposes Maintenance 

Rule Structures Monitoring for managing 

this aging effect, if applicable. If a dewatering system is relied upon for 

control of erosion of cement from porous 

concrete subfoundations, the licensee is 

to ensure proper functioning of the dewatering system through the period of 

extended operation.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon

III.A1-9

(T-04)

III.A1.1-d Concrete:

Interior and 

above-grade 

exterior

Reinforced 

concrete

Air – indoor 

uncontrolled or 

air – outdoor

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling)/ corrosion 

of embedded steel

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of cracking, 

loss of bond, and loss of material 

(spalling, scaling) due to corrosion of 

embedded steel.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program
NUREG-1801, Rev. 1 III A1-10 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A1 Group 1 Structures (BWR Reactor Bldg., PWR Shield Bldg., Control Rm./Bldg.)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A1-10

(T-06)

III.A1.1-f Concrete:

Interior and 

above-grade 

exterior

Reinforced 

concrete

Air – indoor 

uncontrolled or 

air – outdoor

Increase in 

porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling)/ 

aggressive 

chemical attack

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible Areas:

Inspections performed in accordance 

with Structures Monitoring Program will 

indicate the presence of increase in 

porosity and permeability, cracking, or 

loss of material (spalling, scaling) due to 

aggressive chemical attack.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.A1-11

(T-12)

III.A1.3-a Masonry walls:

All

Concrete 

block

Air – indoor 

uncontrolled or 

air – outdoor

Cracking due to 

restraint shrinkage, 

creep, and 

aggressive 

environment

Chapter XI.S5, “Masonry Wall Program” No

III.A1-12

(T-11)

III.A1.2-a Steel 

components:

All structural 

steel

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of material/ 

corrosion

Chapter XI.S6, “Structures Monitoring 

Program”

If protective coatings are relied upon to 

manage the effects of aging, the 

structures monitoring program is to 

include provisions to address protective 

coating monitoring and maintenance.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program
September 2005 III A2-1 NUREG-1801, Rev. 1

A2. GROUP 2 STRUCTURES (BWR REACTOR BLDG. WITH STEEL SUPERSTRUCTURE)

Systems, Structures, and Components

This section addresses the elements of boiling water reactor (BWR) reactor building with steel 

superstructure. For this group, the applicable structural elements are identified: concrete, steel, 

and masonry walls. The aging management review is presented for each applicable 

combination of structural element and aging effect.

System Interfaces

Physical interfaces exist with any system or component that either penetrates the structure wall 

or is supported by the structure wall, floor, and roof. The direct interface is through the system 

or component supports that are anchored to the structure. Structures also protect housed 

systems and components from internal and external design basis events. In the case of tanks, 

there is a functional interface with the associated system. Water-control structures are integral 

parts of the systems that provide plant cooling water and residual heat removal. 
NUREG-1801, Rev. 1 III A2-2 September 2005 

III STRUCTURES AND COMPONENT SUPPORTS

A2 Group 2 Structures (BWR Reactor Bldg. with Steel Superstructure)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A2-1

(T-10)

III.A2.1-j Concrete:

All

Reinforced 

concrete

Air – indoor 

uncontrolled

Reduction of 

strength and 

modulus/ 

elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging management 

program

For any concrete elements that exceed 

specified temperature limits, further 

evaluations are warranted. Appendix A 

of ACI 349-85 specifies the concrete 

temperature limits for normal operation 

or any other long-term period. The 

temperatures shall not exceed 150°F 

except for local areas which are allowed 

to have increased temperatures not to 

exceed 200°F.

Yes, if 

temperature 

limits are 

exceeded
September 2005 III A2-3 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A2 Group 2 Structures (BWR Reactor Bldg. with Steel Superstructure)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A2-2

(T-03)

III.A2.1-c Concrete:

All

Reinforced 

concrete

Any Cracking due to 

expansion/ 

reaction with 

aggregates

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible Areas:

Inspections/evaluations performed in 

accordance with the Structures 

Monitoring Program will indicate the 

presence of expansion and cracking 

due to reaction with aggregates.

Inaccessible Areas:

As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates performed 

in accordance with ASTM C295-54 or 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregatereinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with ACI 

201.2R. Therefore, if these conditions 

are satisfied, aging management is not 

necessary.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas.
NUREG-1801, Rev. 1 III A2-4 September 2005 

III STRUCTURES AND COMPONENT SUPPORTS

A2 Group 2 Structures (BWR Reactor Bldg. with Steel Superstructure)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A2-3

(T-08)

III.A2.1-h Concrete:

All

Reinforced 

concrete

Soil Cracks and 

distortion due to 

increased stress 

levels from 

settlement

Chapter XI.S6, “Structures Monitoring 

Program”

If a de-watering system is relied upon 

for control of settlement, then the 

licensee is to ensure proper functioning 

of the de-watering system through the 

period of extended operation. 

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon
September 2005 III A2-5 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A2 Group 2 Structures (BWR Reactor Bldg. with Steel Superstructure)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A2-4

(T-05)

III.A2.1-e Concrete:

Below-grade 

exterior; 

foundation

Reinforced 

concrete

Ground 

water/soil

Cracking, loss of 

bond, and loss of 

material 

(spalling, 

scaling)/ 

corrosion of 

embedded steel

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible Areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the cracking, loss of bond, 

or loss of material (spalling, scaling) 

due to corrosion of embedded steel.

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 

500 ppm, or sulfates <1500 ppm, as a 

minimum, consider

(1) Examination of the exposed portions 

of the below-grade concrete, when 

excavated for any reason, and 

(2) Periodic monitoring of below-grade 

water chemistry, including consideration 

of potential seasonal variations. 

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the 

concrete aging during the period of 

extended operation.

Yes, plantspecific if 

environment is 

aggressive
NUREG-1801, Rev. 1 III A2-6 September 2005 

III STRUCTURES AND COMPONENT SUPPORTS

A2 Group 2 Structures (BWR Reactor Bldg. with Steel Superstructure)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A2-5

(T-07)

III.A2.1-g Concrete:

Below-grade 

exterior; 

foundation

Reinforced 

concrete

Ground 

water/soil

Increase in 

porosity and 

permeability, 

cracking, loss of 

material 

(spalling, 

scaling)/ 

aggressive 

chemical attack

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 

500 ppm, or sulfates <1500 ppm, as a 

minimum, consider

(1) Examination of the exposed portions 

of the below-grade concrete, when 

excavated for any reason, and 

(2) Periodic monitoring of below-grade 

water chemistry, including consideration 

of potential seasonal variations. 

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the 

concrete aging during the period of 

extended operation.

Yes, plantspecific if 

environment is 

aggressive
September 2005 III A2-7 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A2 Group 2 Structures (BWR Reactor Bldg. with Steel Superstructure)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A2-6

(T-01)

III.A2.1-a Concrete:

Exterior 

above- and 

below-grade; 

foundation

Reinforced 

concrete

Air – outdoor Loss of material 

(spalling, scaling) 

and cracking/ 

freeze-thaw

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible Areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of loss of 

material (spalling, scaling) and cracking 

due to freeze-thaw.

Inaccessible Areas:

Evaluation is needed for plants that are 

located in moderate to severe

weathering conditions (weathering 

index > 100 day-inch/yr) (NUREG1557). Documented evidence to confirm 

that existing concrete has air content of 

3% to 6% and water-to-cement ratio of 

0.35-0.45, and subsequent inspections 

did not exhibit degradation relat ed to 

freeze-thaw, should be considered a 

part of the evaluation.

The weathering index for the 

continental US is shown in ASTM C33-

90, Fig.1.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or for 

inaccessible 

areas of 

plants located 

in moderate to 

severe 

weathering 

conditions
NUREG-1801, Rev. 1 III A2-8 September 2005 

III STRUCTURES AND COMPONENT SUPPORTS

A2 Group 2 Structures (BWR Reactor Bldg. with Steel Superstructure)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A2-7

(T-02)

III.A2.1-b Concrete:

Exterior 

above- and 

below-grade; 

foundation

Reinforced 

concrete

Water – flowing Increase in 

porosity and 

permeability, loss 

of strength/ 

leaching of 

calcium 

hydroxide

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of increase in 

porosity, and permeability due to 

leaching of calcium hydroxide.

Inaccessible Areas:

An aging management program is not 

necessary, even if reinforced concrete 

is exposed to flowing water, if there is 

documented evidence that confirms the 

in-place concrete was constructed in 

accordance with the recommendations 

in ACI 201.2R-77.

Yes, if 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas
September 2005 III A2-9 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A2 Group 2 Structures (BWR Reactor Bldg. with Steel Superstructure)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A2-8

(T-09)

III.A2.1-i Concrete:

Foundation; 

subfoundatio

n

Reinforced 

concrete;

Porous 

concrete

Water – flowing 

under 

foundation

Reduction in 

foundation 

strength, 

cracking, 

differential 

settlement/ 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Monitoring 

Program”

Erosion of cement from porous 

concrete subfoundations beneath 

containment basemats is described in 

NRC IN 97-11. NRC IN 98-26 proposes 

Maintenance Rule Structures 

Monitoring for managing this aging 

effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous concrete 

subfoundations, the licensee is to 

ensure proper functioning of the dewatering system through the period of 

extended operation.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon

III.A2-9

(T-04)

III.A2.1-d Concrete:

Interior and 

above-grade 

exterior

Reinforced 

concrete

Air – indoor 

uncontrolled or 

air – outdoor

Cracking, loss of 

bond, and loss of 

material 

(spalling, 

scaling)/ 

corrosion of 

embedded steel

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of cracking, 

loss of bond, and loss of material 

(spalling, scaling) due to corrosion of 

embedded steel.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program
NUREG-1801, Rev. 1 III A2-10 September 2005 

III STRUCTURES AND COMPONENT SUPPORTS

A2 Group 2 Structures (BWR Reactor Bldg. with Steel Superstructure)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A2-10

(T-06)

III.A2.1-f Concrete:

Interior and 

above-grade 

exterior

Reinforced 

concrete

Air – indoor 

uncontrolled or 

air – outdoor

Increase in 

porosity and 

permeability, 

cracking, loss of 

material 

(spalling, 

scaling)/ 

aggressive 

chemical attack

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible Areas:

Inspections performed in accordance 

with Structures Monitoring Program will 

indicate the presence of increase in 

porosity and permeability, cracking, or 

loss of material (spalling, scaling) due 

to aggressive chemical attack.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.A2-11

(T-12)

III.A2.3-a Masonry walls:

All

Concrete 

block

Air – indoor 

uncontrolled or 

air – outdoor

Cracking due to 

restraint 

shrinkage, creep, 

and aggressive 

environment

Chapter XI.S5, “Masonry Wall Program” No

III.A2-12

(T-11)

III.A2.2-a Steel 

components:

All structural 

steel

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of material/ 

corrosion

Chapter XI.S6, “Structures Monitoring 

Program”

If protective coatings are relied upon to 

manage the effects of aging, the 

structures monitoring program is to 

include provisions to address protective 

coating monitoring and maintenance.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program
September 2005 III A3-1 NUREG-1801, Rev. 1

A3. GROUP 3 STRUCTURES (AUXILIARY BLDG., DIESEL GENERATOR BLDG.,

RADWASTE BLDG., TURBINE BLDG., SWITCHGEAR RM., YARD STRUCTURES 

SUCH AS AFW PUMPHOUSE, UTILITY/PIPING TUNNELS, SECURITY/LIGHTING 

POLES, MANHOLES, DUCT BANKS; SBO STRUCTURES SUCH AS TRANSMISSION 

TOWERS, STARTUP TOWERS CIRCUIT BREAKER FOUNDATION, ELECTRICAL 

ENCLOSURE)

Systems, Structures, and Components

This section addresses the elements of auxiliary building, diesel generator building, radwaste 

building, turbine building, switchgear room, yard structures, and station blackout (SBO)

structures. For this group, the applicable structural elements are identified: concrete, steel, and

masonry walls. The aging management review is presented for each applicable combination of 

structural element and aging effect.

System Interfaces

Physical interfaces exist with any system or component that either penetrates the structure wall 

or is supported by the structure wall, floor, and roof. The direct interface is through the system 

or component supports that are anchored to the structure. Structures also protect housed 

systems and components from internal and external design basis events. In the case of tanks, 

there is a functional interface with the associated system. Water-control structures are integral 

parts of the systems that provide plant cooling water and residual heat removal. 
NUREG-1801, Rev. 1 III A3-2 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A3 Group 3 Structures (Auxiliary Bldg., Diesel Generator Bldg., Radwaste Bldg., Turbine Bldg., Switchgear Rm., Yard Structures such as 

AFW Pumphouse, Utility/Piping Tunnels, Security/Lighting Poles, Manholes, Duct Banks; SBO Structures such as Transmission Towers, 

Startup Towers Circuit Breaker foundation, Electrical Enclosure)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A3-1

(T-10)

III.A3.1-j Concrete:

All

Reinforced 

concrete

Air – indoor 

uncontrolled

Reduction of 

strength and 

modulus/ 

elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging management 

program

For any concrete elements that exceed 

specified temperature limits, further 

evaluations are warranted. Appendix A 

of ACI 349-85 specifies the concrete 

temperature limits for normal operation 

or any other long-term period. The 

temperatures shall not exceed 150°F 

except for local areas which are 

allowed to have increased 

temperatures not to exceed 200°F.

Yes, if 

temperature 

limits are 

exceeded
September 2005 III A3-3 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A3 Group 3 Structures (Auxiliary Bldg., Diesel Generator Bldg., Radwaste Bldg., Turbine Bldg., Switchgear Rm., Yard Structures such as 

AFW Pumphouse, Utility/Piping Tunnels, Security/Lighting Poles, Manholes, Duct Banks; SBO Structures such as Transmission Towers, 

Startup Towers Circuit Breaker foundation, Electrical Enclosure)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A3-2

(T-03)

III.A3.1-c Concrete:

All

Reinforced 

concrete

Any Cracking due to 

expansion/ 

reaction with 

aggregates

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible Areas:

Inspections/evaluations performed in 

accordance with the Structures 

Monitoring Program will indicate the 

presence of expansion and cracking 

due to reaction with aggregates.

Inaccessible Areas:

As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates performed 

in accordance with ASTM C295-54 or 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregatereinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with ACI 

201.2R. Therefore, if these conditions 

are satisfied, aging management is not 

necessary.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas.
NUREG-1801, Rev. 1 III A3-4 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A3 Group 3 Structures (Auxiliary Bldg., Diesel Generator Bldg., Radwaste Bldg., Turbine Bldg., Switchgear Rm., Yard Structures such as 

AFW Pumphouse, Utility/Piping Tunnels, Security/Lighting Poles, Manholes, Duct Banks; SBO Structures such as Transmission Towers, 

Startup Towers Circuit Breaker foundation, Electrical Enclosure)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A3-3

(T-08)

III.A3.1-h Concrete:

All

Reinforced 

concrete

Soil Cracks and 

distortion due to 

increased stress 

levels from 

settlement

Chapter XI.S6, “Structures Monitoring 

Program”

If a de-watering system is relied upon 

for control of settlement, then the 

licensee is to ensure proper functioning 

of the de-watering system through the 

period of extended operation. 

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon
September 2005 III A3-5 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A3 Group 3 Structures (Auxiliary Bldg., Diesel Generator Bldg., Radwaste Bldg., Turbine Bldg., Switchgear Rm., Yard Structures such as 

AFW Pumphouse, Utility/Piping Tunnels, Security/Lighting Poles, Manholes, Duct Banks; SBO Structures such as Transmission Towers, 

Startup Towers Circuit Breaker foundation, Electrical Enclosure)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A3-4

(T-05)

III.A3.1-e Concrete:

Below-grade 

exterior; 

foundation

Reinforced 

concrete

Ground 

water/soil

Cracking, loss of 

bond, and loss of 

material 

(spalling, 

scaling)/ 

corrosion of 

embedded steel

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible Areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the cracking, loss of bond, 

or loss of material (spalling, scaling) 

due to corrosion of embedded steel.

Inaccessible Areas:

For plants with non-aggressive ground

water/soil; i.e., pH > 5.5, chlorides < 

500 ppm, or sulfates <1500 ppm, as a 

minimum, consider

(1) Examination of the exposed 

portions of the below-grade concrete, 

when excavated for any reason, and 

(2) Periodic monitoring of below-grade 

water chemistry, including 

consideration of potential seasonal 

variations. 

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the 

concrete aging during the period of 

extended operation.

Yes, plantspecific if 

environment is 

aggressive
NUREG-1801, Rev. 1 III A3-6 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A3 Group 3 Structures (Auxiliary Bldg., Diesel Generator Bldg., Radwaste Bldg., Turbine Bldg., Switchgear Rm., Yard Structures such as 

AFW Pumphouse, Utility/Piping Tunnels, Security/Lighting Poles, Manholes, Duct Banks; SBO Structures such as Transmission Towers, 

Startup Towers Circuit Breaker foundation, Electrical Enclosure)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A3-5

(T-07)

III.A3.1-g Concrete:

Below-grade 

exterior; 

foundation

Reinforced 

concrete

Ground 

water/soil

Increase in 

porosity and 

permeability, 

cracking, loss of 

material 

(spalling, 

scaling)/ 

aggressive 

chemical attack

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 

500 ppm, or sulfates <1500 ppm, as a 

minimum, consider

(1) Examination of the exposed 

portions of the below-grade concrete, 

when excavated for any reason, and 

(2) Periodic monitoring of below-grade 

water chemistry, including 

consideration of potential seasonal 

variations. 

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the 

concrete aging during the period of 

extended operation.

Yes, plantspecific if 

environment is 

aggressive
September 2005 III A3-7 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A3 Group 3 Structures (Auxiliary Bldg., Diesel Generator Bldg., Radwaste Bldg., Turbine Bldg., Switchgear Rm., Yard Structures such as 

AFW Pumphouse, Utility/Piping Tunnels, Security/Lighting Poles, Manholes, Duct Banks; SBO Structures such as Transmission Towers, 

Startup Towers Circuit Breaker foundation, Electrical Enclosure)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A3-6

(T-01)

III.A3.1-a Concrete:

Exterior 

above- and 

below-grade; 

foundation

Reinforced 

concrete

Air – outdoor Loss of material 

(spalling, scaling) 

and cracking/ 

freeze-thaw

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible Areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of loss of 

material (spalling, scaling) and cracking 

due to freeze-thaw.

Inaccessible Areas:

Evaluation is needed for plants that are 

located in moderate to severe 

weathering conditions (weathering 

index > 100 day-inch/yr) (NUREG1557). Documented evidence to 

confirm that existing concrete has air 

content of 3% to 6% and water-tocement ratio of 0.35-0.45, and 

subsequent inspections did not exhibit 

degradation related to freeze-thaw, 

should be considered a part of the 

evaluation.

The weathering index for the 

continental US is shown in ASTM C33-

90, Fig.1.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or for 

inaccessible 

areas of 

plants located 

in moderate to 

severe 

weathering 

conditions
NUREG-1801, Rev. 1 III A3-8 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A3 Group 3 Structures (Auxiliary Bldg., Diesel Generator Bldg., Radwaste Bldg., Turbine Bldg., Switchgear Rm., Yard Structures such as 

AFW Pumphouse, Utility/Piping Tunnels, Security/Lighting Poles, Manholes, Duct Banks; SBO Structures such as Transmission Towers, 

Startup Towers Circuit Breaker foundation, Electrical Enclosure)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A3-7

(T-02)

III.A3.1-b Concrete:

Exterior 

above- and 

below-grade; 

foundation

Reinforced 

concrete

Water – flowing Increase in 

porosity and 

permeability, loss 

of strength/ 

leaching of 

calcium 

hydroxide

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of increase in 

porosity, and permeability due to 

leaching of calcium hydroxide.

Inaccessible Areas:

An aging management program is not 

necessary, even if reinforced concrete 

is exposed to flowing water, if there is 

documented evidence that confirms the 

in-place concrete was constructed in 

accordance with the recommendations 

in ACI 201.2R-77.

Yes, if 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas
September 2005 III A3-9 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A3 Group 3 Structures (Auxiliary Bldg., Diesel Generator Bldg., Radwaste Bldg., Turbine Bldg., Switchgear Rm., Yard Structures such as 

AFW Pumphouse, Utility/Piping Tunnels, Security/Lighting Poles, Manholes, Duct Banks; SBO Structures such as Transmission Towers, 

Startup Towers Circuit Breaker foundation, Electrical Enclosure)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A3-8

(T-09)

III.A3.1-i Concrete:

Foundation; 

subfoundation

Reinforced 

concrete;

Porous 

concrete

Water – flowing 

under 

foundation

Reduction in 

foundation 

strength, 

cracking, 

differential 

settlement/ 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Monitoring 

Program”

Erosion of cement from porous 

concrete subfoundations beneath 

containment basemats is described in 

NRC IN 97-11. NRC IN 98-26 proposes 

Maintenance Rule Structures 

Monitoring for managing this aging 

effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous 

concrete subfoundations, the licensee 

is to ensure proper functioning of the 

de-watering system through the period 

of extended operation.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon

III.A3-9

(T-04)

III.A3.1-d Concrete:

Interior and 

above-grade 

exterior

Reinforced 

concrete

Air – indoor 

uncontrolled or 

air – outdoor

Cracking, loss of 

bond, and loss of 

material 

(spalling, 

scaling)/ 

corrosion of 

embedded steel

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of cracking, 

loss of bond, and loss of material 

(spalling, scaling) due to corrosion of 

embedded steel.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program
NUREG-1801, Rev. 1 III A3-10 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A3 Group 3 Structures (Auxiliary Bldg., Diesel Generator Bldg., Radwaste Bldg., Turbine Bldg., Switchgear Rm., Yard Structures such as 

AFW Pumphouse, Utility/Piping Tunnels, Security/Lighting Poles, Manholes, Duct Banks; SBO Structures such as Transmission Towers, 

Startup Towers Circuit Breaker foundation, Electrical Enclosure)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A3-10

(T-06)

III.A3.1-f Concrete:

Interior and 

above-grade 

exterior

Reinforced 

concrete

Air – indoor 

uncontrolled or 

air – outdoor

Increase in 

porosity and 

permeability, 

cracking, loss of 

material 

(spalling, 

scaling)/ 

aggressive 

chemical attack

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible Areas:

Inspections performed in accordance 

with Structures Monitoring Program will 

indicate the presence of increase in 

porosity and permeability, cracking, or 

loss of material (spalling, scaling) due 

to aggressive chemical attack.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.A3-11

(T-12)

III.A3.3-a Masonry walls:

All

Concrete 

block

Air – indoor 

uncontrolled or 

air – outdoor

Cracking due to 

restraint 

shrinkage, creep, 

and aggressive 

environment

Chapter XI.S5, “Masonry Wall 

Program”

No

III.A3-12

(T-11)

III.A3.2-a Steel 

components:

All structural 

steel

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of material/ 

corrosion

Chapter XI.S6, “Structures Monitoring 

Program”

If protective coatings are relied upon to 

manage the effects of aging, the 

structures monitoring program is to 

include provisions to address protective 

coating monitoring and maintenance.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program
September 2005 III A4-1 NUREG-1801, Rev. 1

A4. GROUP 4 STRUCTURES (CONTAINMENT INTERNAL STRUCTURES, EXCLUDING 

REFUELING CANAL)

Systems, Structures, and Components

This section addresses the elements of containment internal structures, excluding refueling 

canal. For this group, the applicable structural elements are identified: concrete and steel 

elements. The aging management review is presented for each applicable combination of 

structural element and aging effect.

System Interfaces

Physical interfaces exist with any system or component that either penetrates the structure wall 

or is supported by the structure wall, floor, and roof. The direct interface is through the system 

or component supports that are anchored to the structure. Structures also protect housed 

systems and components from internal and external design basis events. In the case of tanks, 

there is a functional interface with the associated system. Water-control structures are integral 

parts of the systems that provide plant cooling water and residual heat removal. 
NUREG-1801, Rev. 1 III A4-2 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A4 Group 4 Structures (Containment Internal Structures, excluding Refueling Canal)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A4-1

(T-10)

III.A4.1-c Conc rete:

All

Reinforced 

concrete

Air – indoor 

uncontrolled

Reduction of 

strength and 

modulus/ 

elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging management 

program

For any concrete elements that exceed 

specified temperature limits, further 

evaluations are warranted. Appendix A 

of ACI 349-85 specifies the concrete 

temperature limits for normal operation 

or any other long-term period. The 

temperatures shall not exceed 150°F 

except for local areas which are allowed 

to have increased temperatures not to 

exceed 200°F.

Yes, if 

temperature 

limits are 

exceeded
September 2005 III A4-3 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A4 Group 4 Structures (Containment Internal Structures, excluding Refueling Canal)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A4-2

(T-03)

III.A4.1-b Concrete:

All

Reinforced 

concrete

Any Cracking due to 

expansion/ 

reaction with 

aggregates

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible Areas:

Inspections/evaluations performed in 

accordance with the Structures 

Monitoring Program will indicate the 

presence of expansion and cracking due 

to reaction with aggregates.

Inaccessible Areas:

As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates performed 

in accordance with ASTM C295-54 or 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregatereinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with ACI 

201.2R. Therefore, if these conditions 

are satisfied, aging management is not 

necessary.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas.
NUREG-1801, Rev. 1 III A4-4 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A4 Group 4 Structures (Containment Internal Structures, excluding Refueling Canal)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A4-3

(T-04)

III.A4.1-d Concrete:

Interior and 

above-grade 

exterior

Reinforced 

concrete

Air – indoor 

uncontrolled or 

air – outdoor

Cracking, loss of 

bond, and loss 

of material 

(spalling, 

scaling)/ 

corrosion of 

embedded steel

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of cracking, 

loss of bond, and loss of material 

(spalling, scaling) due to corrosion of 

embedded steel.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.A4-4

(T-06)

III.A4.1-a Concrete:

Interior and 

above-grade 

exterior

Reinforced 

concrete

Air – indoor 

uncontrolled or 

air – outdoor

Increase in 

porosity and 

permeability, 

cracking, loss of 

material 

(spalling, 

scaling)/ 

aggressive 

chemical attack

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible Areas:

Inspections performed in accordance 

with Structures Monitoring Program will 

indicate the presence of increase in 

porosity and permeability, cracking, or 

loss of material (spalling, scaling) due to 

aggressive chemical attack.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.A4-5

(T-11)

III.A4.2-a Steel 

components:

All structural 

steel

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of material/ 

corrosion

Chapter XI.S6, “Structures Monitoring 

Program”

If protective coatings are relied upon to 

manage the effects of aging, the 

structures monitoring program is to 

include provisions to address protective 

coating monitoring and maintenance.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program
September 2005 III A4-5 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A4 Group 4 Structures (Containment Internal Structures, excluding Refueling Canal)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A4-6

(T-13)

III.A4.2-b Steel 

components:

Radial beam 

seats in 

BWR 

drywell;

RPV support 

shoes for 

PWR with 

nozzle 

supports;

Steam 

generator 

supports

Lubrite® Air – indoor 

uncontrolled

Lock-up/ wear Chapter XI.S3, “ASME Section XI, 

Subsection IWF” or

Chapter XI.S6, “Structures Monitoring 

Program”

Yes, if not 

within the 

scope of 

Section XI, 

IWF or 

structures 

monitoring 

program
NUREG-1801, Rev. 1 III A4-6 September 2005

This Page Intentionally Left Blank
September 2005 III A5-1 NUREG-1801, Rev. 1

A5. GROUP 5 STRUCTURES (FUEL STORAGE FACILITY, REFUELING CANAL)

Systems, Structures, and Components

This section addresses the elements of the fuel storage facility and refueling canal. For this 

group, the applicable structural elements are identified: concrete, steel, and masonry walls. The 

aging management review is presented for each applicable combination of structural element 

and aging effect.

System Interfaces

Physical interfaces exist with any system or component that either penetrates the structure wall 

or is supported by the structure wall, floor and roof. The direct interface is through the system or 

component supports that are anchored to the structure. Structures also protect housed systems 

and components from internal and external design basis events. In the case of tanks, there is a 

functional interface with the associated system. Water-control structures are integral parts of the 

systems that provide plant cooling water and residual heat removal. 
NUREG-1801, Rev. 1 III A5-2 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A5 Group 5 Structures (Fuel Storage Facility, Refueling Canal)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A5-1

(T-10)

III.A5.1-j Concrete:

All

Reinforced 

concrete

Air – indoor 

uncontrolled

Reduction of 

strength and 

modulus/ 

elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging management 

program

For any concrete elements that exceed 

specified temperature limits, further 

evaluations are warranted. Appendix A 

of ACI 349-85 specifies the concrete 

temperature limits for normal operation 

or any other long-term period. The 

temperatures shall not exceed 150°F 

except for local areas which are 

allowed to have increased 

temperatures not to exceed 200°F.

Yes, if 

temperature 

limits are 

exceeded
September 2005 III A5-3 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A5 Group 5 Structures (Fuel Storage Facility, Refueling Canal)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A5-2

(T-03)

III.A5.1-c Concrete:

All

Reinforced 

concrete

Any Cracking due to 

expansion/ 

reaction with 

aggregates

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible Areas:

Inspections/evaluations performed in 

accordance with the Structures 

Monitoring Program will indicate the 

presence of expansion and cracking 

due to reaction with aggregates.

Inaccessible Areas:

As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates performed 

in accordance with ASTM C295-54 or 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregatereinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with ACI 

201.2R. Therefore, if these conditions 

are satisfied, aging management is not 

necessary.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas.
NUREG-1801, Rev. 1 III A5-4 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A5 Group 5 Structures (Fuel Storage Facility, Refueling Canal)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A5-3

(T-08)

III.A5.1-h Concrete:

All

Reinforced 

concrete

Soil Cracks and 

distortion due to 

increased stress 

levels from 

settlement

Chapter XI.S6, “Structures Monitoring 

Program”

If a de-watering system is relied upon 

for control of settlement, then the 

licensee is to ensure proper functioning 

of the de-watering system through the 

period of extended operation. 

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon
September 2005 III A5-5 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A5 Group 5 Structures (Fuel Storage Facility, Refueling Canal)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A5-4

(T-05)

III.A5.1-e Concrete:

Below-grade 

exterior; 

foundation

Reinforced 

concrete

Ground 

water/soil

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling)/ 

corrosion of 

embedded steel

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible Areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the cracking, loss of bond, 

or loss of material (spalling, scaling) 

due to corrosion of embedded steel.

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 

500 ppm, or sulfates <1500 ppm, as a 

minimum, consider

(1) Examination of the exposed portions 

of the below-grade concrete, when 

excavated for any reason, and 

(2) Periodic monitoring of below-grade 

water chemistry, including 

consideration of potential seasonal 

variations. 

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the 

concrete aging during the period of 

extended operation.

Yes, plantspecific if 

environment is 

aggressive
NUREG-1801, Rev. 1 III A5-6 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A5 Group 5 Structures (Fuel Storage Facility, Refueling Canal)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A5-5

(T-07)

III.A5.1-g Concrete:

Below-grade 

exterior; 

foundation

Reinforced 

concrete

Ground 

water/soil

Increase in 

porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling)/ 

aggressive 

chemical attack

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 

500 ppm, or sulfates <1500 ppm, as a 

minimum, consider

(1) Examination of the exposed portions 

of the below-grade concrete, when 

excavated for any reason, and 

(2) Periodic monitoring of below-grade 

water chemistry, including 

consideration of potential seasonal 

variations. 

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the 

concrete aging during the period of 

extended operation.

Yes, plantspecific if 

environment is 

aggressive
September 2005 III A5-7 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A5 Group 5 Structures (Fuel Storage Facility, Refueling Canal)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A5-6

(T-01)

III.A5.1-a Concrete:

Exterior 

above- and 

below-grade; 

foundation

Reinforced 

concrete

Air – outdoor Loss of material 

(spalling, scaling) 

and cracking/ 

freeze-thaw

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible Areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of loss of 

material (spalling, scaling) and cracking 

due to freeze-thaw.

Inaccessible Areas:

Evaluation is needed for plants that are 

located in moderate to severe 

weathering conditions (weathering 

index > 100 day-inch/yr) (NUREG1557). Documented evidence to 

confirm that existing concrete has air 

content of 3% to 6% and water-tocement ratio of 0.35-0.45, and 

subsequent inspections did not exhibit 

degradation related to freeze-thaw, 

should be considered a part of the 

evaluation.

The weathering index for the 

continental US is shown in ASTM C33-

90, Fig.1.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or for 

inaccessible 

areas of 

plants located 

in moderate to 

severe 

weathering 

conditions
NUREG-1801, Rev. 1 III A5-8 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A5 Group 5 Structures (Fuel Storage Facility, Refueling Canal)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A5-7

(T-02)

III.A5.1-b Concrete:

Exterior 

above- and 

below-grade; 

foundation

Reinforced 

concrete

Water – flowing Increase in 

porosity and 

permeability, loss 

of strength/ 

leaching of 

calcium 

hydroxide

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of increase in 

porosity, and permeability due to 

leaching of calcium hydroxide.

Inaccessible Areas:

An aging management program is not 

necessary, even if reinforced concrete 

is exposed to flowing water, if there is 

documented evidence that confirms the 

in-place concrete was constructed in 

accordance with the recommendations 

in ACI 201.2R-77.

Yes, if 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas
September 2005 III A5-9 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A5 Group 5 Structures (Fuel Storage Facility, Refueling Canal)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A5-8

(T-09)

III.A5.1-i Concrete:

Foundation; 

subfoundatio

n

Reinforced 

concrete;

Porous 

concrete

Water – flowing 

under 

foundation

Reduction in 

foundation 

strength, 

cracking, 

differential 

settlement/ 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Monitoring 

Program”

Erosion of cement from porous 

concrete subfoundations beneath 

containment basemats is described in 

NRC IN 97-11. NRC IN 98-26 proposes 

Maintenance Rule Structures 

Monitoring for managing this aging 

effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous concrete 

subfoundations, the licensee is to 

ensure proper functioning of the dewatering system through the period of 

extended operation.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon

III.A5-9

(T-04)

III.A5.1-d Concrete:

Interior and 

above-grade 

exterior

Reinforced 

concrete

Air – indoor 

uncontrolled or 

air – outdoor

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling)/ 

corrosion of 

embedded steel

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of cracking, 

loss of bond, and loss of material 

(spalling, scaling) due to corrosion of 

embedded steel.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program
NUREG-1801, Rev. 1 III A5-10 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A5 Group 5 Structures (Fuel Storage Facility, Refueling Canal)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A5-10

(T-06)

III.A5.1-f Concrete:

Interior and 

above-grade 

exterior

Reinforced 

concrete

Air – indoor 

uncontrolled or 

air – outdoor

Increase in 

porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling)/ 

aggressive 

chemical attack

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible Areas:

Inspections performed in accordance 

with Structures Monitoring Program will 

indicate the presence of increase in 

porosity and permeability, cracking, or 

loss of material (spalling, scaling) due 

to aggressive chemical attack.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.A5-11

(T-12)

III.A5.3-a Masonry walls:

All

Concrete 

block

Air – indoor 

uncontrolled or 

air – outdoor

Cracking due to 

restraint 

shrinkage, creep, 

and aggressive 

environment

Chapter XI.S5, “Masonry Wall Program” No

III.A5-12

(T-11)

III.A5.2-a Steel 

components:

All structural 

steel

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of material/ 

corrosion

Chapter XI.S6, “Structures Monitoring 

Program”

If protective coatings are relied upon to 

manage the effects of aging, the 

structures monitoring program is to 

include provisions to address protective 

coating monitoring and maintenance.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.A5-13

(T-14)

III.A5.2-b Steel 

components:

Fuel pool 

liner

Stainless 

steel

Treated water 

or treated 

borated water

Cracking/ stress 

corrosion 

cracking

Loss of 

material/pitting 

and crevice 

corrosion

Chapter XI.M2, "Water Chemistry" and,

Monitoring of the spent fuel pool water 

level in accordance with technical 

specifications and leakage from the 

leak chase channels.

No
September 2005 III A6-1 NUREG-1801, Rev. 1

A6. GROUP 6 STRUCTURES (WATER-CONTROL STRUCTURES)

Systems, Structures, and Components

This section addresses the elements of water-control structures. For this group, the applicable 

structural elements are identified: concrete, steel, masonry walls, and earthen water-control 

structures. The aging management review is presented for each applicable combination of 

structural element and aging effect.

System Interfaces

Physical interfaces exist with any system or component that either penetrates the structure wall 

or is supported by the structure wall, floor, and roof. The direct interface is through the system 

or component supports that are anchored to the structure. Structures also protect housed 

systems and components from internal and external design basis events. In the case of tanks, 

there is a functional interface with the associated system. Water-control structures are integral 

parts of the systems that provide plant cooling water and residual heat removal. 
NUREG-1801, Rev. 1 III A6-2 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A6 Group 6 Structures (Water-Control Structures)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

III.A6-1

(T-18)

III.A6.1-d Concrete:

All

Reinforced 

concrete

Air – indoor 

uncontrolled or 

air – outdoor

Cracking, loss of 

bond, and loss of 

material 

(spalling, 

scaling)/ 

corrosion of 

embedded steel

Chapter XI.S7, “Regulatory Guide 

1.127, Inspection of Water-Control 

Structures Associated with Nuclear 

Power Plants” or the FERC / US Army 

Corp of Engineers dam inspections 

and maintenance programs.

Accessible areas:

As described in NUREG-1557, 

corrosion of exterior above-grade and 

interior embedded steel is not 

significant if the steel is not exposed to 

an aggressive environment (concrete 

pH <11.5 or chlorides >500 ppm). If 

such steel is exposed to an aggressive 

environment, corrosion is not 

significant if the concrete in which the 

steel is embedded has a low water-tocement ratio (0.35-0.45), adequate air 

entrainment (3-6%), low permeability, 

and is designed in accordance with 

ACI 318-63 or ACI 349-85. Therefore, 

if these conditions are satisfied, aging 

management is not necessary.

Inaccessible areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 

500 ppm, or sulfates <1500 ppm, as a 

minimum, consider (1) Examination of 

the exposed portions of the below 

grade concrete, when excavated for 

any reason, and

Yes, plantspecific if 

environment 

is aggressive
September 2005 III A6-3 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A6 Group 6 Structures (Water-Control Structures)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

(2) Periodic monitoring of below-grade 

water chemistry, including 

consideration of potential seasonal 

variations.

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the 

concrete aging during the period of 

extended operation.
NUREG-1801, Rev. 1 III A6-4 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A6 Group 6 Structures (Water-Control Structures)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

III.A6-2

(T-17)

III.A6.1-c Concrete:

All

Reinforced 

concrete

Any Cracking due to 

expansion/ 

reaction with 

aggregates

Chapter XI.S7, “Regulatory Guide 

1.127, Inspection of Water-Control 

Structures Associated with Nuclear 

Power Plants” or the FERC / US Army 

Corp of Engineers dam inspections 

and maintenance programs.

Accessible Areas:

Inspections/evaluations performed in 

accordance with “Regulatory Guide 

1.127, Inspection of Water-Control 

Structures Associated with Nuclear 

Power Plants” or the FERC / US Army 

Corp of Engineers dam inspections 

and maintenance programs will 

indicate the presence of expansion 

and cracking due to reaction with 

aggregates.

Inaccessible areas:

As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates performed 

in accordance with ASTM C295-54 or 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregatereinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with ACI 

201.2R. Therefore, if these conditions 

are satisfied, aging management is not 

necessary.

Yes, if 

concrete was 

not 

constructed 

as stated for 

inaccessible 

areas
September 2005 III A6-5 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A6 Group 6 Structures (Water-Control Structures)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

III.A6-3

(T-19)

III.A6.1-e Concrete:

All

Reinforced 

concrete

Ground 

water/soil

Increase in 

porosity and 

permeability, 

cracking, loss of 

material 

(spalling, 

scaling)/ 

aggressive 

chemical attack

Chapter XI.S7, “Regulatory Guide 

1.127, Inspection of Water-Control 

Structures Associated with Nuclear 

Power Plants” or the FERC / US Army 

Corp of Engineers dam inspections 

and maintenance programs.

Accessible Areas:

Inspections performed in accordance 

with “Regulatory Guide 1.127, 

Inspection of Water-Control Structures 

Associated with Nuclear Power Plants” 

or the FERC / US Army Corp of 

Engineers dam inspections and 

maintenance programs will indicate the 

presence of increase in porosity and 

permeability, cracking, or loss of 

material (spalling, scaling) due to 

aggressive chemical attack.

Inaccessible areas:

For plants with non-aggressive ground 

water/soil; i.e. pH > 5.5, chlorides < 

500 ppm, or sulfates <1500 ppm, as a 

minimum, consider: 

(1) Examination of the exposed

portions of the below grade concrete, 

when excavated for any reason, and

(2) Periodic monitoring of below-grade 

water chemistry, including 

consideration of potential seasonal 

variations.

Yes, plantspecific if 

environment 

is aggressive
NUREG-1801, Rev. 1 III A6-6 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A6 Group 6 Structures (Water-Control Structures)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the 

concrete aging during the period of 

extended operation.
September 2005 III A6-7 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A6 Group 6 Structures (Water-Control Structures)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

III.A6-4

(T-08)

III.A6.1-f Concrete:

All

Reinforced 

concrete

Soil Cracks and 

distortion due to 

increased stress 

levels from 

settlement

Chapter XI.S6, “Structures Monitoring 

Program”

If a de-watering system is relied upon 

for control of settlement, then the 

licensee is to ensure proper 

functioning of the de-watering system 

through the period of extended 

operation. 

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon
NUREG-1801, Rev. 1 III A6-8 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A6 Group 6 Structures (Water-Control Structures)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

III.A6-5

(T-15)

III.A6.1-a Concrete:

Exterior aboveand belowgrade; 

foundation

Reinforced 

concrete

Air – outdoor Loss of material 

(spalling, 

scaling) and 

cracking/ freezethaw

Chapter XI.S7, “Regulatory Guide 

1.127, Inspection of Water-Control 

Structures Associated with Nuclear 

Power Plants” or the FERC / US Army 

Corp of Engineers dam inspections 

and maintenance programs.

Accessible Areas:

Inspections performed in accordance 

with Chapter XI.S7, “Regulatory Guide 

1.127, Inspection of Water-Control 

Structures Associated with Nuclear 

Power Plants” or the FERC / US Army 

Corp of Engineers dam inspections 

and maintenance programs will 

indicate the presence of loss of 

material (spalling, scaling) and 

cracking due to freeze-thaw.

Inaccessible Areas:

As described in NUREG-1557, freezethaw does not cause loss of material 

from reinforced concrete in 

foundations, or in above- and belowgrade exterior concrete, for plants 

located in a geographic region of 

negligible weathering conditions 

(weathering index <100 day-inch/yr). 

Loss of material from such concrete is 

not significant at plants located in 

areas in which weathering conditions 

are severe (weathering index >500 

day-inch/yr) or moderate (100-500 

day-inch/yr), provided that the concrete 

Yes, for 

inaccessible 

areas of 

plants located 

in moderate to 

severe 

weathering 

conditions
September 2005 III A6-9 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A6 Group 6 Structures (Water-Control Structures)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

mix design meets the air content 

(entrained air 3-6%) and water-tocement ratio (0.35-0.45) specified in 

ACI 318-63 or ACI 349-85. Therefore, 

if these conditions are satisfied, aging 

management is not necessary.

The weathering index is defined in 

ASTM C33-90, Table 3, Footnote E. 

Fig. 1 of ASTM C33-90 illustrates the 

various weathering index regions 

throughout the U.S.
NUREG-1801, Rev. 1 III A6-10 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A6 Group 6 Structures (Water-Control Structures)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

III.A6-6

(T-16)

III.A6.1-b Concrete:

Exterior aboveand belowgrade; 

foundation; 

interior slab

Reinforced 

concrete

Water –

flowing

Increase in 

porosity and 

permeability, 

loss of strength/ 

leaching of 

calcium 

hydroxide

Chapter XI.S7, “Regulatory Guide 

1.127, Inspection of Water-Control 

Structures Associated with Nuclear 

Power Plants” or the FERC / US Army 

Corp of Engineers dam inspections 

and maintenance programs

Accessible Areas:

Inspections performed in accordance 

with Chapter XI.S7, “Regulatory Guide 

1.127, Inspection of Water-Control 

Structures Associated with Nuclear 

Power Plants” or the FERC / US Army 

Corp of Engineers dam inspections 

and maintenance programs will 

indicate the presence of increase in 

porosity and permeability, loss of 

strength/ leaching of calcium hydroxide

Inaccessible Areas:

As described in NUREG-1557, 

leaching of calcium hydroxide from 

reinforced concrete becomes 

significant only if the concrete is 

exposed to flowing water. Even if 

reinforced concrete is exposed to 

flowing water, such leaching is not 

significant if the concrete is 

constructed to ensure that it is dense, 

well-cured, has low permeability, and 

that cracking is well controlled. 

Cracking is controlled through proper 

arrangement and distribution of 

reinforcing bars. All of the above 

Yes, if 

concrete was 

not 

constructed 

as stated for 

inaccessible 

areas
September 2005 III A6-11 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A6 Group 6 Structures (Water-Control Structures)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

characteristics are assured if the 

concrete was constructed with the 

guidance of ACI 201.2R-77. Therefore, 

if these conditions are satisfied, aging 

management is not necessary.

III.A6-7

(T-20)

III.A6.1-h Concrete:

Exterior aboveand belowgrade;

foundation; 

interior slab

Reinforced 

concrete

Water –

flowing

Loss of material/ 

abrasion; 

cavitation

Chapter XI.S7, “Regulatory Guide 

1.127, Inspection of Water-Control 

Structures Associated with Nuclear 

Power Plants” or the FERC / US Army 

Corp of Engineers dam inspections 

and maintenance programs.

No

III.A6-8

(T-09)

III.A6.1-g Concrete:

Foundation; 

subfoundation

Reinforced 

concrete;

Porous 

concrete

Water –

flowing under 

foundation

Reduction in 

foundation 

strength, 

cracking, 

differential 

settlement/ 

erosion of 

porous concrete 

subfoundation

Chapter XI.S6, “Structures Monitoring 

Program”

Erosion of cement from porous 

concrete subfoundations beneath 

containment basemats is described in 

NRC IN 97-11. NRC IN 98-26 

proposes Maintenance Rule Structures 

Monitoring for managing this aging 

effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous 

concrete subfoundations, the licensee 

is to ensure proper functioning of the 

de-watering system through the period 

of extended operation.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon
NUREG-1801, Rev. 1 III A6-12 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A6 Group 6 Structures (Water-Control Structures)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

III.A6-9

(T-22)

III.A6.4-a Earthen watercontrol 

structures:

Dams,

Embankments,

Reservoirs,

Channels,

Canals and 

ponds

Various Water –

flowing

Water –

standing

Loss of material, 

loss of form/ 

erosion, 

settlement, 

sedimentation, 

frost action, 

waves, currents, 

surface runoff, 

seepage

Chapter XI.S7, “Regulatory Guide 

1.127, Inspection of Water-Control 

Structures Associated with Nuclear 

Power Plants” or the FERC / US Army 

Corp of Engineers dam inspections 

and maintenance programs.

No

III.A6-10

(T-12)

III.A6.3-a Masonry walls:

All

Concrete 

block

Air – indoor 

uncontrolled or 

air – outdoor

Cracking due to 

restraint 

shrinkage, 

creep, and 

aggressive 

environment

Chapter XI.S5, “Masonry Wall 

Program”

No

III.A6-11

(T-21)

III.A6.2-a Metal 

components:

All structural 

members

Steel; 

copper 

alloys

Air – indoor 

uncontrolled or 

air – outdoor; 

Water –

flowing or 

water –

standing

Loss of material/ 

general (steel 

only), pitting and 

crevice corrosion

Chapter XI.S7, “Regulatory Guide 

1.127, Inspection of Water-Control 

Structures Associated with Nuclear 

Power Plants” or the FERC / US Army 

Corp of Engineers dam inspections 

and maintenance programs.

If protective coatings are relied upon to 

manage the effects of aging, this AMP 

is to include provisions to address 

protective coating monitoring and 

maintenance.

No
September 2005 III A6-13 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A6 Group 6 Structures (Water-Control Structures)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

III.A6-12

(TP-7)

III.A6. Seals, gaskets, 

and moisture 

barriers 

(caulking, 

flashing, and 

other sealants)

Elastomers

such as 

EPDM 

rubber

Various Loss of sealing/ 

deterioration of 

seals, gaskets, 

and moisture 

barriers 

(caulking, 

flashing, and 

other sealants)

Chapter XI.S6, “Structures Monitoring 

Program”

No
NUREG-1801, Rev. 1 III A6-14 September 2005

This Page Intentionally Left Blank
September 2005 III A7-1 NUREG-1801, Rev. 1

A7. GROUP 7 STRUCTURES (CONCRETE TANKS AND MISSILE BARRIERS)

Systems, Structures, and Components

This section addresses the elements of concrete tanks and missile barriers. For this group, the 

applicable structural elements are identified: concrete and steel. The aging management review 

is presented for each applicable combination of structural element and aging effect.

System Interfaces

Physical interfaces exist with any system or component that either penetrates the structure wall 

or is supported by the structure wall, floor, and roof. The direct interface is through the system 

or component supports that are anchored to the structure. Structures also protect housed 

systems and components from internal and external design basis events. In the case of tanks, 

there is a functional interface with the associated system. Water-control structures are integral 

parts of the systems that provide plant cooling water and residual heat removal.
NUREG-1801, Rev. 1 III A7-2 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A7 Group 7 Structures (Concrete Tanks and Missile Barriers)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A7-1

(T-03)

III.A7.1-c Concrete:

All

Reinforced 

concrete

Any Cracking due to 

expansion/ 

reaction with 

aggregates

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible Areas:

Inspections/evaluations performed in 

accordance with the Structures 

Monitoring Program will indicate the 

presence of expansion and cracking 

due to reaction with aggregates.

Inaccessible Areas:

As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates performed 

in accordance with ASTM C295-54 or 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregatereinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with ACI 

201.2R. Therefore, if these conditions 

are satisfied, aging management is not 

necessary.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas.
September 2005 III A7-3 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A7 Group 7 Structures (Concrete Tanks and Missile Barriers)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A7-2

(T-08)

III.A7.1-h Concrete:

All

Reinforced 

concrete

Soil Cracks and 

distortion due to 

increased stress 

levels from 

settlement

Chapter XI.S6, “Structures Monitoring 

Program”

If a de-watering system is relied upon 

for control of settlement, then the 

licensee is to ensure proper functioning 

of the de-watering system through the 

period of extended operation. 

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon
NUREG-1801, Rev. 1 III A7-4 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A7 Group 7 Structures (Concrete Tanks and Missile Barriers)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A7-3

(T-05)

III.A7.1-e Concrete:

Below-grade 

exterior; 

foundation

Reinforced 

concrete

Ground 

water/soil

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling)/ 

corrosion of 

embedded steel

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible Areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the cracking, loss of bond, 

or loss of material (spalling, scaling) 

due to corrosion of embedded steel.

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 

500 ppm, or sulfates <1500 ppm, as a 

minimum, consider

(1) Examination of the exposed portions 

of the below-grade concrete, when 

excavated for any reason, and 

(2) Periodic monitoring of below-grade 

water chemistry, including 

consideration of potential seasonal 

variations. 

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the 

concrete aging during the period of 

extended operation.

Yes, plantspecific if 

environment is 

aggressive
September 2005 III A7-5 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A7 Group 7 Structures (Concrete Tanks and Missile Barriers)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A7-4

(T-07)

III.A7.1-g Concrete:

Below-grade 

exterior; 

foundation

Reinforced 

concrete

Ground 

water/soil

Increase in 

porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling)/ 

aggressive 

chemical attack

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 

500 ppm, or sulfates <1500 ppm, as a 

minimum, consider

(1) Examination of the exposed portions 

of the below-grade concrete, when 

excavated for any reason, and 

(2) Periodic monitoring of below-grade 

water chemistry, including 

consideration of potential seasonal 

variations. 

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the 

concrete aging during the period of 

extended operation.

Yes, plantspecific if 

environment is 

aggressive
NUREG-1801, Rev. 1 III A7-6 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A7 Group 7 Structures (Concrete Tanks and Missile Barriers)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A7-5

(T-01)

III.A7.1-a Concrete:

Exterior 

above- and 

below-grade; 

foundation

Reinforced 

concrete

Air – outdoor Loss of material 

(spalling, scaling) 

and cracking/ 

freeze-thaw

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible Areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of loss of 

material (spalling, scaling) and cracking 

due to freeze-thaw.

Inaccessible Areas:

Evaluation is needed for plants that are 

located in moderate to severe 

weathering conditions (weathering 

index > 100 day-inch/yr) (NUREG1557). Documented evidence to 

confirm that existing concrete has air 

content of 3% to 6% and water-tocement ratio of 0.35-0.45, and 

subsequent inspections did not exhibit 

degradation related to freeze-thaw, 

should be considered a part of the 

evaluation.

The weathering index for the 

continental US is shown in ASTM C33-

90, Fig.1.

Yes, if not 

within the 

scope of the 

applicant’s

structures 

monitoring 

program or for 

inaccessible 

areas of 

plants located 

in moderate to 

severe 

weathering 

conditions
September 2005 III A7-7 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A7 Group 7 Structures (Concrete Tanks and Missile Barriers)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A7-6

(T-02)

III.A7.1-b Concrete:

Exterior 

above- and 

below-grade; 

foundation

Reinforced 

concrete

Water – flowing Increase in 

porosity and 

permeability, loss 

of strength/ 

leaching of 

calcium 

hydroxide

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of increase in 

porosity, and permeability due to 

leaching of calcium hydroxide.

Inaccessible Areas:

An aging management program is not 

necessary, even if reinforced concrete 

is exposed to flowing water, if there is 

documented evidence that confirms the 

in-place concrete was constructed in 

accordance with the recommendations 

in ACI 201.2R-77.

Yes, if 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas
NUREG-1801, Rev. 1 III A7-8 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A7 Group 7 Structures (Concrete Tanks and Missile Barriers)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A7-7

(T-09)

III.A7.1-i Concrete:

Foundation; 

subfoundatio

n

Reinforced 

concrete;

Porous 

concrete

Water – flowing 

under 

foundation

Reduction in 

foundation 

strength, 

cracking, 

differential 

settlement/ 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Monitoring 

Program”

Erosion of cement from porous 

concrete subfoundations beneath 

containment basemats is described in 

NRC IN 97-11. NRC IN 98-26 proposes 

Maintenance Rule Structures 

Monitoring for managing this aging 

effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous concrete 

subfoundations, the licensee is to 

ensure proper functioning of the dewatering system through the period of 

extended operation.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon

III.A7-8

(T-04)

III.A7.1-d Concrete:

Interior and 

above-grade 

exterior

Reinforced 

concrete

Air – indoor 

uncontrolled or 

air – outdoor

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling)/ 

corrosion of 

embedded steel

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of cracking, 

loss of bond, and loss of material 

(spalling, scaling) due to corrosion of 

embedded steel.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program
September 2005 III A7-9 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A7 Group 7 Structures (Concrete Tanks and Missile Barriers)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A7-9

(T-06)

III.A7.1-f Concrete:

Interior and 

above-grade 

exterior

Reinforced 

concrete

Air – indoor 

uncontrolled or 

air – outdoor

Increase in 

porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling)/ 

aggressive 

chemical attack

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible Areas:

Inspections performed in accordance 

with Structures Monitoring Program will 

indicate the presence of increase in 

porosity and permeability, cracking, or 

loss of material (spalling, scaling) due 

to aggressive chemical attack.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.A7-10

(T-11)

III.A7.2-a Steel 

components:

All structural 

steel

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of material/ 

corrosion

Chapter XI.S6, “Structures Monitoring 

Program”

If protective coatings are relied upon to 

manage the effects of aging, the 

structures monitoring program is to 

include provisions to address protective 

coating monitoring and maintenance.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.A7-11

(T-23)

III.A7.2-b Steel 

components:

Tank liner

Stainless 

steel

Water –

standing

Cracking/ stress 

corrosion 

cracking

Loss of 

material/pitting 

and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific
NUREG-1801, Rev. 1 III A7-10 September 2005

DraftDraftNUREG-1801, Rev. 1 III A8-10 September 20055

This Page Intentionally Left Blank
September 2005 III A8-1 NUREG-1801, Rev. 1

A8. GROUP 8 STRUCTURES (STEEL TANKS AND MISSILE BARRIERS)

Systems, Structures, and Components

This section addresses the elements of steel tanks and missile barriers. For this group, the 

applicable structural elements are identified: concrete and steel. The aging management review 

is presented for each applicable combination of structural element and aging effect.

System Interfaces

Physical interfaces exist with any system or component that either penetrates the structure wall 

or is supported by the structure wall, floor, and roof. The direct interface is through the system 

or component supports that are anchored to the structure. Structures also protect housed 

systems and components from internal and external design basis events. In the case of tanks, 

there is a functional interface with the associated system. Water-control structures are integral 

parts of the systems that provide plant cooling water and residual heat removal.
NUREG-1801, Rev. 1 III A8-2 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A8 Group 8 Structures (Steel Tanks and Missile Barriers)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A8-1

(T-03)

III.A8.1-c Concrete:

All

Reinforced 

concrete

Any Cracking due to 

expansion/ 

reaction with 

aggregates

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible Areas:

Inspections/evaluations performed in 

accordance with the Structures 

Monitoring Program will indicate the 

presence of expansion and cracking 

due to reaction with aggregates.

Inaccessible Areas:

As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates performed 

in accordance with ASTM C295-54 or 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregatereinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with ACI 

201.2R. Therefore, if these conditions 

are satisfied, aging management is not 

necessary.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas.
September 2005 III A8-3 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A8 Group 8 Structures (Steel Tanks and Missile Barriers)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A8-2

(T-08)

III.A8.1-f Concrete:

All

Reinforced 

concrete

Soil Cracks and 

distortion due to 

increased stress

levels from 

settlement

Chapter XI.S6, “Structures Monitoring 

Program”

If a de-watering system is relied upon 

for control of settlement, then the 

licensee is to ensure proper functioning 

of the de-watering system through the 

period of extended operation. 

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon
NUREG-1801, Rev. 1 III A8-4 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A8 Group 8 Structures (Steel Tanks and Missile Barriers)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A8-3

(T-05)

III.A8.1-d Concrete:

Below-grade 

exterior; 

foundation

Reinforced 

concrete

Ground 

water/soil

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling)/ 

corrosion of 

embedded steel

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible Areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the cracking, loss of bond, 

or loss of material (spalling, scaling) 

due to corrosion of embedded steel.

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 

500 ppm, or sulfates <1500 ppm, as a 

minimum, consider

(1) Examination of the exposed portions 

of the below-grade concrete, when 

excavated for any reason, and 

(2) Periodic monitoring of below-grade 

water chemistry, including 

consideration of potential seasonal 

variations. 

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the 

concrete aging during the period of 

extended operation.

Yes, plantspecific if 

environment is 

aggressive
September 2005 III A8-5 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A8 Group 8 Structures (Steel Tanks and Missile Barriers)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A8-4

(T-07)

III.A8.1-e Concrete:

Below-grade 

exterior; 

foundation

Reinforced 

concrete

Ground 

water/soil

Increase in 

porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling)/ 

aggressive 

chemical attack

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 

500 ppm, or sulfates <1500 ppm, as a 

minimum, consider

(1) Examination of the exposed portions 

of the below-grade concrete, when 

excavated for any reason, and 

(2) Periodic monitoring of below-grade 

water chemistry, including 

consideration of potential seasonal 

variations. 

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the 

concrete aging during the period of 

extended operation.

Yes, plantspecific if 

environment is 

aggressive
NUREG-1801, Rev. 1 III A8-6 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A8 Group 8 Structures (Steel Tanks and Missile Barriers)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A8-5

(T-01)

III.A8.1-a Concrete:

Exterior 

above- and 

below-grade; 

foundation

Reinforced 

concrete

Air – outdoor Loss of material 

(spalling, scaling) 

and cracking/ 

freeze-thaw

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible Areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of loss of 

material (spalling, scaling) and cracking 

due to freeze-thaw.

Inaccessible Areas:

Evaluation is needed for plants that are 

located in moderate to severe 

weathering conditions (weathering 

index > 100 day-inch/yr) (NUREG1557). Documented evidence to 

confirm that existing concrete has air 

content of 3% to 6% and water-tocement ratio of 0.35-0.45, and 

subsequent inspections did not exhibit 

degradation related to freeze-thaw, 

should be considered a part of the 

evaluation.

The weathering index for the 

continental US is shown in ASTM C33-

90, Fig.1.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or for 

inaccessible 

areas of 

plants located 

in moderate to 

severe 

weathering 

conditions
September 2005 III A8-7 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A8 Group 8 Structures (Steel Tanks and Missile Barriers)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A8-6

(T-02)

III.A8.1-b Concrete:

Exterior 

above- and 

below-grade; 

foundation

Reinforced 

concrete

Water – flowing Increase in 

porosity and 

permeability, loss 

of strength/ 

leaching of 

calcium 

hydroxide

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of increase in 

porosity, and permeability due to 

leaching of calcium hydroxide.

Inaccessible Areas:

An aging management program is not 

necessary, even if reinforced concrete 

is exposed to flowing water, if there is 

documented evidence that confirms the 

in-place concrete was constructed in 

accordance with the recommendations 

in ACI 201.2R-77.

Yes, if 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas
NUREG-1801, Rev. 1 III A8-8 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

A8 Group 8 Structures (Steel Tanks and Missile Barriers)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A8-7

(T-09)

III.A8.1-g Concrete:

Foundation; 

subfoundatio

n

Reinforced 

concrete;

Porous 

concrete

Water – flowing 

under 

foundation

Reduction in 

foundation 

strength, 

cracking, 

differential 

settlement/ 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Monitoring 

Program”

Erosion of cement from porous 

concrete subfoundations beneath 

containment basemats is described in 

NRC IN 97-11. NRC IN 98-26 proposes 

Maintenance Rule Structures 

Monitoring for managing this aging 

effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous concrete 

subfoundations, the licensee is to 

ensure proper functioning of the dewatering system through the period of 

extended operation.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon

III.A8-8

(T-11)

III.A8.2-a Steel 

components:

All structural 

steel

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of material/ 

corrosion

Chapter XI.S6, “Structures Monitoring 

Program”

If protective coatings are relied upon to 

manage the effects of aging, the 

structures monitoring program is to 

include provisions to address protective 

coating monitoring and maintenance.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.A8-9

(T-23)

III.A8.2-b Steel 

components:

Tank liner

Stainless 

steel

Water –

standing

Cracking/ stress 

corrosion 

cracking

Loss of 

material/pitting 

and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific
September 2005 III A9-1 NUREG-1801, Rev. 1

A9. GROUP 9 STRUCTURES (BWR UNIT VENT STACK)

Systems, Structures, and Components

This section addresses the elements of the boiling water reactor (BWR) unit vent stack. For this 

group, the applicable structural element is identified: concrete. The aging management review is 

presented for each applicable combination of structural element and aging effect.

System Interfaces

Physical interfaces exist with any system or component that either penetrates the structure wall 

or is supported by the structure wall, floor, and roof. The direct interface is through the system 

or component supports that are anchored to the structure. Structures also protect housed 

systems and components from internal and external design basis events. In the case of tanks, 

there is a functional interface with the associated system. Water-control structures are integral 

parts of the systems that provide plant cooling water and residual heat removal. 
NUREG-1801, Rev. 1 III A9-2 September 20055

III STRUCTURES AND COMPONENT SUPPORTS

A9 Group 9 Structures (BWR Unit Vent Stack)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A9-1

(T-03)

III.A9.1-c Concrete:

All

Reinforced 

concrete

Any Cracking due to 

expansion/ 

reaction with 

aggregates

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible Areas:

Inspections/evaluations performed in 

accordance with the Structures 

Monitoring Program will indicate the 

presence of expansion and cracking 

due to reaction with aggregates.

Inaccessible Areas:

As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates performed 

in accordance with ASTM C295-54 or 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregatereinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with ACI 

201.2R. Therefore, if these conditions 

are satisfied, aging management is not 

necessary.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas.
September 2005 III A9-3 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A9 Group 9 Structures (BWR Unit Vent Stack)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A9-2

(T-08)

III.A9.1-h Concrete:

All

Reinforced 

concrete

Soil Cracks and 

distortion due to 

increased stress 

levels from 

settlement

Chapter XI.S6, “Structures Monitoring 

Program”

If a de-watering system is relied upon 

for control of settlement, then the 

licensee is to ensure proper functioning 

of the de-watering system through the 

period of extended operation. 

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon
NUREG-1801, Rev. 1 III A9-4 September 20055

III STRUCTURES AND COMPONENT SUPPORTS

A9 Group 9 Structures (BWR Unit Vent Stack)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A9-3

(T-05)

III.A9.1-e Concrete:

Below-grade 

exterior; 

foundation

Reinforced 

concrete

Ground 

water/soil

Cracking, loss of 

bond, and loss of 

material 

(spalling, 

scaling)/ 

corrosion of 

embedded steel

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible Areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the cracking, loss of bond, 

or loss of material (spalling, scaling) 

due to corrosion of embedded steel.

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 

500 ppm, or sulfates <1500 ppm, as a 

minimum, consider

(1) Examination of the exposed portions 

of the below-grade concrete, when 

excavated for any reason, and 

(2) Periodic monitoring of below-grade 

water chemistry, including consideration 

of potential seasonal variations. 

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the 

concrete aging during the period of 

extended operation.

Yes, plantspecific if 

environment is 

aggressive
September 2005 III A9-5 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A9 Group 9 Structures (BWR Unit Vent Stack)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A9-4

(T-07)

III.A9.1-g Concrete:

Below-grade 

exterior; 

foundation

Reinforced 

concrete

Ground 

water/soil

Increase in 

porosity and 

permeability, 

cracking, loss of 

material 

(spalling, 

scaling)/ 

aggressive 

chemical attack

Inaccessible Areas:

For plants with non-aggressive ground 

water/soil; i.e., pH > 5.5, chlorides < 

500 ppm, or sulfates <1500 ppm, as a 

minimum, consider

(1) Examination of the exposed portions 

of the below-grade concrete, when 

excavated for any reason, and 

(2) Periodic monitoring of below-grade 

water chemistry, including consideration 

of potential seasonal variations. 

For plants with aggressive 

groundwater/soil, and/or where the 

concrete structural elements have 

experienced degradation, a plant 

specific AMP accounting for the extent 

of the degradation experienced should 

be implemented to manage the 

concrete aging during the period of 

extended operation.

Yes, plantspecific if 

environment is 

aggressive
NUREG-1801, Rev. 1 III A9-6 September 20055

III STRUCTURES AND COMPONENT SUPPORTS

A9 Group 9 Structures (BWR Unit Vent Stack)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A9-5

(T-01)

III.A9.1-a Concrete:

Exterior 

above- and 

below-grade; 

foundation

Reinforced 

concrete

Air – outdoor Loss of material 

(spalling, scaling) 

and cracking/ 

freeze-thaw

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible Areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of loss of 

material (spalling, scaling) and cracking 

due to freeze-thaw.

Inaccessible Areas:

Evaluation is needed for plants that are 

located in moderate to severe 

weathering conditions (weathering 

index > 100 day-inch/yr) (NUREG1557). Documented evidence to confirm 

that existing concrete has air content of 

3% to 6% and water-to-cement ratio of 

0.35-0.45, and subsequent inspections 

did not exhibit degradation related to 

freeze-thaw, should be considered a 

part of the evaluation.

The weathering index for the 

continental US is shown in ASTM C33-

90, Fig.1.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or for 

inaccessible 

areas of 

plants located 

in moderate to 

severe 

weathering 

conditions
September 2005 III A9-7 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A9 Group 9 Structures (BWR Unit Vent Stack)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A9-6

(T-02)

III.A9.1-b Concrete:

Exterior 

above- and 

below-grade; 

foundation

Reinforced 

concrete

Water – flowing Increase in 

porosity and 

permeability, loss 

of strength/ 

leaching of 

calcium 

hydroxide

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of increase in 

porosity, and permeability due to 

leaching of calcium hydroxide.

Inaccessible Areas:

An aging management program is not 

necessary, even if reinforced concrete 

is exposed to flowing water, if there is 

documented evidence that confirms the 

in-place concrete was constructed in 

accordance with the recommendations 

in ACI 201.2R-77.

Yes, if 

concrete was 

not 

constructed as 

stated for 

inaccessible 

areas
NUREG-1801, Rev. 1 III A9-8 September 20055

III STRUCTURES AND COMPONENT SUPPORTS

A9 Group 9 Structures (BWR Unit Vent Stack)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A9-7

(T-09)

III.A9.1-i Concrete:

Foundation; 

subfoundatio

n

Reinforced 

concrete;

Porous 

concrete

Water – flowing 

under 

foundation

Reduction in 

foundation 

strength, 

cracking, 

differential 

settlement/ 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Monitoring 

Program”

Erosion of cement from porous 

concrete subfoundations beneath 

containment basemats is described in 

NRC IN 97-11. NRC IN 98-26 proposes 

Maintenance Rule Structures 

Monitoring for managing this aging 

effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous concrete 

subfoundations, the licensee is to 

ensure proper functioning of the dewatering system through the period of 

extended operation.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program or a 

de-watering 

system is 

relied upon

III.A9-8

(T-04)

III.A9.1-d Concrete:

Interior and 

above-grade 

exterior

Reinforced 

concrete

Air – indoor 

uncontrolled or 

air – outdoor

Cracking, loss of 

bond, and loss of 

material 

(spalling, 

scaling)/ 

corrosion of 

embedded steel

Chapter XI.S6, “Structures Monitoring 

Program”

Accessible areas:

Inspections performed in accordance 

with the Structures Monitoring Program 

will indicate the presence of cracking, 

loss of bond, and loss of material 

(spalling, scaling) due to corrosion of 

embedded steel.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program
September 2005 III A9-9 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

A9 Group 9 Structures (BWR Unit Vent Stack)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.A9-9

(T-06)

III.A9.1-f Concrete:

Interior and 

above-grade 

exterior

Reinforced 

concrete

Air – indoor 

uncontrolled or 

air – outdoor

Increase in 

porosity and 

permeability, 

cracking, loss of 

material 

(spalling, 

scaling)/ 

aggressive 

chemical attack

Chapter XI.S6, "Structures Monitoring 

Program"

Accessible Areas:

Inspections performed in accordance 

with Structures Monitoring Program will 

indicate the presence of increase in 

porosity and permeability, cracking, or 

loss of material (spalling, scaling) due 

to aggressive chemical attack.

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program
NUREG-1801, Rev. 1 III A9-10 September 2005

This Page Intentionally Left Blank
September 2005 III B-i NUREG-1801, Rev. 1

III.B COMPONENT SUPPORTS

B1. Supports for ASME Piping and Components

B2. Supports for Cable Trays, Conduit, HVAC Ducts, TubeTrack®, Instrument Tubing, 

Non-ASME Piping and Components

B3. Anchorage of Racks, Panels, Cabinets, and Enclosures for Electrical Equipment and 

Instrumentation

B4. Supports for Emergency Diesel Generator (EDG), HVAC System Components, and 

Other Miscellaneous Mechanical Equipment

B5. Supports for Platforms, Pipe Whip Restraints, Jet Impingement Shields, Masonry 

Walls, and Other Miscellaneous Structures
NUREG-1801, Rev. 1 III B-ii September 2005

This Page Intentionally Left Blank
September 2005 III B1-1 NUREG-1801, Rev. 1

B1. SUPPORTS FOR ASME PIPING AND COMPONENTS 

B1.1 Class 1

B1.2 Class 2 and 3

B1.3 Class MC (BWR Containment Supports) 
NUREG-1801, Rev. 1 III B1-2 September 2005

This Page Intentionally Left Blank
September 2005 III B1-3 NUREG-1801, Rev. 1

B1. SUPPORTS FOR ASME PIPING AND COMPONENTS

Systems, Structures, and Components

This section addresses supports and anchorage for ASME piping systems and components. It is 

subdivided into Class 1 (III.B1.1), Class 2 and 3 (III.B1.2), and Class MC (III.B1.3). Applicable 

aging effects are identified and the aging management review is presented for each applicable 

combination of support component and aging effect.

System Interfaces

Physical interfaces exist with the structure, system, or component being supported and with the 

building structural element to which the support is anchored. A primary function of supports is to 

provide anchorage of the supported element for internal and external design basis events, so 

that the supported element can perform its intended function.
NUREG-1801, Rev. 1 III B1-4 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

B1.1 Class 1

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

III.B1.1-1

(T-29)

III.B1.1.4-a Building 

concrete at 

locations of 

expansion 

and grouted 

anchors; 

grout pads for 

support base 

plates

Reinforced 

concrete;

Grout

Air – indoor 

uncontrolled or 

air – outdoor

Reduction in 

concrete anchor 

capacity due to 

local concrete 

degradation/ 

service-induced 

cracking or other 

concrete aging 

mechanisms

Chapter XI.S6, “Structures 

Monitoring Program”

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.B1.1-2

(T-28)

III.B1.1.3-a Constant and 

variable load 

spring 

hangers; 

guides; stops

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of 

mechanical 

function/ 

corrosion, 

distortion, dirt, 

overload, fatigue 

due to vibratory 

and cyclic 

thermal loads

Chapter XI.S3, “ASME Section XI, 

Subsection IWF”

No

III.B1.1-3

(T-27)

III.B1.1.2-a High strength 

bolting for 

NSSS 

component 

supports

Low alloy 

steel, yield 

strength 

>150 ksi

Air – indoor 

uncontrolled

Cracking/ stress 

corrosion 

cracking

Chapter XI.M18, “Bolting Integrity” No

III.B1.1-4

(TP-9)

III.B1.1. High strength 

bolting for 

NSSS 

component 

supports

Low alloy 

steel, yield 

strength 

>150 ksi

Air – indoor 

uncontrolled

Loss of material/ 

general 

corrosion

Chapter XI.M18, “Bolting Integrity” No
September 2005 III B1-5 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

B1.1 Class 1

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

III.B1.1-5

(T-32)

III.B1.1.3-a Sliding 

surfaces

Lubrite® Air – indoor 

uncontrolled or 

air – outdoor

Loss of 

mechanical 

function/ 

corrosion, 

distortion, dirt, 

overload, fatigue 

due to vibratory 

and cyclic 

thermal loads

Chapter XI.S3, “ASME Section XI, 

Subsection IWF”

No

III.B1.1-6

(TP-8)

III.B1.1. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Aluminum Air – indoor 

uncontrolled

None None No

III.B1.1-7

(TP-11)

III.B1.1. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel

Air – indoor 

uncontrolled

None None No
NUREG-1801, Rev. 1 III B1-6 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

B1.1 Class 1

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

III.B1.1-8

(TP-3)

III.B1.1. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel, 

aluminum

Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

No

III.B1.1-9

(TP-5)

III.B1.1. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless steel Air – indoor 

uncontrolled

None None No

III.B1.1-10

(TP-4)

III.B1.1. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless steel Air with borated 

water leakage

None None No
September 2005 III B1-7 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

B1.1 Class 1

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

III.B1.1-11

(TP-10)

III.B1.1. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless 

steel; steel

Treated Water 

< 60C (<140 F)

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” 

for BWR water, and

Chapter XI.S3, “ASME Section XI, 

Subsection IWF”

No

III.B1.1-12

(T-26)

III.B1.1.1-c Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor 

uncontrolled

Cumulative 

fatigue damage/ 

fatigue

(Only if CLB 

fatigue analysis 

exists)

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluated for 

the period of extended operation. 

See the Standard Review Plan, 

Section 4.3 “Metal Fatigue,” for 

acceptable methods for meeting the 

requirements of 10 CFR 54.21(c)(1).

Yes,

TLAA

III.B1.1-13

(T-24)

III.B1.1.1-a Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of material/ 

general and 

pitting corrosion

Chapter XI.S3, “ASME Section XI, 

Subsection IWF”

No
NUREG-1801, Rev. 1 III B1-8 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

B1.1 Class 1

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

III.B1.1-14

(T-25)

III.B1.1.1-b Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

No

III.B1.1-15

(T-33)

III.B1.1.3-a Vibration 

isolation 

elements

Non-metallic 

(e.g., Rubber)

Air – indoor 

uncontrolled or 

air – outdoor

Reduction or 

loss of isolation 

function/ 

radiation 

hardening, 

temperature, 

humidity, 

sustained 

vibratory loading

Chapter XI.S3, “ASME Section XI, 

Subsection IWF”

No
September 2005 III B1-9 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

B1.2 Class 2 and 3

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

III.B1.2-1

(T-29)

III.B1.2.3-a Building 

concrete at 

locations of 

expansion 

and grouted 

anchors; 

grout pads for 

support base 

plates

Reinforced 

concrete;

Grout

Air – indoor 

uncontrolled or 

air – outdoor

Reduction in 

concrete anchor 

capacity due to 

local concrete 

degradation/ 

service-induced 

cracking or other 

concrete aging 

mechanisms

Chapter XI.S6, “Structures 

Monitoring Program”

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.B1.2-2

(T-28)

III.B1.2.2-a Constant and 

variable load 

spring 

hangers; 

guides; stops

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of 

mechanical 

function/ 

corrosion, 

distortion, dirt, 

overload, fatigue 

due to vibratory 

and cyclic 

thermal loads

Chapter XI.S3, “ASME Section XI, 

Subsection IWF”

No

III.B1.2-3

(T-32)

III.B1.2.2-a Sliding 

surfaces

Lubrite® Air – indoor 

uncontrolled or 

air – outdoor

Loss of 

mechanical 

function/ 

corrosion, 

distortion, dirt, 

overload, fatigue 

due to vibratory 

and cyclic 

thermal loads

Chapter XI.S3, “ASME Section XI, 

Subsection IWF”

No
NUREG-1801, Rev. 1 III B1-10 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

B1.2 Class 2 and 3

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

III.B1.2-4

(TP-8)

III.B1.2. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Aluminum Air – indoor 

uncontrolled

None None No

III.B1.2-5

(TP-11)

III.B1.2. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel

Air – indoor 

uncontrolled

None None No

III.B1.2-6

(TP-3)

III.B1.2. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel, 

aluminum

Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

No
September 2005 III B1-11 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

B1.2 Class 2 and 3

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

III.B1.2-7

(TP-5)

III.B1.2. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless steel Air – indoor 

uncontrolled

None None No

III.B1.2-8

(TP-4)

III.B1.2. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless steel Air with borated 

water leakage

None None No

III.B1.2-9

(T-26)

III.B1.2.1-c Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor 

uncontrolled

Cumulative 

fatigue damage/ 

fatigue

(Only if CLB 

fatigue analysis 

exists)

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluated for 

the period of extended operation. 

See the Standard Review Plan, 

Section 4.3 “Metal Fatigue,” for 

acceptable methods for meeting the 

requirements of 10 CFR 54.21(c)(1).

Yes,

TLAA
NUREG-1801, Rev. 1 III B1-12 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

B1.2 Class 2 and 3

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

III.B1.2-10

(T-24)

III.B1.2.1-a Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of material/ 

general and 

pitting corrosion

Chapter XI.S3, “ASME Section XI, 

Subsection IWF”

No

III.B1.2-11

(T-25)

III.B1.2.1-b Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

No

III.B1.2-12

(T-33)

III.B1.2.2-a Vibration 

isolation 

elements

Non-metallic 

(e.g., Rubber)

Air – indoor 

uncontrolled or 

air – outdoor

Reduction or 

loss of isolation 

function/ 

radiation 

hardening, 

temperature, 

humidity, 

sustained 

vibratory loading

Chapter XI.S3, “ASME Section XI, 

Subsection IWF”

No
September 2005 III B1-13 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

B1.3 Class MC (BWR Containment Supports) 

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

III.B1.3-1

(T-29)

III.B1.3.3-a Building 

concrete at 

locations of 

expansion 

and grouted 

anchors; 

grout pads for 

support base 

plates

Reinforced 

concrete;

Grout

Air – indoor 

uncontrolled or 

air – outdoor

Reduction in 

concrete anchor 

capacity due to 

local concrete 

degradation/ 

service-induced 

cracking or other 

concrete aging 

mechanisms

Chapter XI.S6, “Structures 

Monitoring Program”

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.B1.3-2

(T-28)

III.B1.3.2-a Constant and 

variable load 

spring 

hangers; 

guides; stops

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of 

mechanical 

function/ 

corrosion, 

distortion, dirt, 

overload, fatigue 

due to vibratory 

and cyclic 

thermal loads

Chapter XI.S3, “ASME Section XI, 

Subsection IWF”

No

III.B1.3-3

(T-32)

III.B1.3.2-a Sliding 

surfaces

Lubrite® Air – indoor 

uncontrolled or 

air – outdoor

Loss of 

mechanical 

function/ 

corrosion, 

distortion, dirt, 

overload, fatigue 

due to vibratory 

and cyclic 

thermal loads

Chapter XI.S3, “ASME Section XI, 

Subsection IWF”

No
NUREG-1801, Rev. 1 III B1-14 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

B1.3 Class MC (BWR Containment Supports) 

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

III.B1.3-4

(TP-8)

III.B1.3. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Aluminum Air – indoor 

uncontrolled

None None No

III.B1.3-5

(TP-11)

III.B1.3. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel

Air – indoor 

uncontrolled

None None No

III.B1.3-6

(TP-3)

III.B1.3. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel, 

aluminum

Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

No
September 2005 III B1-15 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

B1.3 Class MC (BWR Containment Supports) 

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

III.B1.3-7

(TP-5)

III.B1.3. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless steel Air – indoor 

uncontrolled

None None No

III.B1.3-8

(TP-4)

III.B1.3. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless steel Air with borated 

water leakage

None None No

III.B1.3-9

(T-26)

III.B1.3.1-b Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor 

uncontrolled

Cumulative 

fatigue damage/ 

fatigue

(Only if CLB 

fatigue analysis 

exists)

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluated for 

the period of extended operation. 

See the Standard Review Plan, 

Section 4.3 “Metal Fatigue,” for 

acceptable methods for meeting the 

requirements of 10 CFR 54.21(c)(1).

Yes,

TLAA
NUREG-1801, Rev. 1 III B1-16 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

B1.3 Class MC (BWR Containment Supports) 

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

III.B1.3-10

(T-24)

III.B1.3.1-a Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor 

uncontrolled or

air – outdoor

Loss of material/ 

general and 

pitting corrosion

Chapter XI.S3, “ASME Section XI, 

Subsection IWF”

No

III.B1.3-11

(T-33)

III.B1.3.2-a Vibration 

isolation 

elements

Non-metallic 

(e.g., Rubber)

Air – indoor 

uncontrolled or 

air – outdoor

Reduction or 

loss of isolation 

function/ 

radiation 

hardening, 

temperature, 

humidity, 

sustained 

vibratory loading

Chapter XI.S3, “ASME Section XI, 

Subsection IWF”

No
September 2005 III B2-1 NUREG-1801, Rev. 1

B2. SUPPORTS FOR CABLE TRAYS, CONDUIT, HVAC DUCTS, TUBETRACK®, 

INSTRUMENT TUBING, NON-ASME PIPING AND COMPONENTS

Systems, Structures, and Components

This section addresses supports and anchorage for cable trays, conduit, heating, ventilation, 

and air-conditioning (HVAC) ducts, TubeTrack®, instrument tubing, and non-ASME piping and 

components. Applicable aging effects are identified and the aging management review is 

presented for each applicable combination of support component and aging effect.

System Interfaces

Physical interfaces exist with the structure, system, or component being supported and with the 

building structural element to which the support is anchored. A primary function of supports is to 

provide anchorage of the supported element for internal and external design basis events, so 

that the supported element can perform its intended function.
NUREG-1801, Rev. 1 III B2-2 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

B2 Supports for Cable Trays, Conduit, HVAC Ducts, TubeTrack, Instrument Tubing, Non-ASME Piping and Components

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.B2-1

(T-29)

III.B2.2-a Building 

concrete at 

locations of 

expansion 

and grouted 

anchors; grout 

pads for 

support base 

plates

Reinforced 

concrete;

Grout

Air – indoor 

uncontrolled or 

air – outdoor

Reduction in 

concrete anchor 

capacity due to 

local concrete 

degradation/ 

service-induced 

cracking or other 

concrete aging 

mechanisms

Chapter XI.S6, “Structures Monitoring 

Program”

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring

program

III.B2-2

(TP-1)

III.B2. Sliding 

support 

bearings and 

sliding 

support 

surfaces

Lubrite®, 

graphitic tool 

steel

Air – indoor 

uncontrolled

Loss of 

mechanical 

function/ 

corrosion, 

distortion, dirt, 

overload, fatigue 

due to vibratory 

and cyclic 

thermal loads

Chapter XI.S6, “Structures Monitoring 

Program”

No

III.B2-3

(TP-2)

III.B2. Sliding 

support 

bearings and 

sliding 

support 

surfaces

Lubrite®, 

graphitic tool 

steel

Air – outdoor Loss of 

mechanical 

function/ 

corrosion, 

distortion, dirt, 

overload, fatigue 

due to vibratory 

and cyclic 

thermal loads

Chapter XI.S6, “Structures Monitoring 

Program”

No
September 2005 III B2-3 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

B2 Supports for Cable Trays, Conduit, HVAC Ducts, TubeTrack, Instrument Tubing, Non-ASME Piping and Components

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.B2-4

(TP-8)

III.B2. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Aluminum Air – indoor 

uncontrolled

None None No

III.B2-5

(TP-11)

III.B2. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel

Air – indoor 

uncontrolled

None None No

III.B2-6

(TP-3)

III.B2. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel, 

aluminum

Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

No
NUREG-1801, Rev. 1 III B2-4 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

B2 Supports for Cable Trays, Conduit, HVAC Ducts, TubeTrack, Instrument Tubing, Non-ASME Piping and Components

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.B2-7

(TP-6)

III.B2. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building

structure

Galvanized 

steel, 

aluminum, 

stainless 

steel

Air – outdoor Loss of material/ 

pitting and 

crevice corrosion

Chapter XI.S6, “Structures Monitoring 

Program”

No

III.B2-8

(TP-5)

III.B2. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless 

steel

Air – indoor 

uncontrolled

None None No

III.B2-9

(TP-4)

III.B2. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless 

steel

Air with borated 

water leakage

None None No
September 2005 III B2-5 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

B2 Supports for Cable Trays, Conduit, HVAC Ducts, TubeTrack, Instrument Tubing, Non-ASME Piping and Components

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.B2-10

(T-30)

III.B2.1-a Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of material/ 

general and 

pitting corrosion

Chapter XI.S6, “Structures Monitoring 

Program”

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.B2-11

(T-25)

III.B2.1-b Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

No
NUREG-1801, Rev. 1 III B2-6 September 2005

This Page Intentionally Left Blank
September 2005 III B3-1 NUREG-1801, Rev. 1

B3. ANCHORAGE OF RACKS, PANELS, CABINETS, AND ENCLOSURES 

FOR ELECTRICAL EQUIPMENT AND INSTRUMENTATION

Systems, Structures, and Components

This section addresses supports and anchorage for racks, panels, cabinets, and enclosures for 

electrical equipment and instrumentation. Applicable aging effects are identified and the aging 

management review is presented for each applicable combination of support component and 

aging effect.

System Interfaces

Physical interfaces exist with the structure, system, or component being supported and with the 

building structural element to which the support is anchored. A primary function of supports is to 

provide anchorage of the supported element for internal and external design basis events, so 

that the supported element can perform its intended function.
NUREG-1801, Rev. 1 III B3-2 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

B3 Anchorage of Racks, Panels, Cabinets, and Enclosures for Electrical Equipment and Instrumentation

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.B3-1

(T-29)

III.B3.2-a Building 

concrete at 

locations of 

expansion 

and grouted 

anchors; grout 

pads for 

support base 

plates

Reinforced 

concrete;

Grout

Air – indoor 

uncontrolled or 

air – outdoor

Reduction in 

concrete anchor 

capacity due to 

local concrete 

degradation/ 

service-induced 

cracking or other 

concrete aging 

mechanisms

Chapter XI.S6, “Structures Monitoring 

Program”

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.B3-2

(TP-8)

III.B3. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Aluminum Air – indoor 

uncontrolled

None None No

III.B3-3

(TP-11)

III.B3. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel

Air – indoor 

uncontrolled

None None No
September 2005 III B3-3 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

B3 Anchorage of Racks, Panels, Cabinets, and Enclosures for Electrical Equipment and Instrumentation

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.B3-4

(TP-3)

III.B3. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to

building 

structure

Galvanized 

steel, 

aluminum

Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

No

III.B3-5

(TP-5)

III.B3. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless 

steel

Air – indoor 

uncontrolled

None None No

III.B3-6

(TP-4)

III.B3. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless 

steel

Air with borated 

water leakage

None None No
NUREG-1801, Rev. 1 III B3-4 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

B3 Anchorage of Racks, Panels, Cabinets, and Enclosures for Electrical Equipment and Instrumentation

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.B3-7

(T-30)

III.B3.1-a Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of material/ 

general and 

pitting corrosion

Chapter XI.S6, “Structures Monitoring 

Program”

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.B3-8

(T-25)

III.B3.1-b Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

No
September 2005 III B4-1 NUREG-1801, Rev. 1

B4. SUPPORTS FOR EMERGENCY DIESEL GENERATOR (EDG), HVAC SYSTEM

COMPONENTS, AND OTHER MISCELLANEOUS MECHANICAL EQUIPMENT

Systems, Structures, and Components

This section addresses supports and anchorage for the emergency diesel generator (EDG) and 

HVAC system components, and other miscellaneous mechanical equipment. Applicable aging 

effects are identified and the aging management review is presented for each applicable 

combination of support component and aging effect.

System Interfaces

Physical interfaces exist with the structure, system, or component being supported and with the 

building structural element to which the support is anchored. A primary function of supports is to 

provide anchorage of the supported element for internal and external design basis events, so 

that the supported element can perform its intended function.
NUREG-1801, Rev. 1 III B4-2 September 200

5

III STRUCTURES AND COMPONENT SUPPORTS

B4 Supports for Emergency Diesel Generator (EDG), HVAC System Components, and Other Miscellaneous Mechanical Equipment

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.B4-1

(T-29)

III.B4.3-a Building 

concrete at 

locations of 

expansion 

and grouted 

anchors; 

grout pads for 

support base 

plates

Reinforced 

concrete;

Grout

Air – indoor 

uncontrolled or 

air – outdoor

Reduction in 

concrete anchor 

capacity due to 

local concrete 

degradation/ 

service-induced 

cracking or other 

concrete aging 

mechanisms

Chapter XI.S6, “Structures Monitoring 

Program”

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.B4-2

(TP-1)

III.B4. Sliding 

support 

bearings and 

sliding 

support 

surfaces

Lubrite®, 

graphitic tool 

steel

Air – indoor 

uncontrolled

Loss of 

mechanical 

function/ 

corrosion, 

distortion, dirt, 

overload, fatigue 

due to vibratory 

and cyclic 

thermal loads

Chapter XI.S6, “Structures Monitoring 

Program”

No

III.B4-3

(TP-2)

III.B4. Sliding 

support 

bearings and 

sliding 

support 

surfaces

Lubrite®, 

graphitic tool 

steel

Air – outdoor Loss of 

mechanical 

function/ 

corrosion, 

distortion, dirt, 

overload, fatigue 

due to vibratory 

and cyclic 

thermal loads

Chapter XI.S6, “Structures Monitoring 

Program”

No
September 2005 III B4-3 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

B4 Supports for Emergency Diesel Generator (EDG), HVAC System Components, and Other Miscellaneous Mechanical Equipment

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.B4-4

(TP-8)

III.B4. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Aluminum Air – indoor 

uncontrolled

None None No

III.B4-5

(TP-11)

III.B4. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel

Air – indoor 

uncontrolled

None None No

III.B4-6

(TP-3)

III.B4. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel, 

aluminum

Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

No
NUREG-1801, Rev. 1 III B4-4 September 200

5

III STRUCTURES AND COMPONENT SUPPORTS

B4 Supports for Emergency Diesel Generator (EDG), HVAC System Components, and Other Miscellaneous Mechanical Equipment

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.B4-7

(TP-6)

III.B4. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel, 

aluminum, 

stainless steel

Air – outdoor Loss of material/ 

pitting and 

crevice corrosion

Chapter XI.S6, “Structures Monitoring 

Program”

No

III.B4-8

(TP-5)

III.B4. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless steel Air – indoor 

uncontrolled

None None No

III.B4-9

(TP-4)

III.B4. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless steel Air with borated 

water leakage

None None No
September 2005 III B4-5 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

B4 Supports for Emergency Diesel Generator (EDG), HVAC System Components, and Other Miscellaneous Mechanical Equipment

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.B4-10

(T-30)

III.B4.1-a Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of material/ 

general and 

pitting corrosion

Chapter XI.S6, “Structures Monitoring 

Program”

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.B4-11

(T-25)

III.B4.1-b Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

No

III.B4-12

(T-31)

III.B4.2-a Vibration 

isolation 

elements

Non-metallic 

(e.g., Rubber)

Air – indoor 

uncontrolled or 

air – outdoor

Reduction or 

loss of isolation 

function/ 

radiation 

hardening, 

temperature, 

humidity, 

sustained 

vibratory loading

Chapter XI.S6, “Structures Monitoring 

Program”

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program
NUREG-1801, Rev. 1 III B4-6 September 2005

This Page Intentionally Left Blank
September 2005 III B5-1 NUREG-1801, Rev. 1

B5. SUPPORTS FOR PLATFORMS, PIPE WHIP RESTRAINTS, JET IMPINGEMENT 

SHIELDS, MASONRY WALLS, AND OTHER MISCELLANEOUS STRUCTURES

Systems, Structures, and Components

This section addresses supports and anchorage for platforms, pipe whip restraints, jet 

impingement shields, masonry walls, and other miscellaneous structures. Applicable aging 

effects are identified and the aging management review is presented for each applicable 

combination of support component and aging effect.

System Interfaces

Physical interfaces exist with the structure, system, or component being supported and with the 

building structural element to which the support is anchored. A primary function of supports is to 

provide anchorage of the supported element for internal and external design basis events, so 

that the supported element can perform its intended function.
NUREG-1801, Rev. 1 III B5-2 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

B5 Supports for Platforms, Pipe Whip Restraints, Jet Impingement Shields, Masonry Walls, and Other Miscellaneous Structures

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.B5-1

(T-29)

III.B5.2-a Building 

concrete at 

locations of 

expansion 

and grouted 

anchors; grout 

pads for 

support base 

plates

Reinforced 

concrete;

Grout

Air – indoor 

uncontrolled or 

air – outdoor

Reduction in 

concrete anchor 

capacity due to 

local concrete 

degradation/ 

service-induced 

cracking or other 

concrete aging 

mechanisms

Chapter XI.S6, “Structures Monitoring 

Program”

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.B5-2

(TP-8)

III.B5. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Aluminum Air – indoor

uncontrolled

None None No

III.B5-3

(TP-11)

III.B5. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel

Air – indoor 

uncontrolled

None None No
September 2005 III B5-3 NUREG-1801, Rev. 1

III STRUCTURES AND COMPONENT SUPPORTS

B5 Supports for Platforms, Pipe Whip Restraints, Jet Impingement Shields, Masonry Walls, and Other Miscellaneous Structures

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.B5-4

(TP-3)

III.B5. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel, 

aluminum

Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

No

III.B5-5

(TP-5)

III.B5. Support 

members; 

welds; bolted 

connections;

support 

anchorage to 

building 

structure

Stainless 

steel

Air – indoor 

uncontrolled

None None No

III.B5-6

(TP-4)

III.B5. Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless 

steel

Air with borated 

water leakage

None None No
NUREG-1801, Rev. 1 III B5-4 September 2005

III STRUCTURES AND COMPONENT SUPPORTS

B5 Supports for Platforms, Pipe Whip Restraints, Jet Impingement Shields, Masonry Walls, and Other Miscellaneous Structures

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

III.B5-7

(T-30)

III.B5.1-a Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor 

uncontrolled or 

air – outdoor

Loss of material/ 

general and 

pitting corrosion

Chapter XI.S6, “Structures Monitoring 

Program”

Yes, if not 

within the 

scope of the 

applicant’s 

structures 

monitoring 

program

III.B5-8

(T-25)

III.B5.1-b Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air with borated 

water leakage

Loss of material/

boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

No
September 2005 IV-i NUREG-1801, Rev. 1

CHAPTER IV

REACTOR VESSEL, INTERNALS, AND REACTOR 

COOLANT SYSTEM 
NUREG-1801, Rev. 1 IV-ii September 2005

This Page Intentionally Left Blank
September 2005 IV-iii NUREG-1801, Rev. 1

MAJOR PLANT SECTIONS

A1. Reactor Vessel (Boiling Water Reactor)

A2. Reactor Vessel (Pressurized Water Reactor)

B1. Reactor Vessel Internals (Boiling Water Reactor)

B2. Reactor Vessel Internals (PWR) - Westinghouse

B3. Reactor Vessel Internals (PWR) - Combustion Engineering

B4. Reactor Vessel Internals (PWR) - Babcock and Wilcox

C1. Reactor Coolant Pressure Boundary (Boiling Water Reactor)

C2. Reactor Coolant System and Connected Lines (Pressurized Water Reactor)

D1. Steam Generator (Recirculating)

D2. Steam Generator (Once-Through)

E. Common Miscellaneous Material/Environment Combinations

 
NUREG-1801, Rev. 1 IV-iv September 2005

This Page Intentionally Left Blank
September 2005 IV A1-1 NUREG-1801, Rev. 1

A1. REACTOR VESSEL (BOILING WATER REACTOR)

Systems, Structures, and Components

This section addresses the boiling water reactor (BWR) pressure vessel and consists of the 

vessel shell and flanges, attachment welds, top and bottom heads, nozzles (including safe 

ends) for the reactor coolant recirculating system and connected systems (such as high and low 

pressure core spray, high and low pressure coolant injection, main steam, and feedwater 

systems), penetrations for control rod drive (CRD) stub tubes, instrumentation, standby liquid 

control, flux monitor, drain lines, and control rod drive mechanism housings. The support skirt 

and attachment welds for vessel supports are also included in the following table for the BWR 

vessel. Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for 

Water-, Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” all 

structures and components that comprise the reactor vessel are governed by Group A Quality 

Standards.

Common miscellaneous material/environment combinations where aging effects are not 

expected to degrade the ability of the structure or component to perform its intended function for 

the extended period of operation are included in IV.E.

System Interfaces

The systems that interface with the reactor vessel include the reactor vessel internals (IV.B1), 

the reactor coolant pressure boundary (IV.C1), the emergency core cooling system (V.D2), and 

standby liquid control system (VII.E2).
NUREG-1801, Rev. 1 IV.A1-2 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

A1 Reactor Vessel (BWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

IV.A1-1

(R-68)

IV.A1.4-a Nozzle safe ends 

(and associated 

welds)

High pressure 

core spray

Low pressure 

core spray

Control rod drive 

return line

Recirculating 

water

Low pressure 

coolant injection 

or RHR injection 

mode

Stainless 

steel; 

nickel alloy

Reactor coolant Cracking/ stress 

corrosion cracking 

and intergranular 

stress corrosion 

cracking

Chapter XI.M7, “BWR Stress Corrosion 

Cracking,” and

Chapter XI.M2, “Water Chemistry,” for 

BWR water

No

IV.A1-2

(R-66)

IV.A1.3-c Nozzles

Control rod drive 

return line

Steel (with 

or without 

stainless 

steel 

cladding)

Reactor coolant Cracking/ cyclic 

loading

Chapter XI.M6, “BWR Control Rod Drive 

Return Line Nozzle”

No

IV.A1-3

(R-65)

IV.A1.3-b Nozzles

Feedwater

Steel (with 

or without 

stainless 

steel 

cladding)

Reactor coolant Cracking/ cyclic 

loading

Chapter XI.M5, “BWR Feedwater 

Nozzle”

No
September 2005 IV.A1-3 NUREG-1801, Rev.1 

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

A1 Reactor Vessel (BWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

IV.A1-4

(R-67)

IV.A1.3-e Nozzles

Low pressure 

coolant injection 

or RHR injection 

mode

Steel Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ 

neutron irradiation 

embrittlement

Neutron irradiation embrittlement is a 

time-limited aging analysis (TLAA) to 

be evaluated for the period of extended 

operation for all ferritic materials that 

have a neutron fluence greater than 

1E17 n/cm2 (E >1 MeV) at the end of 

the license renewal term. In 

accordance with approved BWRVIP-74, 

the TLAA is to evaluate the impact of 

neutron embrittlement on: (a) the 

adjusted reference temperature values 

used for calculation of the plant’s 

pressure-temperature limits, (b) the 

need for inservice inspection of 

circumferential welds, and (c) the 

Charpy upper shelf energy or the 

equivalent margins analyses performed 

in accordance with 10 CFR Part 50, 

Appendix G The applicant may choose 

to demonstrate that the materials of the 

nozzles are not controlling for the TLAA 

evaluations. See the Standard Review 

Plan, Section 4.2 “Reactor Vessel 

Neutron Embrittlement” for acceptable 

methods for meeting the requirements 

of 10 CFR 54.21(c).

Yes,

TLAA
NUREG-1801, Rev. 1 IV.A1-4 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

A1 Reactor Vessel (BWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

IV.A1-5

(R-69)

IV.A1.5-a Penetrations

Control rod drive 

stub tubes 

Instrumentation

Jet pump 

instrument

Standby liquid 

control

Flux monitor

Drain line

Stainless 

steel; 

nickel alloy

Reactor coolant Cracking/ stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, cyclic 

loading

Chapter XI.M8, “BWR Penetrations,” 

and

Chapter XI.M2, “Water Chemistry,” for 

BWR water

No

IV.A1-6

(R-70)

IV.A1.7-a Pressure vessel 

support skirt and 

attachment welds

Steel Air – indoor 

uncontrolled

Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA
September 2005 IV.A1-5 NUREG-1801, Rev.1 

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

A1 Reactor Vessel (BWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

IV.A1-7

(R-04)

IV.A1.3-a 

IV.A1.3-d 

IV.A1.5-b 

IV.A1.2-a 

IV.A1.2-b 

IV.A1.2-b 

IV.A1.3-d 

IV.A1.4-b 

IV.A1.1-b 

IV.A1.5-b 

IV.A1.2-a 

IV.A1.5-b

IV.A1.5-b 

IV.A1.5-b 

IV.A1.6-a 

IV.A1.5-b 

IV.A1.2-b 

IV.A1.2-b

Reactor vessel 

components:

Flanges;

Nozzles;

Penetrations;

Safe ends;

Thermal sleeves;

Vessel shells, 

heads and welds 

Steel; 

stainless 

steel; steel 

with nickelalloy or 

stainless 

steel 

cladding; 

nickelalloy

Reactor coolant Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be performed for the period of 

extended operation, and, for Class 1 

components, environmental effects on 

fatigue are to be addressed. See the 

Standard Review Plan, Section 4.3 

“Metal Fatigue,” for acceptable 

methods for meeting the requirements 

of 10 CFR 54.21(c)(1).

Yes,

TLAA

IV.A1-8

(RP-25)

IV.A1. Reactor Vessel:

Flanges, nozzles; 

penetrations; safe 

ends; vessel 

shells, heads and 

welds

Stainless 

steel; steel 

with nickelalloy or 

stainless 

steel 

cladding; 

nickelalloy

Reactor Coolant Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter XI.M32, 

“One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
NUREG-1801, Rev. 1 IV.A1-6 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

A1 Reactor Vessel (BWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

IV.A1-9

(R-60)

IV.A1.1-c Top head 

enclosure

Closure studs 

and nuts

Highstrength 

low alloy 

steel

Maximum 

tensile 

strength < 

1172 MPa 

(<170 ksi)

Air with reactor 

coolant leakage

Cracking/ stress 

corrosion cracking 

and intergranular 

stress corrosion 

cracking

Chapter XI.M3, “Reactor Head Closure 

Studs”

No

IV.A1-10

(R-61)

IV.A1.1-d Top head 

enclosure

Vessel flange 

leak detection 

line

Stainless 

steel; 

nickel alloy

Air with reactor 

coolant leakage 

(Internal)

or

Reactor Coolant 

Cracking/ stress 

corrosion cracking 

and intergranular 

stress corrosion 

cracking

A plant-specific aging management 

program is to be evaluated because 

existing programs may not be capable 

of mitigating or detecting crack 

initiation and growth due to SCC in the 

vessel flange leak detection line.

Yes, plantspecific

IV.A1-11

(R-59)

IV.A1.1-a Top head 

enclosure (without 

cladding)

Top head

Nozzles (vent, 

top head spray 

or RCIC, and 

spare)

Steel Reactor coolant Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water 

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter XI.M32, 

“One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

IV.A1-12

(R-64)

IV.A1.2-e Vessel shell

Attachment 

welds

Stainless 

steel; 

nickel alloy

Reactor coolant Cracking/ stress 

corrosion cracking 

and intergranular 

stress corrosion 

cracking

Chapter XI.M4, “BWR Vessel ID 

Attachment Welds,” and

Chapter XI.M2, “Water Chemistry,” for 

BWR water

No
September 2005 IV.A1-7 NUREG-1801, Rev.1 

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

A1 Reactor Vessel (BWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

IV.A1-13

(R-62)

IV.A1.2-c Vessel shell

Intermediate 

beltline shell

Beltline welds

Steel (with 

or without 

stainless 

steel 

cladding)

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ 

neutron irradiation 

embrittlement

Neutron irradiation embrittlement is a 

time dependent aging mechanism to be 

evaluated for the period of extended 

operation for all ferritic materials that 

have a neutron fluence greater than 

1E17 n/cm2 (E >1 MeV) at the end of 

the license renewal term. Aspects of 

this evaluation may involve a TLAA. In 

accordance with approved BWRVIP-74, 

the TLAA is to evaluate the impact of 

neutron embrittlement on: (a) the 

adjusted reference temperature values 

used for calculation of the plant’s 

pressure-temperature limits, (b) the 

need for inservice inspection of 

circumferential welds, and (c) the 

Charpy upper shelf energy or the 

equivalent margins analyses performed 

in accordance with 10 CFR Part 50, 

Appendix G. Additionally, the applicant 

is to monitor axial beltline weld 

embrittlement. One acceptable method 

is to determine that the mean RTNDT of 

the axial beltline welds at the end of the 

extended period of operation is less 

than the value specified by the staff in 

its March 7, 2000 letter (ADAMS 

ML031430372). See the Standard 

Review Plan, Section 4.2 “Reactor 

Vessel Neutron Embrittlement” for 

acceptable methods for meeting the 

requirements of 10 CFR 54.21(c).

Yes,

TLAA
NUREG-1801, Rev. 1 IV.A1-8 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

A1 Reactor Vessel (BWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging Management Program (AMP) Further Evaluation

IV.A1-14

(R-63)

IV.A1.2-d Vessel shell

Intermediate 

beltline shell

Beltline welds

Steel (with 

or without 

stainless 

steel 

cladding)

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ 

neutron irradiation 

embrittlement

Chapter XI.M31, “Reactor Vessel 

Surveillance”

No
September 2005 IV.A2-1 NUREG-1801, Rev. 1

A2. REACTOR VESSEL (PRESSURIZED WATER REACTOR)

Systems, Structures, and Components

This section addresses the pressurized water reactor (PWR) vessel pressure boundary and

consists of the vessel shell and flanges, the top closure head and bottom head, the control rod 

drive (CRD) mechanism housings, nozzles (including safe ends) for reactor coolant inlet and 

outlet lines and safety injection, and penetrations through either the closure head or bottom head 

domes for instrumentation and leakage monitoring tubes. Attachments to the vessel such as 

core support pads, as well as pressure vessel support and attachment welds, are also included 

in the table. Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for 

Water-, Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” all 

systems, structures, and components that comprise the reactor coolant system are governed 

by Group A Quality Standards. 

Common miscellaneous material/environment combinations where aging effects are not 

expected to degrade the ability of the structure or component to perform its intended function for 

the extended period of operation are included in IV.E.

System Interfaces

The systems that interface with the PWR reactor vessel include the reactor vessel internals 

(IV.B2, IV.B3, and IV.B4, respectively, for Westinghouse, Combustion Engineering, and Babcock

and Wilcox designs), the reactor coolant system and connected lines (IV.C2), and the 

emergency core cooling system (V.D1).
NUREG-1801, Rev. 1 IV.A2-2 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

A2 Reactor Vessel (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.A2-1

(RP-13)

IV.A2. Bottommounted guide 

tube

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

IV.A2-2

(R-71)

IV.A2.1-c Closure head

Stud assembly

High-strength 

low alloy 

steel

Maximum 

tensile 

strength < 

1172 MPa 

(<170 ksi)

Air with reactor 

coolant leakage

Cracking/ stress 

corrosion cracking

Chapter XI.M3, “Reactor Head Closure 

Studs”

No

IV.A2-3

(R-72)

IV.A2.1-d Closure head

Stud assembly

High-strength 

low alloy 

steel

Maximum 

tensile 

strength < 

1172 MPa 

(<170 ksi)

Air with reactor 

coolant leakage

Loss of material/ 

wear

Chapter XI.M3, “Reactor Head Closure 

Studs”

No

IV.A2-4

(R-73)

IV.A2.1-e Closure head

Stud assembly

Low alloy 

steel

Air with reactor 

coolant leakage

Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA
September 2005 IV.A2-3 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

A2 Reactor Vessel (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.A2-5

(R-74)

IV.A2.1-f Closure head

Vessel flange 

leak detection 

line

Stainless 

steel

Air with reactor 

coolant leakage 

(Internal)

or

Reactor Coolant 

Cracking/ stress 

corrosion cracking

A plant-specific aging management 

program is to be evaluated because 

existing programs may not be capable 

of mitigating or detecting crack 

initiation and growth due to SCC in the 

vessel flange leak detection line.

Yes, plantspecific

IV.A2-6

(R-78)

IV.A2.2-e Control rod drive 

head 

penetration

Flange bolting

Stainless 

steel

Air with reactor 

coolant leakage

Cracking/ stress 

corrosion cracking

Chapter XI.M18, “Bolting Integrity” No

IV.A2-7

(R-79)

IV.A2.2-f Control rod drive 

head 

penetration

Flange bolting

Stainless 

steel

Air with reactor 

coolant leakage

Loss of material/ 

wear

Chapter XI.M18, “Bolting Integrity” No

IV.A2-8

(R-80)

IV.A2.2-g Control rod drive 

head 

penetration

Flange bolting

Stainless 

steel

Air with reactor 

coolant leakage

Loss of preload/ 

thermal effects, 

gasket creep, and 

self-loosening 

Chapter XI.M18, “Bolting Integrity” No
NUREG-1801, Rev. 1 IV.A2-4 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

A2 Reactor Vessel (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.A2-9

(R-75)

IV.A2.2-a Control rod drive 

head 

penetration

Nozzle and 

welds

Nickel alloy Reactor coolant Cracking/ primary 

water stress 

corrosion cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components and Chapter XI.M2, “Water 

Chemistry,” for PWR primary water and 

Chapter XI.M11-A, "Nickel-Alloy 

Penetration Nozzles Welded to the 

Upper Reactor Vessel Closure Heads 

of Pressurized Water Reactors (PWRs 

Only)"

No

IV.A2-10

(R-77)

IV.A2.2-d Control rod drive 

head 

penetration

Pressure 

housing

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C (>482°F)

Loss of fracture 

toughness/ 

thermal aging 

embrittlement

Chapter XI.M12, “Thermal Aging 

Embrittlement of Cast Austenitic 

Stainless Steel (CASS)”

No

IV.A2-11

(R-76)

IV.A2.2-b Control rod drive 

head 

penetration

Pressure 

housing

Stainless 

steel; nickel 

alloy

Reactor coolant Cracking/ stress

corrosion 

cracking, primary 

water stress 

corrosion cracking

Chapter XI.M2, “Water Chemistry,” and

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD" and,

For nickel alloy, comply with applicable 

NRC Orders and provide a commitment 

in the FSAR supplement to submit a 

plant-specific AMP to implement 

applicable (1) Bulletins and Generic 

Letters and (2) staff-accepted industry 

guidelines.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV.A2-5 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

A2 Reactor Vessel (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.A2-12

(R-88)

IV.A2.6-a Core support 

pads/ core 

guide lugs

Nickel alloy Reactor coolant Cracking/ primary 

water stress 

corrosion cracking

Chapter XI.M2, “Water Chemistry,” and

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD" and,

Comply with applicable NRC Orders 

and provide a commitment in the FSAR 

supplement to submit a plant-specific 

AMP to implement applicable (1) 

Bulletins and Generic Letters and (2) 

staff-accepted industry guidelines.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.A2-13

(R-17)

IV.A2.8-b 

IV.A2.5-e 

IV.A2.1-a

External 

surfaces

Steel Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid Corrosion” No

IV.A2-14

(RP-28)

IV.A2. Flanges; 

nozzles; 

penetrations; 

pressure 

housings; safe 

ends; vessel 

shells, heads 

and welds

Stainless 

steel; steel 

with nickelalloy or 

stainless 

steel 

cladding; 

nickel-alloy

Reactor Coolant Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No

IV.A2-15

(R-83)

IV.A2.4-b Nozzle safe 

ends and welds:

Inlet

Outlet

Safety 

injection

Stainless 

steel; nickel 

alloy welds 

and/or 

buttering

Reactor coolant Cracking/ stress 

corrosion 

cracking, primary 

water stress 

corrosion cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No
NUREG-1801, Rev. 1 IV.A2-6 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

A2 Reactor Vessel (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.A2-16

(R-81)

IV.A2.3-a Nozzles

Inlet

Outlet

Safety 

injection

Steel with 

stainless 

steel 

cladding

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ 

neutron irradiation 

embrittlement

Neutron irradiation embrittlement is a 

time-limited aging analysis (TLAA) to 

be evaluated for the period of extended 

operation for all ferritic materials that 

have a neutron fluence greater than 

1E17 n/cm2 (E >1 MeV) at the end of 

the license renewal term. The TLAA is 

to evaluate the impact of neutron 

embrittlement on: (a) the RTPTS value 

based on the requirements in 10 CFR 

50.61, (b) the adjusted reference 

temperature values used for calculation 

of the plant’s pressure-temperature 

limits, and (c) the Charpy upper shelf 

energy or the equivalent margins 

analyses performed in accordance with 

10 CFR Part 50, Appendix G 

requirements. The applicant may 

choose to demonstrate that the 

materials in the inlet, outlet, and safety 

injection nozzles are not controlling for 

the TLAA evaluations.

Yes,

TLAA

IV.A2-17

(R-82)

IV.A2.3-b Nozzles

Inlet

Outlet

Safety 

injection

Steel with 

stainless 

steel 

cladding

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ 

neutron irradiation 

embrittlement

Chapter XI.M31, “Reactor Vessel 

Surveillance”

No
September 2005 IV.A2-7 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

A2 Reactor Vessel (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.A2-18

(R-90)

IV.A2.7-b Penetrations

Head vent pipe 

(top head)

Instrument 

tubes (top 

head)

Nickel alloy Reactor coolant Cracking/ primary 

water stress 

corrosion cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components and Chapter XI.M2, “Water 

Chemistry,” for PWR primary water and 

Chapter XI.M11-A, "Nickel-Alloy 

Penetration Nozzles Welded to the 

Upper Reactor Vessel Closure Heads 

of Pressurized Water Reactors (PWRs 

Only)"

No

IV.A2-19

(R-89)

IV.A2.7-a Penetrations

Instrument 

tubes (bottom 

head)

Nickel alloy Reactor coolant Cracking/ primary 

water stress 

corrosion cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD” for Class 1 

components, and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water and

Comply with applicable NRC Orders 

and provide a commitment in the FSAR 

supplement to implement applicable (1) 

Bulletins and Generic Letters and (2) 

staff-accepted industry guidelines.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.A2-20

(R-70)

IV.A2.8-a Pressure vessel 

support skirt 

and attachment 

welds

Steel Air – indoor 

uncontrolled

Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA
NUREG-1801, Rev. 1 IV.A2-8 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

A2 Reactor Vessel (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.A2-21

(R-219)

IV.A2.3-c 

IV.A2.5-d 

IV.A2.4-a 

IV.A2.4-a 

IV.A2.4-a 

IV.A2.3-c 

IV.A2.5-d 

IV.A2.2-c 

IV.A2.1-b 

IV.A2.5-d 

IV.A2.5-d 

IV.A2.3-c 

IV.A2.2-c

Reactor vessel 

components:

Flanges;

Nozzles;

Penetrations;

Pressure 

housings;

Safe ends;

Thermal 

sleeves;

Vessel shells, 

heads and 

welds 

Steel; 

stainless 

steel; steel 

with nickelalloy or 

stainless 

steel 

cladding; 

nickel-alloy

Reactor coolant Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be performed for the period of 

extended operation, and, for Class 1 

components, environmental effects on 

fatigue are to be addressed. See the 

Standard Review Plan, Section 4.3 

“Metal Fatigue,” for acceptable 

methods for meeting the requirements 

of 10 CFR 54.21(c)(1).

Yes,

TLAA
September 2005 IV.A2-9 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

A2 Reactor Vessel (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.A2-22

(R-85)

IV.A2.5-b Vessel shell

Upper shell

Intermediate 

and lower shell

(including 

beltline welds)

SA508-Cl 2 

forgings clad 

with 

stainless 

steel using a 

high-heatinput welding 

process

Reactor coolant Crack growth/ 

cyclic loading

Growth of intergranular separations 

(underclad cracks) in low-alloy steel 

forging heat affected zone under 

austenitic stainless steel cladding is a 

time-limited aging analysis (TLAA) to 

be evaluated for the period of extended 

operation for all the SA 508-Cl 2 

forgings where the cladding was 

deposited with a high heat input 

welding process. The methodology for 

evaluating an underclad flaw is in 

accordance with the current wellestablished flaw evaluation procedure 

and criterion in the ASME Section XI 

Code. See the Standard Review Plan, 

Section 4.7, “Other Plant-Specific 

Time-Limited Aging Analysis,” for 

generic guidance for meeting the 

requirements of 10 CFR 54.21(c).

Yes,

TLAA
NUREG-1801, Rev. 1 IV.A2-10 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

A2 Reactor Vessel (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.A2-23

(R-84)

IV.A2.5-a Vessel shell

Upper shell

Intermediate 

and lower shell

(including 

beltline welds)

Steel with 

stainless 

steel 

cladding

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ 

neutron irradiation 

embrittlement

Neutron irradiation embrittlement is a 

time-limited aging analysis (TLAA) to 

be evaluated for the period of extended 

operation for all ferritic materials that 

have a neutron fluence greater than 

1E17 n/cm2 (E >1 MeV) at the end of 

the license renewal term. The TLAA is 

to evaluate the impact of neutron 

embrittlement on: (a) the RTPTS value 

based on the requirements in 10 CFR 

50.61, (b) the adjusted reference 

temperature values used for calculation 

of the plant’s pressure-temperature 

limits, and (c) the Charpy upper shelf 

energy or the equivalent margins 

analyses performed in accordance with 

10 CFR Part 50, Appendix G 

requirements. See the Standard Review 

Plan, Section 4.2 “Reactor Vessel 

Neutron Embrittlement” for acceptable 

methods for meeting the requirements 

of 10 CFR 54.21(c).

Yes,

TLAA
September 2005 IV.A2-11 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

A2 Reactor Vessel (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.A2-24

(R-86)

IV.A2.5-c Vessel shell

Upper shell

Intermediate 

and lower shell

(including 

beltline welds)

Steel with 

stainless 

steel 

cladding

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ 

neutron irradiation 

embrittlement

Chapter XI.M31, “Reactor Vessel 

Surveillance”

No

IV.A2-25

(R-87)

IV.A2.5-f Vessel shell

Vessel flange

Steel Reactor coolant Loss of material/ 

wear

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components

No
NUREG-1801, Rev. 1 IV A2-12 September 2005

This Page Intentionally Left Blank
September 2005 IV B1-1 NUREG-1801, Rev. 1

B1. REACTOR VESSEL INTERNALS (BOILING WATER REACTOR)

Systems, Structures, and Components

This section addresses the boiling water reactor (BWR) vessel internals and consists of the 

core shroud (including repairs) and core plate, the top guide, feedwater spargers, core spray 

lines and spargers, jet pump assemblies, fuel supports and control rod drive (CRD), and 

instrument housings, such as the intermediate range monitor (IRM) dry tubes, the low power 

range monitor (LPRM) dry tubes, and the source range monitor (SRM) dry tubes. Based on 

Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, Steam-, and

Radioactive-Waste-Containing Components of Nuclear Power Plants,” all structures and 

components that comprise the reactor vessel are governed by Group A or B Quality Standards.

 

Common miscellaneous material/environment combinations where aging effects are not

expected to degrade the ability of the structure or component to perform its intended function for 

the extended period of operation are included in IV.E.

System Interfaces

The systems that interface with the reactor vessel internals include the reactor pressure vessel 

(IV.A1) and the reactor coolant pressure boundary (IV.C1).
NUREG-1801, Rev. 1 IV B1-2 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B1 Reactor Vessel Internals (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B1-1

(R-92)

IV.B1.1-a Core shroud 

(including 

repairs) and 

core plate

Core shroud 

(upper, 

central, lower)

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

intergranular 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M9, “BWR Vessel Internals,” 

for core shroud and

Chapter XI.M2, “Water Chemistry” for 

BWR water

No

IV.B1-2

(R-96)

IV.B1.1-f Core shroud 

(including 

repairs) and 

core plate

Shroud 

support 

structure 

(shroud 

support 

cylinder, 

shroud support 

plate, shroud 

support legs)

Nickel alloy Reactor coolant Cracking/ stress 

corrosion cracking, 

intergranular 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M9, “BWR Vessel Internals,” 

for shroud support and

Chapter XI.M2, “Water Chemistry,” for 

BWR water

No

IV.B1-3

(R-97)

IV.B1.1-g Core shroud 

and core plate

 LPCI coupling

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

intergranular 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M9, “BWR Vessel Internals,” 

for the LPCI coupling and

Chapter XI.M2, “Water Chemistry,” for 

BWR water

No
September 2005 IV B1-3 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B1 Reactor Vessel Internals (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B1-4

(R-95)

IV.B1.1-e Core shroud 

and core plate

Access hole 

cover

(mechanical 

covers)

Nickel alloy Reactor coolant Cracking/ stress 

corrosion cracking, 

intergranular 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components and

Chapter XI.M2, “Water Chemistry,” for 

BWR water

No

IV.B1-5

(R-94)

IV.B1.1-d Core shroud 

and core plate

Access hole 

cover

(welded

covers)

Nickel alloy Reactor coolant Cracking/ stress 

corrosion cracking, 

intergranular 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components and Chapter XI.M2, “Water 

Chemistry,” for BWR water

Because cracking initiated in crevice 

regions is not amenable to visual 

inspection, for BWRs with a crevice in 

the access hole covers, an augmented 

inspection is to include ultrasonic 

testing (UT) or other demonstrated 

acceptable inspection of the access 

hole cover welds.

No

IV.B1-6

(R-93)

IV.B1.1-b Core shroud 

and core plate

Core plate

Core plate 

bolts (used in 

early BWRs)

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

intergranular 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M9, “BWR Vessel Internals,” 

for core plate and

Chapter XI.M2, “Water Chemistry” for 

BWR water

No
NUREG-1801, Rev. 1 IV B1-4 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B1 Reactor Vessel Internals (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B1-7

(R-99)

IV.B1.3-a Core spray lines 

and spargers

Core spray 

lines (headers)

Spray rings

Spray nozzles

Thermal 

sleeves

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

intergranular 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M9, “BWR Vessel Internals,” 

for core spray internals and

Chapter XI.M2, “Water Chemistry,” for 

BWR water

No

IV.B1-8

(R-104)

IV.B1.5-c Fuel supports 

and control rod 

drive 

assemblies

Control rod 

drive housing

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking 

and intergranular 

stress corrosion 

cracking

Chapter XI.M9, “BWR Vessel Internals,” 

for lower plenum and

Chapter XI.M2, “Water Chemistry,” for 

BWR water

No

IV.B1-9

(R-103)

IV.B1.5-a Fuel supports 

and control rod 

drive 

assemblies

Orificed fuel 

support

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C (>482°F) 

and neutron flux

Loss of fracture 

toughness/ 

thermal aging and 

neutron irradiation 

embrittlement

Chapter XI.M13, “Thermal Aging and 

Neutron Irradiation Embrittlement of 

Cast Austenitic Stainless Steel 

(CASS)”

No
September 2005 IV B1-5 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B1 Reactor Vessel Internals (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B1-10

(R-105)

IV.B1.6-a Instrumentation

Intermediate 

range monitor 

(IRM) dry 

tubes

Source range 

monitor (SRM) 

dry tubes

Incore neutron 

flux monitor 

guide tubes

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

intergranular 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M9, “BWR Vessel Internals,” 

for lower plenum and

Chapter XI.M2, “Water Chemistry,” for 

BWR water

No

IV.B1-11

(R-101)

IV.B1.4-c Jet pump 

assemblies

Castings

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C (>482°F) 

and neutron flux

Loss of fracture 

toughness/ 

thermal aging and 

neutron irradiation 

embrittlement

Chapter XI.M13, “Thermal Aging and 

Neutron Irradiation Embrittlement of 

Cast Austenitic Stainless Steel 

(CASS)”

No

IV.B1-12

(R-102)

IV.B1.4-d Jet pump 

assemblies

Jet pump 

sensing line

Stainless 

steel

Reactor coolant Cracking/ cyclic 

loading

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific
NUREG-1801, Rev. 1 IV B1-6 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B1 Reactor Vessel Internals (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B1-13

(R-100)

IV.B1.4-a Jet pump 

assemblies

Thermal sleeve

Inlet header

Riser brace 

arm

Holddown 

beams

Inlet elbow

Mixing 

assembly

Diffuser

Castings

Nickel alloy; 

stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

intergranular 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M9, “BWR Vessel Internals,” 

for jet pump assembly and

Chapter XI.M2, “Water Chemistry,” for 

BWR water

No

IV.B1-14

(R-53)

IV.B1.6-b 

IV.B1.3-b 

IV.B1.4-b 

IV.B1.2-b 

IV.B1.5-b 

IV.B1.1-c

Reactor vessel 

internals 

components

Stainless 

steel; nickel 

alloy

Reactor coolant Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA

IV.B1-15

(RP-26)

IV.B1. Reactor vessel 

internals 

components

Stainless 

steel; nickel 

alloy

Reactor coolant Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components and Chapter XI.M2, “Water 

Chemistry” for BWR water

No

IV.B1-16

(RP-18)

IV.B1. Steam Dryers Stainless 

steel

Reactor coolant Cracking/ flowinduced vibrationA plant-specific aging management 

program is to be evaluated.

Yes, plantspecific
September 2005 IV B1-7 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B1 Reactor Vessel Internals (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B1-17

(R-98)

IV.B1.2-a Top guide Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

intergranular 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M9, “BWR Vessel Internals,” 

for top guide and Chapter XI.M2, “Water 

Chemistry,” for BWR water. 

Additionally, for top guides with neutron 

fluence exceeding the IASCC threshold 

(5E20, E>lMeV) prior to the period of 

extended operation, inspect five percent 

(5%) of the top guide locations using 

enhanced visual inspection technique, 

EVT-1 within six years after entering 

the period of extended operation. An 

additional 5% of the top guide locations 

will be inspected within twelve years 

after entering the period of extended 

operation.

Alternatively, if the neutron fluence for 

the limiting top guide location is 

projected to exceed the threshold for 

IASCC after entering the period of 

extended operation, inspect 5% of the 

top guide locations (EVT-1) within six 

years after the date projected for 

exceeding the threshold. An additional 

5% of the top guide locations will be 

inspected within twelve years after the 

date projected for exceeding the 

threshold.

The top guide inspection locations are 

those that have high neutron fluences 

exceeding the IASCC threshold.

No
NUREG-1801, Rev. 1 IV B1-8 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B1 Reactor Vessel Internals (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

The extent and frequency of 

examination of the top guide is similar 

to the examination of the control rod 

drive housing guide tube in BWRVIP47.
September 2005 IV B2-1 NUREG-1801, Rev. 1

B2. REACTOR VESSEL INTERNALS (PWR) - WESTINGHOUSE

Systems, Structures, and Components

This section addresses the Westinghouse pressurized water reactor (PWR) vessel internals 

and consists of the upper internals assembly, the rod control cluster assemblies (RCCA) guide 

tube assemblies, the core barrel, the baffle/former assembly, the lower internal assembly, and 

the instrumentation support structures. Based on Regulatory Guide 1.26, “Quality Group 

Classifications and Standards for Water-, Steam-, and Radioactive-Waste-Containing 

Components of Nuclear Power Plants,” all structures and components that comprise the 

reactor vessel are governed by Group A or B Quality Standards. 

Common miscellaneous material/environment combinations where aging effects are not 

expected to degrade the ability of the structure or component to perform its intended function for 

the extended period of operation are included in IV.E.

System Interfaces

The systems that interface with the reactor vessel internals include the reactor pressure vessel 

(IV.A2).
NUREG-1801, Rev. 1 IV B2-2 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-1

(R-124)

IV.B2.4-b Baffle/former 

assembly

Baffle and 

former plates

Stainless 

steel

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B2-3 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-2

(R-123)

IV.B2.4-a Baffle/former 

assembly

Baffle and 

former plates

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B2-4 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-3

(R-127)

IV.B2.4-e Baffle/former 

assembly

Baffle and 

former plates

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ neutron 

irradiation 

embrittlement, void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B2-4

(R-126)

IV.B2.4-d Baffle/former 

assembly

Baffle/former 

bolts

Stainless 

steel

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B2-5 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-5

(R-129)

IV.B2.4-h Baffle/former 

assembly

Baffle/former 

bolts

Stainless 

steel

Reactor coolant Loss of preload/ 

stress relaxation

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B2-6

(R-128)

IV.B2.4-f Baffle/former 

assembly

Baffle/former 

bolts and 

screws

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ neutron 

irradiation 

embrittlement, void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B2-6 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-7

(R-121)

IV.B2.3-b Core barrel

Core barrel 

(CB)

CB flange 

(upper)

CB outlet 

nozzles

Thermal shield

Stainless 

steel

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B2-7 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-8

(R-120)

IV.B2.3-a Core barrel

Core barrel 

(CB)

CB flange 

(upper)

CB outlet 

nozzles

Thermal shield

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B2-8 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-9

(R-122)

IV.B2.3-c Core barrel

Core barrel 

(CB)

CB flange 

(upper)

CB outlet 

nozzles

Thermal shield

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ neutron 

irradiation 

embrittlement, void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B2-9 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-10

(R-125)

IV.B2.4-c Core barrel 

assembly

Baffle/former 

assembly

Baffle/former 

bolts and 

screws

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry," for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B2-10 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-11

(R-144)

IV.B2.6-b Instrumentation 

support 

structures

Flux thimble 

guide tubes

Stainless 

steel

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee

commitment 

needs to be 

confirmed
September 2005 IV B2-11 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-12

(R-143)

IV.B2.6-a Instrumentation 

support 

structures

Flux thimble 

guide tubes

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B2-13

(R-145)

IV.B2.6-c Instrumentation 

support 

structures

Flux thimble 

tubes

Stainless 

steel with or 

without 

chrome 

plating

Reactor coolant Loss of material/ 

wear

Chapter XI.M37, “Flux Thimble Tube 

Inspection"

No
NUREG-1801, Rev. 1 IV B2-12 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-14

(R-137)

IV.B2.5-i Lower internal 

assembly

Clevis insert 

bolts

Stainless 

steel; nickel 

alloy

Reactor coolant Loss of preload/ 

stress relaxation

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B2-15

(R-134)

IV.B2.5-f Lower internal 

assembly

Fuel alignment 

pins

Lower support 

plate column 

bolts

Clevis insert 

bolts

Stainless 

steel; nickel 

alloy

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B2-13 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-16

(R-133)

IV.B2.5-e Lower internal 

assembly

Fuel alignment 

pins

Lower support 

plate column 

bolts

Clevis insert 

bolts

Stainless 

steel; nickel 

alloy

Reactor coolant Cracking/ stress 

corrosion cracking, 

primary water 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B2-14 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-17

(R-135)

IV.B2.5-g Lower internal 

assembly

Fuel alignment 

pins

Lower support 

plate column 

bolts

Clevis insert 

bolts

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ neutron 

irradiation 

embrittlement, void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B2-18

(R-132)

IV.B2.5-c Lower internal 

assembly

Lower core 

plate

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ neutron 

irradiation 

embrittlement, void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B2-15 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-19

(R-131)

IV.B2.5-b Lower internal 

assembly

Lower core 

plate

Radial keys 

and clevis 

inserts

Stainless 

steel; nickel 

alloy

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B2-16 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-20

(R-130)

IV.B2.5-a Lower internal 

assembly

Lower core 

plate

Radial keys 

and clevis 

inserts

Stainless 

steel; nickel 

alloy

Reactor coolant Cracking/ stress 

corrosion cracking, 

primary water 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B2-21

(R-140)

IV.B2.5-m Lower internal 

assembly

Lower support 

casting

Lower support 

plate columns

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C (>482°F) 

and neutron flux

Loss of fracture 

toughness/ thermal 

aging and neutron 

irradiation 

embrittlement

Chapter XI.M13, “Thermal Aging and 

Neutron Irradiation Embrittlement of 

Cast Austenitic Stainless Steel 

(CASS)”

No
September 2005 IV B2-17 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-22

(R-141)

IV.B2.5-n Lower internal 

assembly

Lower support 

forging

Lower support 

plate columns

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ neutron 

irradiation 

embrittlement, void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B2-23

(R-139)

IV.B2.5-l Lower internal 

assembly

Lower support 

forging or 

casting

Lower support 

plate columns

Stainless 

steel

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B2-18 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-24

(R-138)

IV.B2.5-k Lower internal 

assembly

Lower support 

forging or 

casting

Lower support 

plate columns

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B2-19 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-25

(R-136)

IV.B2.5-h Lower internal 

assembly

Lower support 

plate column 

bolts

Stainless 

steel; nickel 

alloy

Reactor coolant Loss of preload/ 

stress relaxation

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B2-26

(R-142)

IV.B2.5-o Lower internal 

assembly

Radial keys 

and clevis 

Inserts

Stainless 

steel

Reactor coolant Loss of material/ 

wear

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components

No
NUREG-1801, Rev. 1 IV B2-20 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-27

(R-119)

IV.B2.2-e RCCA guide 

tube assemblies

RCCA guide 

tube bolts

RCCA guide 

tube support 

pins

Stainless 

steel; nickel 

alloy

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B2-21 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-28

(R-118)

IV.B2.2-d RCCA guide 

tube assemblies

RCCA guide 

tube bolts

RCCA guide 

tube support 

pins

Stainless 

steel; nickel 

alloy

Reactor coolant Cracking/ stress 

corrosion cracking, 

primary water 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B2-22 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-29

(R-117)

IV.B2.2-b RCCA guide 

tube assemblies

RCCA guide 

tubes

Stainless 

steel

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B2-23 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-30

(R-116)

IV.B2.2-a RCCA guide 

tube assemblies

RCCA guide 

tubes

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B2-31

(R-53)

IV.B2.1-m 

IV.B2.2-f 

IV.B2.1-c 

IV.B2.2-c 

IV.B2.3-d 

IV.B2.4-g 

IV.B2.5-p 

IV.B2.5-j 

IV.B2.5-d 

IV.B2.1-h

Reactor vessel 

internals 

components

Stainless 

steel; nickel 

alloy

Reactor coolant Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA
NUREG-1801, Rev. 1 IV B2-24 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-32

(RP-24)

IV.B2. Reactor vessel 

internals 

components

Stainless 

steel; nickel 

alloy

Reactor coolant Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No

IV.B2-33

(R-108)

IV.B2.1-d Upper internals 

assembly

Hold-down 

spring

Stainless 

steel

Reactor coolant Loss of preload/ 

stress relaxation

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B2-34

(R-115)

IV.B2.1-l Upper internals 

assembly

Upper core 

plate 

alignment pins

Stainless 

steel; nickel 

alloy

Reactor coolant Loss of material/ 

wear

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components

No
September 2005 IV B2-25 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-35

(R-110)

IV.B2.1-f Upper internals 

assembly

Upper support 

column

Stainless 

steel

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B2-26 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-36

(R-109)

IV.B2.1-e Upper internals 

assembly

Upper support 

column

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B2-37

(R-111)

IV.B2.1-g Upper internals 

assembly

Upper support 

column

(only cast 

austenitic 

stainless steel 

portions)

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C (>482°F) 

and neutron flux

Loss of fracture 

toughness/ thermal 

aging and neutron 

irradiation 

embrittlement

Chapter XI.M13, “Thermal Aging and 

Neutron Irradiation Embrittlement of 

Cast Austenitic Stainless Steel 

(CASS)”

No
September 2005 IV B2-27 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-38

(R-114)

IV.B2.1-k Upper internals 

assembly

Upper support 

column bolts

Stainless 

steel; nickel 

alloy

Reactor coolant Loss of preload/ 

stress relaxation

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B2-39

(R-113)

IV.B2.1-j Upper internals 

assembly

Upper support 

column bolts 

Upper core 

plate 

alignment pins

Fuel alignment 

pins

Stainless 

steel; nickel 

alloy

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B2-28 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-40

(R-112)

IV.B2.1-i Upper internals 

assembly

Upper support 

column bolts 

Upper core 

plate 

alignment pins

Fuel alignment 

pins

Stainless 

steel; nickel 

alloy

Reactor coolant Cracking/ stress 

corrosion cracking, 

primary water 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B2-29 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-41

(R-107)

IV.B2.1-b Upper internals 

assembly

Upper support 

plate

Upper core 

plate

Hold-down 

spring

Stainless 

steel

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B2-30 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B2 Reactor Vessel Internals (PWR) - Westinghouse

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B2-42

(R-106)

IV.B2.1-a Upper internals 

assembly

Upper support 

plate

Upper core 

plate

Hold-down 

spring

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B3-1 NUREG-1801, Rev. 1

B3. REACTOR VESSEL INTERNALS (PWR) - COMBUSTION ENGINEERING

Systems, Structures, and Components

This section addresses the Combustion Engineering pressurized water reactor (PWR) vessel 

internals and consists of the upper internals assembly, the control element assembly (CEA),

shroud assemblies, the core support barrel, the core shroud assembly, and the lower internal 

assembly. Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for

Water-, Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” all 

structures and components that comprise the reactor vessel are governed by Group A or B 

Quality Standards. 

Common miscellaneous material/environment combinations where aging effects are not 

expected to degrade the ability of the structure or component to perform its intended function for 

the extended period of operation are included in IV.E.

System Interfaces

The systems that interface with the reactor vessel internals include the reactor pressure vessel

(IV.A2).
NUREG-1801, Rev. 1 IV B3-2 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B3 Reactor Vessel Internals (PWR) - Combustion Engineering

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B3-1

(R-153)

IV.B3.2-e CEA shroud 

assemblies

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C (>482°F) 

and neutron flux

Loss of fracture 

toughness/ thermal 

aging and neutron 

irradiation 

embrittlement

Chapter XI.M13, “Thermal Aging and 

Neutron Irradiation Embrittlement of 

Cast Austenitic Stainless Steel 

(CASS)”

No

IV.B3-2

(R-149)

IV.B3.2-a CEA shroud 

assemblies

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B3-3

(R-152)

IV.B3.2-d CEA shroud 

assemblies

CEA shroud 

extension 

shaft guides

Stainless 

steel

Reactor coolant Loss of material/ 

wear

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 components

No
September 2005 IV B3-3 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B3 Reactor Vessel Internals (PWR) - Combustion Engineering

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B3-4

(R-151)

IV.B3.2-c CEA shroud 

assemblies

CEA shrouds 

bolts

Stainless 

steel; nickel 

alloy

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B3-4 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B3 Reactor Vessel Internals (PWR) - Combustion Engineering

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B3-5

(R-150)

IV.B3.2-b CEA shroud 

assemblies

CEA shrouds 

bolts

Stainless 

steel; nickel 

alloy

Reactor coolant Cracking/ stress 

corrosion cracking, 

primary water 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water. No further aging 

management review is necessary if the 

applicant provides a commitment in the 

FSAR supplement to (1) participate in 

the industry programs for investigating 

and managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B3-5 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B3 Reactor Vessel Internals (PWR) - Combustion Engineering

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B3-6

(R-154)

IV.B3.2-g CEA shroud 

assemblies

CEA shrouds 

bolts

Stainless 

steel; nickel 

alloy

Reactor coolant Loss of preload/ 

stress relaxation

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B3-7

(R-165)

IV.B3.4-h Core shroud 

assembly

Core shroud 

assembly 

bolts

Core shroud 

tie rods

Stainless 

steel; nickel 

alloy

Reactor coolant Loss of preload/ 

stress relaxation

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B3-6 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B3 Reactor Vessel Internals (PWR) - Combustion Engineering

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B3-8

(R-163)

IV.B3.4-f Core shroud 

assembly

Core shroud 

assembly 

bolts (later 

plants are 

welded)

Stainless 

steel; nickel 

alloy

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be

confirmed
September 2005 IV B3-7 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B3 Reactor Vessel Internals (PWR) - Combustion Engineering

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B3-9

(R-162)

IV.B3.4-e Core shroud 

assembly

Core shroud 

assembly 

bolts (later 

plants are 

welded)

Stainless 

steel; nickel 

alloy

Reactor coolant Cracking/ stress 

corrosion cracking, 

primary water 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B3-8 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B3 Reactor Vessel Internals (PWR) - Combustion Engineering

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B3-10

(R-164)

IV.B3.4-g Core shroud 

assembly

Core shroud 

assembly 

bolts (later 

plants are 

welded)

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ neutron 

irradiation 

embrittlement, void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B3-9 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B3 Reactor Vessel Internals (PWR) - Combustion Engineering

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B3-11

(R-159)

IV.B3.4-a Core shroud 

assembly

Core shroud 

tie rods (core 

support plate 

attached by 

welds in later 

plants)

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B3-10 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B3 Reactor Vessel Internals (PWR) - Combustion Engineering

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B3-12

(R-161)

IV.B3.4-c Core shroud 

assembly

Core shroud 

tie rods (core 

support plate 

attached by 

welds in later 

plants)

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture

toughness/ neutron 

irradiation 

embrittlement, void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B3-13

(R-160)

IV.B3.4-b Core shroud 

assembly

Core shroud 

tie rods (core 

support plate 

attached by 

welds in later 

plants)

Stainless 

steel; nickel 

alloy

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B3-11 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B3 Reactor Vessel Internals (PWR) - Combustion Engineering

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B3-14

(R-158)

IV.B3.3-b Core support 

barrel

Core support 

barrel upper 

flange

Stainless 

steel

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B3-12 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B3 Reactor Vessel Internals (PWR) - Combustion Engineering

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B3-15

(R-155)

IV.B3.3-a Core support 

barrel

Core support 

barrel upper 

flange

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B3-13 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B3 Reactor Vessel Internals (PWR) - Combustion Engineering

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B3-16

(R-157)

IV.B3.3-a Core support 

barrel

Core support 

barrel upper 

flange

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ neutron 

irradiation 

embrittlement, void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B3-17

(R-156)

IV.B3.3-b Core support 

barrel

Core support 

barrel upper 

flange

Core support 

barrel 

alignment 

keys

Stainless 

steel

Reactor coolant Loss of material/ 

wear

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 components

No

IV.B3-18

(R-171)

IV.B3.5-f Lower internal 

assembly

Core support 

column

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C (>482°F) 

and neutron flux

Loss of fracture 

toughness/ thermal 

aging and neutron 

irradiation 

embrittlement

Chapter XI.M13, “Thermal Aging and 

Neutron Irradiation Embrittlement of 

Cast Austenitic Stainless Steel 

(CASS)”

No
NUREG-1801, Rev. 1 IV B3-14 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B3 Reactor Vessel Internals (PWR) - Combustion Engineering

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B3-19

(R-168)

IV.B3.5-c Lower internal 

assembly

Core support 

plate

Fuel 

alignment 

pins

Lower 

support 

structure 

beam 

assemblies

Core support 

column bolts

 Core support 

barrel 

snubber 

assemblies

Stainless 

steel; nickel 

alloy

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B3-15 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B3 Reactor Vessel Internals (PWR) - Combustion Engineering

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B3-20

(R-169)

IV.B3.5-d Lower internal 

assembly

Core support 

plate

Fuel 

alignment 

pins

Lower 

support 

structure 

beam 

assemblies

Core support 

column bolts

 Core support 

barrel 

snubber 

assemblies

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ neutron 

irradiation 

embrittlement, void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B3-16 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B3 Reactor Vessel Internals (PWR) - Combustion Engineering

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B3-21

(R-166)

IV.B3.5-a Lower internal 

assembly

Core support 

plate

Lower 

support 

structure 

beam 

assemblies

Core support 

column

Core support 

barrel 

snubber 

assemblies

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B3-22

(R-170)

IV.B3.5-e Lower internal 

assembly

Fuel 

alignment 

pins

Core support 

barrel 

snubber 

assemblies

Stainless 

steel; nickel 

alloy

Reactor coolant Loss of material/ 

wear

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 components

No
September 2005 IV B3-17 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B3 Reactor Vessel Internals (PWR) - Combustion Engineering

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B3-23

(R-167)

IV.B3.5-b Lower internal 

Assembly

Fuel 

alignment 

pins

Core support 

column bolts

Stainless 

steel; nickel 

alloy

Reactor coolant Cracking/ stress 

corrosion cracking, 

primary water 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B3-24

(R-53)

IV.B3.4-d 

IV.B3.5-g 

IV.B3.2-f

Reactor vessel 

internals 

components

Stainless 

steel; nickel 

alloy

Reactor coolant Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA

IV.B3-25

(RP-24)

IV.B3. Reactor vessel 

internals 

components

Stainless 

steel; nickel 

alloy

Reactor coolant Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No
NUREG-1801, Rev. 1 IV B3-18 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B3 Reactor Vessel Internals (PWR) - Combustion Engineering

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B3-26

(R-148)

IV.B3.1-c Upper 

internals 

assembly

Fuel 

alignment 

plate

Fuel 

alignment 

plate guide 

lugs and their 

lugs

Hold-down 

ring

Stainless 

steel

Reactor coolant Loss of material/ 

wear

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 components

No

IV.B3-27

(R-147)

IV.B3.1-b Upper 

internals 

assembly

Upper guide 

structure 

support plate

Fuel 

alignment 

plate

Fuel 

alignment 

plate guide 

lugs and 

guide lug 

inserts

Stainless 

steel

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B3-19 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B3 Reactor Vessel Internals (PWR) - Combustion Engineering

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B3-28

(R-146)

IV.B3.1-a Upper 

internals 

assembly

Upper guide 

structure 

support plate

Fuel 

alignment 

plate

Fuel 

alignment 

plate guide 

lugs and 

guide lug 

inserts

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and managing 

aging effects on reactor internals; (2) 

evaluate and implement the results of 

the industry programs as applicable to 

the reactor internals; and (3) upon 

completion of these programs, but not 

less than 24 months before entering the 

period of extended operation, submit an 

inspection plan for reactor internals to 

the NRC for review and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV.B3-20 September 2005

This Page Intentionally Left Blank
September 2005 IV B4-1 NUREG-1801, Rev. 1

B4. REACTOR VESSEL INTERNALS (PWR) - BABCOCK AND WILCOX

Systems, Structures, and Components

This section addresses the Babcock and Wilcox pressurized water reactor (PWR) vessel 

internals and consists of the plenum cover and plenum cylinder, the upper grid assembly, the 

control rod guide tube (CRGT) assembly, the core support shield assembly, the core barrel 

assembly, the lower grid assembly, and the flow distributor assembly. Based on Regulatory 

Guide 1.26, “Quality Group Classifications and Standards for Water-, Steam-, and RadioactiveWaste-Containing Components of Nuclear Power Plants,” all structures and components that 

comprise the reactor vessel are governed by Group A or B Quality Standards. 

Common miscellaneous material/environment combinations where aging effects are not 

expected to degrade the ability of the structure or component to perform its intended function for 

the extended period of operation are included in IV.E.

System Interfaces

The systems that interface with the reactor vessel internals include the reactor pressure vessel

(IV.A2).
NUREG-1801, Rev. 1 IV B4-2 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-1

(R-128)

IV.B4.5-i Baffle/former 

assembly

Baffle/former 

bolts and 

screws

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ neutron 

irradiation 

embrittlement, void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B4-3 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-2

(R-180)

IV.B4.3-a Control rod 

guide tube 

(CRGT) 

assembly

CRGT pipe 

and flange

CRGT spacer 

casting

CRGT rod 

guide tubes

CRGT rod 

guide sectors

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B4-4 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-3

(R-182)

IV.B4.3-c Control rod 

guide tube 

(CRGT) 

assembly

CRGT pipe 

and flange

CRGT spacer 

casting

CRGT spacer 

screws

Flange-toupper grid 

screws

CRGT rod 

guide tubes

CRGT rod 

guide sectors

Stainless 

steel

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B4-4

(R-183)

IV.B4.3-d Control rod 

guide tube 

(CRGT) 

assembly

CRGT spacer 

casting

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C (>482°F) 

and neutron flux

Loss of fracture 

toughness/ thermal 

aging and neutron 

irradiation 

embrittlement

Chapter XI.M13, “Thermal Aging and 

Neutron Irradiation Embrittlement of 

Cast Austenitic Stainless Steel 

(CASS)”

No
September 2005 IV B4-5 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-5

(R-181)

IV.B4.3-b Control rod 

guide tube 

(CRGT) 

assembly

CRGT spacer 

screws

Flange-toupper grid 

screws

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B4-6 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-6

(R-184)

IV.B4.3-e Control rod 

guide tube 

(CRGT) 

assembly

Flange-toupper grid 

screws

Stainless 

steel

Reactor coolant Loss of preload/ 

stress relaxation

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B4-7 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-7

(R-125)

IV.B4.5-g Core barrel 

assembly

Baffle/former 

assembly

Baffle/former 

bolts and 

screws

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry," for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B4-8 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-8

(R-199)

IV.B4.5-h Core barrel 

assembly

Baffle/former 

bolts and 

screws

Stainless 

steel

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B4-9

(R-201)

IV.B4.5-j Core barrel 

assembly

Baffle/former 

bolts and 

screws

Stainless 

steel

Reactor coolant Loss of preload/ 

stress relaxation

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B4-9 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-10

(R-193)

IV.B4.5-a Core barrel 

assembly

Core barrel 

cylinder (top 

and bottom 

flange)

Baffle plates 

and formers

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B4-10 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-11

(R-195)

IV.B4.5-c Core barrel 

assembly

Core barrel 

cylinder (top 

and bottom 

flange)

Lower 

internals 

assembly-tocore barrel 

bolts

Core barrel-tothermal shield 

bolts

Baffle plates 

and formers

Stainless 

steel; nickel 

alloy

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B4-11 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-12

(R-196)

IV.B4.5-d Core barrel 

assembly

Core barrel 

cylinder (top 

and bottom 

flange)

Lower 

internals 

assembly-tocore barrel 

bolts

Core barrel-tothermal shield 

bolts

Baffle plates 

and formers

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ neutron 

irradiation 

embrittlement, void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B4-12 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-13

(R-194)

IV.B4.5-b Core barrel 

assembly

Lower 

internals 

assembly-tocore barrel 

bolts

Core barrel-tothermal shield 

bolts

Stainless 

steel; nickel 

alloy

Reactor coolant Cracking/ stress 

corrosion cracking, 

primary water 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B4-13 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-14

(R-197)

IV.B4.5-e Core barrel 

assembly

Lower 

internals 

assembly-tocore barrel 

bolts

Core barrel-tothermal shield 

bolts

Stainless 

steel; nickel 

alloy

Reactor coolant Loss of preload/ 

stress relaxation

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B4-15

(R-190)

IV.B4.4-f Core support 

shield 

assembly

Core support 

shield cylinder

(top flange)

vent valve 

assembly 

locking device

Stainless 

steel

Reactor coolant Loss of material/ 

wear

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components

No
NUREG-1801, Rev. 1 IV B4-14 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-16

(R-188)

IV.B4.4-d Core support 

shield 

assembly

Core support 

shield cylinder 

(top and 

bottom flange)

Core support 

shield-to-core 

barrel bolts

Outlet and 

vent valve

nozzles

vent valve

assembly 

locking device

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ neutron 

irradiation 

embrittlement, void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B4-15 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-17

(R-187)

IV.B4.4-c Core support 

shield 

assembly

Core support 

shield cylinder 

(top and 

bottom flange)

Core support 

shield-to-core 

barrel bolts

vent valve

retaining ring

vent valve

assembly 

locking device

Stainless 

steel; nickel 

alloy

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B4-16 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-18

(R-185)

IV.B4.4-a Core support 

shield 

assembly

Core support 

shield cylinder 

(top and 

bottom flange)

Outlet and 

vent valve 

nozzles

vent valve

body and 

retaining ring

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B4-17 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-19

(R-192)

IV.B4.4-h Core support 

shield 

assembly

Core support 

shield-to-core 

barrel bolts

Stainless 

steel; nickel 

alloy

Reactor coolant Loss of preload/ 

stress relaxation

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B4-18 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-20

(R-186)

IV.B4.4-b Core support 

shield 

assembly

Core support 

shield-to-core 

barrel bolts

vent valve

assembly 

locking device

Stainless 

steel; nickel 

alloy

Reactor coolant Cracking/ stress 

corrosion cracking, 

primary water 

stress corrosion

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B4-21

(R-191)

IV.B4.4-g Core support 

shield 

assembly

Outlet and 

vent valve 

nozzles

vent valve

body and 

retaining ring

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C (>482°F) 

and neutron flux

Loss of fracture 

toughness/ thermal 

aging and neutron 

irradiation 

embrittlement

Chapter XI.M13, “Thermal Aging and 

Neutron Irradiation Embrittlement of 

Cast Austenitic Stainless Steel 

(CASS)”

No
September 2005 IV B4-19 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-22

(R-209)

IV.B4.7-a Flow distributor 

assembly

Flow 

distributor 

head and 

flange

Incore guide 

support plate

Clamping ring

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B4-20 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-23

(R-211)

IV.B4.7-c Flow distributor 

assembly

Flow 

distributor

head and 

flange

Shell forgingto-flow 

distributor 

bolts

Incore guide 

support plate

Clamping ring

Stainless 

steel; nickel 

alloy

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B4-24

(R-212)

IV.B4.7-d Flow distributor 

assembly

Flow 

distributor 

head and 

flange

Shell forgingto-flow 

distributor 

bolts

Incore guide 

support plate

Clamping ring

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ neutron 

irradiation 

embrittlement, void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B4-21 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-25

(R-210)

IV.B4.7-b Flow distributor 

assembly

Shell forgingto-flow 

distributor 

bolts

Stainless 

steel; nickel 

alloy

Reactor coolant Cracking/ stress 

corrosion cracking, 

primary water 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B4-22 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-26

(R-213)

IV.B4.7-e Flow distributor 

assembly

Shell forgingto-flow 

distributor 

bolts

Stainless 

steel; nickel 

alloy

Reactor coolant Loss of preload/ 

stress relaxation

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B4-27

(R-208)

IV.B4.6-h Lower grid 

assembly

Fuel assembly 

support pads 

Guide blocks

Stainless 

steel

Reactor coolant Loss of material/ 

wear

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components

No

IV.B4-28

(R-206)

IV.B4.6-e Lower grid 

assembly

Incore guide 

tube spider 

castings

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C (>482°F) 

and neutron flux

Loss of fracture 

toughness/ thermal 

aging and neutron 

irradiation 

embrittlement

Chapter XI.M13, “Thermal Aging and 

Neutron Irradiation Embrittlement of 

Cast Austenitic Stainless Steel 

(CASS)”

No
September 2005 IV B4-23 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-29

(R-202)

IV.B4.6-a Lower grid 

assembly

Lower grid rib 

section

Fuel assembly 

support pads

Lower grid flow 

dist. plate

Orifice plugs

Lower grid and 

shell forgings

Guide blocks

Shock pads

Support post 

pipes

Incore guide 

tube spider 

castings

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B4-24 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-30

(R-204)

IV.B4.6-c Lower grid 

assembly

Lower grid rib 

section

Fuel assembly 

support pads

Lower grid ribto-shell forging 

screws

Lower grid flow 

dist. plate

Orifice plugs

Lower grid and 

shell forgings

Lower 

internals 

assembly-tothermal shield 

bolts

Guide blocks 

and bolts

Shock pads 

and bolts

Support post 

pipes

Incore guide 

tube spider 

castings

Stainless 

steel; nickel 

alloy

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B4-25 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-31

(R-205)

IV.B4.6-d Lower grid 

assembly

Lower grid rib 

section

Fuel assembly 

support pads

Lower grid ribto-shell forging 

screws

Lower grid flow 

dist. plate

Orifice plugs

Lower grid and 

shell forgings

Lower 

internals 

assembly-tothermal shield 

bolts

Guide blocks 

and bolts

Shock pads 

and bolts

Support post 

pipes

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ neutron 

irradiation 

embrittlement, void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B4-26 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-32

(R-203)

IV.B4.6-b Lower grid 

assembly

Lower grid ribto-shell forging 

screws

Lower 

internals 

assembly-tothermal shield 

bolts

Guide blocks 

bolts

Shock pads 

bolts

Stainless 

steel; nickel 

alloy

Reactor coolant Cracking/ stress 

corrosion cracking, 

primary water 

stress corrosion 

cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B4-27 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-33

(R-207)

IV.B4.6-g Lower grid 

assembly

Lower grid ribto-shell forging 

screws

Lower 

internals 

assembly-tothermal shield 

bolts

Stainless 

steel; nickel 

alloy

Reactor coolant Loss of preload/ 

stress relaxation

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B4-28 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-34

(R-172)

IV.B4.1-a Plenum cover 

and plenum 

cylinder

Plenum cover 

assembly

Plenum 

cylinder

Reinforcing 

plates

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B4-29 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-35

(R-174)

IV.B4.1-c Plenum cover 

and plenum 

cylinder

Plenum cover 

assembly 

Plenum 

cylinder

Reinforcing 

plates

Top flange-tocover bolts 

Bottom flangeto-upper grid 

screws

Stainless 

steel

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B4-30 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-36

(R-173)

IV.B4.1-b Plenum cover 

and plenum 

cylinder

Top flange-tocover bolts 

Bottom flangeto-upper grid 

screws

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B4-37

(R-53)

IV.B4.3-f 

IV.B4.5-f 

IV.B4.6-f 

IV.B4.2-d 

IV.B4.1-d 

IV.B4.4-e

Reactor vessel 

internals 

components

Stainless 

steel; nickel 

alloy

Reactor coolant Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA

IV.B4-38

(RP-24)

IV.B4. Reactor vessel 

internals 

components

Stainless 

steel; nickel 

alloy

Reactor coolant Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No
September 2005 IV B4-31 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-39

(R-215)

IV.B4.8-b Thermal shield Stainless 

steel

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B4-32 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-40

(R-214)

IV.B4.8-a Thermal shield Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B4-33 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-41

(R-216)

IV.B4.8-c Thermal shield Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ neutron 

irradiation 

embrittlement, void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B4-42

(R-179)

IV.B4.2-f Upper grid 

assembly

Fuel assembly 

support pads 

Plenum rib 

pads

Stainless 

steel

Reactor coolant Loss of material/ 

wear

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components

No
NUREG-1801, Rev. 1 IV B4-34 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-43

(R-176)

IV.B4.2-b Upper grid 

assembly

Rib- to-ring 

screws

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV B4-35 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-44

(R-175)

IV.B4.2-a Upper grid 

assembly

Upper grid rib 

section

Upper grid ring 

forging

Fuel assembly 

support pads

Plenum rib 

pads

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

irradiation-assisted 

stress corrosion 

cracking

Chapter XI.M2, "Water Chemistry" for 

PWR primary water

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV B4-36 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

B4 Reactor Vessel Internals (PWR) – Babcock & Wilcox

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.B4-45

(R-177)

IV.B4.2-c Upper grid 

assembly

Upper grid rib 

section

Upper grid ring 

forging

Fuel assembly 

support pads

Plenum rib 

pads

Rib-to-ring 

screws

Stainless 

steel

Reactor coolant Changes in 

dimensions/ void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.B4-46

(R-178)

IV.B4.2-e Upper grid 

assembly

Upper grid rib 

section

Upper grid ring 

forging

Fuel assembly 

support pads

Plenum rib 

pads

Rib-to-ring 

screws

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness/ neutron 

irradiation 

embrittlement, void 

swelling

No further aging management review is 

necessary if the applicant provides a 

commitment in the FSAR supplement 

to (1) participate in the industry 

programs for investigating and 

managing aging effects on reactor 

internals; (2) evaluate and implement 

the results of the industry programs as 

applicable to the reactor internals; and 

(3) upon completion of these programs, 

but not less than 24 months before 

entering the period of extended 

operation, submit an inspection plan for 

reactor internals to the NRC for review 

and approval.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV C1-1 NUREG-1801, Rev. 1

C1. REACTOR COOLANT PRESSURE BOUNDARY (BOILING WATER REACTOR)

Systems, Structures, and Components

This section addresses the boiling water reactor (BWR) primary coolant pressure boundary and 

consists of the reactor coolant recirculation system and portions of other systems connected to 

the pressure vessel extending to the second containment isolation valve or to the first anchor 

point outside containment. The connected systems include the residual heat removal (RHR), 

low–pressure core spray (LPCS), high–pressure core spray (HPCS), low–pressure coolant 

injection (LPCI), high–pressure coolant injection (HPCI), reactor core isolation cooling (RCIC), 

isolation condenser (IC), reactor water cleanup (RWC), standby liquid control (SLC), feedwater 

(FW), and main steam (MS) systems; and the steam line to the HPCI and RCIC pump turbines. 

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” all systems, 

structures, and components that comprise the reactor coolant pressure boundary are governed 

by Group A Quality Standards.

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration, or are subject to replacement based on qualified life or specified time period. 

Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management review.

Common miscellaneous material/environment combinations where aging effects are not 

expected to degrade the ability of the structure or component to perform its intended function for 

the extended period of operation are included in IV.E.

System Interfaces

The systems that interface with the reactor coolant pressure boundary include the reactor 

pressure vessel (IV.A1), the emergency core cooling system (V.D2), the standby liquid control 

system (VII.E2), the reactor water cleanup system (VII.E3), the shutdown cooling system (older 

plants) (VII.E4), the main steam system (VIII.B2), and the feedwater system (VIII.D2).
NUREG-1801, Rev. 1 IV C1-2 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

C1 Reactor Coolant Pressure Boundary (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.C1-1

(R-03)

IV.C1.1-i Class 1 piping, 

fittings and 

branch 

connections 

< nominal pipe 

sizes (NPS) 4

Stainless 

steel; steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

intergranular stress 

corrosion cracking 

(for stainless steel 

only), and thermal 

and mechanical 

loading

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components, and

Chapter XI.M2, “Water Chemistry,” for 

BWR water and

XI.M35, "One-Time Inspection of ASME 

Code Class 1 Small-bore Piping"

No

IV.C1-2

(R-52)

IV.C1.1-g Class 1 piping, 

piping 

components, 

and piping 

elements

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C (>482°F)

Loss of fracture 

toughness/ thermal 

aging 

embrittlement

Chapter XI.M12, “Thermal Aging 

Embrittlement of Cast Austenitic 

Stainless Steel (CASS)”

No
September 2005 IV C1-3 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

C1 Reactor Coolant Pressure Boundary (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.C1-3

(R-08)

IV.C1.2-c 

IV.C1.3-b

Class 1 pump 

casings, and 

valve bodies 

and bonnets

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C (>482°F)

Loss of fracture 

toughness/ thermal 

aging 

embrittlement

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 components

For pump casings and valve bodies, 

screening for susceptibility to thermal 

aging is not necessary. The ASME 

Section XI inspection requirements are 

sufficient for managing the effects of 

loss of fracture toughness due to 

thermal aging embrittlement of CASS 

pump casings and valve bodies. 

Alternatively, the requirements of ASME 

Code Case N-481 for pump casings are 

sufficient for managing the effects of 

loss of fracture toughness due to 

thermal aging embrittlement of CASS 

pump casings.

No
NUREG-1801, Rev. 1 IV C1-4 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

C1 Reactor Coolant Pressure Boundary (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.C1-4

(R-15)

IV.C1.4-a Isolation 

condenser 

components

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking, 

intergranular stress 

corrosion cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 components

and Chapter XI.M2, “Water Chemistry,” 

for BWR water. 

The AMP in Chapter XI.M1 is to be 

augmented to detect cracking due to 

stress corrosion cracking and 

verification of the program's 

effectiveness is necessary to ensure 

that significant degradation is not 

occurring and the component intended 

function will be maintained during the 

extended period of operation. An 

acceptable verification program is to 

include temperature and radioactivity 

monitoring of the shell side water, and 

eddy current testing of tubes.

Yes, detection 

of aging effects 

is to be 

evaluated
September 2005 IV C1-5 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

C1 Reactor Coolant Pressure Boundary (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.C1-5

(R-225)

IV.C1.4-a Isolation 

condenser 

components

Stainless 

steel; steel

Reactor coolant Cracking/ cyclic 

loading

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 components

The AMP in Chapter XI.M1 is to be 

augmented to detect cracking due to 

cyclic loading and verification of the 

program's effectiveness is necessary to 

ensure that significant degradation is 

not occurring and the component 

intended function will be maintained 

during the extended period of operation. 

An acceptable verification program is to 

include temperature and radioactivity 

monitoring of the shell side water, and 

eddy current testing of tubes.

Yes, detection 

of aging effects 

is to be 

evaluated

IV.C1-6

(R-16)

IV.C1.4-b Isolation 

condenser 

components

Stainless 

steel; steel

Reactor coolant Loss of material/ 

general (steel 

only), pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter XI.M32, 

“One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

IV.C1-7

(R-23)

IV.C1.1-c 

IV.C1.1-a 

IV.C1.3-a

Piping, piping 

components, 

and piping 

elements

Steel Reactor coolant Wall thinning/ flowaccelerated 

corrosion

Chapter XI.M17, “Flow-Accelerated 

Corrosion”

No
NUREG-1801, Rev. 1 IV C1-6 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

C1 Reactor Coolant Pressure Boundary (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.C1-8

(R-21)

IV.C1.1-f Piping, piping 

components, 

and piping 

elements 

greater than or 

equal to 4 

NPS

Nickel alloy Reactor coolant Cracking/ stress 

corrosion cracking 

and intergranular 

stress corrosion 

cracking

Chapter XI.M7, “BWR Stress Corrosion 

Cracking,” and

Chapter XI.M2, “Water Chemistry,” for 

BWR water

No

IV.C1-9

(R-20)

IV.C1.2-b 

IV.C1.1-f 

IV.C1.3-c

Piping, piping 

components, 

and piping 

elements 

greater than or 

equal to 4 

NPS

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking 

and intergranular 

stress corrosion 

cracking

Chapter XI.M7, “BWR Stress Corrosion 

Cracking,” and

Chapter XI.M2, “Water Chemistry,” for 

BWR water

No

IV.C1-10

(R-27)

IV.C1.2-e 

IV.C1.3-f

Pump and 

valve closure 

bolting

Low-alloy 

steel SA 193 

Gr. B7

System 

temperature up 

to 288°C (550°F)

Loss of preload/ 

thermal effects, 

gasket creep, and 

self-loosening

Chapter XI.M18, “Bolting Integrity” No

IV.C1-11

(R-28)

IV.C1.2-f 

IV.C1.3-g

Pump and 

valve closure 

bolting

Steel System 

temperature up 

to 288°C (550°F)

Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be performed for the period of 

extended operation; check ASME Code 

limits for allowable cycles (less than 

7000 cycles) of thermal stress range. 

See the Standard Review Plan, Section 

4.3, “Metal Fatigue,” for acceptable 

methods for meeting the requirements 

of 10 CFR 54.21(c)(1).

Yes,

TLAA

IV.C1-12

(R-26)

IV.C1.3-e 

IV.C1.2-d

Pump and 

valve closure 

bolting

Steel System 

temperature up 

to 288°C (550°F)

Loss of material/ 

wear

Chapter XI.M18, “Bolting Integrity” No
September 2005 IV C1-7 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

C1 Reactor Coolant Pressure Boundary (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.C1-13

(R-29)

IV.C1.2-d 

IV.C1.3-e

Pump and 

valve seal 

flange closure 

bolting

Stainless 

steel; steel

System 

temperature up 

to 288°C (550°F)

Loss of material/ 

wear

Chapter XI.M18, “Bolting Integrity” No

IV.C1-14

(RP-27)

IV.C1. Reactor 

coolant 

pressure 

boundary 

components

Steel with 

stainless 

steel or 

nickel alloy 

cladding; 

stainless 

steel; nickel 

alloy

Reactor coolant Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter XI.M32, 

“One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

IV.C1-15

(R-220)

IV.C1.1-e 

IV.C1.1-b 

IV.C1.1-h 

IV.C1.3-d 

IV.C1.1-e 

IV.C1.1-h 

IV.C1.1-d 

IV.C1.1-h 

IV.C1.2-a 

IV.C1.2-a 

IV.C1.1-h 

IV.C1.2-a 

IV.C1.1-h 

IV.C1.1-h 

IV.C1.3-d 

IV.C1.1-h 

IV.C1.3-d

Reactor 

coolant 

pressure 

boundary 

components:

Piping, piping 

components, 

and piping 

elements

Steel; 

stainless 

steel; steel 

with nickelalloy or 

stainless 

steel 

cladding; 

nickel-alloy

Reactor coolant Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be performed for the period of 

extended operation, and for Class 1 

components, environmental effects on 

fatigue are to be addressed. See the 

Standard Review Plan, Section 4.3 

“Metal Fatigue,” for acceptable methods 

for meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA
NUREG-1801, Rev. 1 IV C1-8 September 2005

This Page Intentionally Left Blank
September 2005 IV C2-1 NUREG-1801, Rev. 1

C2. REACTOR COOLANT SYSTEM AND CONNECTED LINES

(PRESSURIZED WATER REACTOR)

Systems, Structures, and Components

This section addresses the pressurized water reactor (PWR) primary coolant pressure 

boundary and consists of the reactor coolant system and portions of other connected systems 

generally extending up to and including the second containment isolation valve or to the first 

anchor point and including the containment isolation valves, the reactor coolant pump, valves, 

pressurizer, and the pressurizer relief tank. The connected systems include the residual heat 

removal (RHR) or low pressure injection system, high pressure injection system, sampling 

system, and the small-bore piping. With respect to other systems such as the core flood system

(CFS) or the safety injection tank (SIT) and the chemical and volume control system (CVCS), 

the isolation valves associated with the boundary between ASME Code class 1 and 2 are located 

inside the containment. Based on Regulatory Guide 1.26, “Quality Group Classifications and 

Standards for Water-, Steam-, and Radioactive-Waste-Containing Components of Nuclear 

Power Plants,” and with the exception of the pressurizer relief tank, which is governed by Group 

B Quality Standards, all systems, structures, and components that comprise the reactor coolant 

system are governed by Group A Quality Standards. The recirculating pump seal water heat 

exchanger is discussed in V.D1. 

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration, or are subject to replacement based on qualified life or specified time period. 

Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management review. 

Common miscellaneous material/environment combinations where aging effects are not 

expected to degrade the ability of the structure or component to perform its intended function for 

the extended period of operation are included in IV.E.

System Interfaces

The systems that interface with the reactor coolant pressure boundary include the reactor 

pressure vessel (IV.A2), the steam generators (IV.D1 and IV.D2), the emergency core cooling 

system (V.D1), and the chemical and volume control system (VII.E1).
NUREG-1801, Rev. 1 IV C2-2 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

C2 Reactor Coolant System and Connected Lines (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.C2-1

(R-02)

IV.C2.1-g 

IV.C2.2-h

Class 1 piping, 

fittings and 

branch 

connections < 

NPS 4

Stainless 

steel; steel

with 

stainless 

steel 

cladding

Reactor coolant Cracking/ stress 

corrosion 

cracking, thermal 

and mechanical 

loading

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components, and

Chapter XI.M2, “Water Chemistry,” for 

PWR water and

XI.M35, "One-Time Inspection of ASME 

Code Class 1 Small-bore Piping"

No

IV.C2-2

(R-07)

IV.C2.5-h 

IV.C2.5-m 

IV.C2.2-f

Class 1 piping, 

fittings, primary 

nozzles, safe 

ends, manways, 

and flanges

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Reactor coolant Cracking/ stress 

corrosion cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No
September 2005 IV C2-3 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

C2 Reactor Coolant System and Connected Lines (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.C2-3

(R-05)

IV.C2.2-g 

IV.C2.5-i 

IV.C2.1-e

Class 1 piping, 

piping 

components, 

and piping 

elements

Cast 

austenitic 

stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking

Monitoring and control of primary water 

chemistry in accordance with the 

guidelines in EPRI TR-105714 (Rev. 3 

or later) minimize the potential of SCC, 

and material selection according to 

NUREG-0313, Rev. 2 guidelines of 

=0.035% C and =7.5% ferrite reduces 

susceptibility to SCC.

For CASS components that do not 

meet either one of the above 

guidelines, a plant-specific aging 

management program is to be 

evaluated. The program is to include 

(a) adequate inspection methods to 

ensure detection of cracks, and (b) flaw 

evaluation methodology for CASS 

components that are susceptible to 

thermal aging embrittlement.

Yes, plantspecific

IV.C2-4

(R-52)

IV.C2.5-l 

IV.C2.1-f 

IV.C2.2-e

Class 1 piping, 

piping 

components, 

and piping 

elements

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C (>482°F)

Loss of fracture 

toughness/ 

thermal aging 

embrittlement

Chapter XI.M12, “Thermal Aging 

Embrittlement of Cast Austenitic 

Stainless Steel (CASS)”

No

IV.C2-5

(R-09)

IV.C2.3-b 

IV.C2.4-b

Class 1 pump 

casings and 

valve bodies

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Reactor coolant Cracking/ stress 

corrosion cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No
NUREG-1801, Rev. 1 IV C2-4 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

C2 Reactor Coolant System and Connected Lines (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.C2-6

(R-08)

IV.C2.3-c 

IV.C2.4-c

Class 1 pump 

casings, and 

valve bodies and 

bonnets

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C (>482°F)

Loss of fracture 

toughness/ 

thermal aging 

embrittlement

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components

For pump casings and valve bodies, 

screening for susceptibility to thermal 

aging is not necessary. The ASME 

Section XI inspection requirements are 

sufficient for managing the effects of 

loss of fracture toughness due to 

thermal aging embrittlement of CASS 

pump casings and valve bodies. 

Alternatively, the requirements of 

ASME Code Case N-481 for pump 

casings are sufficient for managing the 

effects of loss of fracture toughness 

due to thermal aging embrittlement of 

CASS pump casings.

No

IV.C2-7

(R-11)

IV.C2.5-n 

IV.C2.3-e 

IV.C2.4-e

Closure bolting Highstrength lowalloy steel, 

stainless 

steel

Air with reactor 

coolant leakage

Cracking/ stress 

corrosion cracking

Chapter XI.M18, “Bolting Integrity” No

IV.C2-8

(R-12)

IV.C2.4-g 

IV.C2.5-p 

IV.C2.3-g

Closure bolting Low-alloy 

steel, 

stainless 

steel

Air with reactor 

coolant leakage

Loss of preload/ 

thermal effects, 

gasket creep, and 

self-loosening

Chapter XI.M18, “Bolting Integrity” No
September 2005 IV C2-5 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

C2 Reactor Coolant System and Connected Lines (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.C2-9

(R-17)

IV.C2.3-f 

IV.C2.2-d 

IV.C2.1-d 

IV.C2.5-b 

IV.C2.5-u 

IV.C2.6-b 

IV.C2.4-f 

IV.C2.5-o

External 

surfaces

Steel Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid Corrosion” No

IV.C2-10

(R-18)

IV.C2.5-w 

IV.C2.3-d 

IV.C2.4-d 

IV.C2.5-t

Piping and 

components 

external 

surfaces and 

bolting

Stainless 

steel; steel

System 

temperature up 

to 340°C (644°F)

Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA

IV.C2-11

(RP-11)

IV.C2. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

IV.C2-12

(RP-12)

IV.C2. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No
NUREG-1801, Rev. 1 IV C2-6 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

C2 Reactor Coolant System and Connected Lines (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.C2-13

(RP-31)

IV.C2. Piping, piping 

components, 

and piping 

elements

Nickel alloy Reactor coolant/ 

steam

Cracking/ primary 

water stress 

corrosion cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD” for Class 1 

components, and

Chapter XI.M2, “Water Chemistry” for 

PWR primary water and

Comply with applicable NRC Orders 

and provide a commitment in the FSAR 

supplement to implement applicable (1) 

Bulletins and Generic Letters and (2) 

staff-accepted industry guidelines.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.C2-14

(RP-10)

IV.C2. Piping, piping 

components, 

and piping 

elements

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

IV.C2-15

(RP-23)

IV.C2. Piping, piping 

components, 

and piping 

elements; 

flanges; heater 

sheaths and 

sleeves; 

penetrations; 

thermal sleeves; 

vessel shell 

heads and 

welds

Steel with 

stainless 

steel or 

nickel alloy 

cladding; 

stainless 

steel; nickel 

alloy

Reactor coolant Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No
September 2005 IV C2-7 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

C2 Reactor Coolant System and Connected Lines (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.C2-16

(R-19)

IV.C2.5-v Pressurizer

Integral 

support

Stainless 

steel; steel

Air with metal 

temperature up 

to 288°C (550°F)

Cracking/ cyclic 

loading

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components

No

IV.C2-17

(R-24)

IV.C2.5-j Pressurizer

Spray head

Nickel alloy; 

stainless 

steel

Reactor coolant Cracking/ stress 

corrosion 

cracking, primary 

water stress 

corrosion cracking

Chapter XI.M2, “Water Chemistry,” and 

Chapter XI.M32 "One-Time Inspection" 

and

For nickel alloy welded spray heads, 

comply with applicable NRC Orders 

and provide a commitment in the FSAR 

supplement to implement applicable (1) 

Bulletins and Generic Letters and (2) 

staff-accepted industry guidelines.

No, unless 

licensee 

commitment 

needs to be 

confirmed
NUREG-1801, Rev. 1 IV C2-8 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

C2 Reactor Coolant System and Connected Lines (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.C2-18

(R-58)

IV.C2.5-c 

IV.C2.5-g

Pressurizer 

components

Steel with 

stainless 

steel or 

nickel alloy 

cladding; or 

stainless 

steel

Reactor coolant Cracking/ cyclic 

loading

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

Cracks in the pressurizer cladding 

could propagate from cyclic loading 

into the ferrite base metal and weld 

metal. However, because the weld 

metal between the surge nozzle and 

the vessel lower head is subjected to 

the maximum stress cycles and the 

area is periodically inspected as part of 

the ISI program, the existing AMP is 

adequate for managing the effect of 

pressurizer clad cracking.

No

IV.C2-19

(R-25)

IV.C2.5-g 

IV.C2.5-c

Pressurizer 

components

Steel with 

stainless 

steel or 

nickel alloy 

cladding; or 

stainless 

steel

Reactor coolant Cracking/ stress 

corrosion 

cracking, primary 

water stress 

corrosion cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD” for Class 1 

components, and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water 

No
September 2005 IV C2-9 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

C2 Reactor Coolant System and Connected Lines (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.C2-20

(R-217)

IV.C2.5-r Pressurizer 

heater sheaths 

and sleeves, 

and heater 

bundle 

diaphragm plate

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No

IV.C2-21

(R-06)

IV.C2.5-m 

IV.C2.5-k 

IV.C2.5-s

Pressurizer 

instrumentation 

penetrations, 

heater sheaths 

and sleeves, 

heater bundle 

diaphragm plate, 

and manways 

and flanges

Nickel alloy 

or nickel 

alloy 

cladding

Reactor coolant Cracking/ primary 

water stress 

corrosion cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD” for Class 1 

components, and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water and

For nickel alloy, comply with applicable 

NRC Orders and provide a commitment 

in the FSAR supplement to implement 

applicable (1) Bulletins and Generic 

Letters and (2) staff-accepted industry 

guidelines.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.C2-22

(R-14)

IV.C2.6-c Pressurizer 

relief tank

Tank shell and 

heads

Flanges and 

nozzles

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Treated borated 

water >60°C 

(>140°F)

Cracking/ stress 

corrosion cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No
NUREG-1801, Rev. 1 IV C2-10 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

C2 Reactor Coolant System and Connected Lines (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.C2-23

(R-13)

IV.C2.6-a Pressurizer 

relief tank

Tank shell and 

heads

Flanges and 

nozzles

Steel with 

stainless 

steel 

cladding

Treated borated 

water

Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA

IV.C2-24

(RP-22)

IV.C2. Pressurizer 

surge and 

steam space 

nozzles, and 

welds

Nickel alloy Reactor coolant/ 

steam

Cracking/ primary 

water stress 

corrosion cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD” for Class 1 

components, and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water and

Comply with applicable NRC Orders 

and provide a commitment in the FSAR 

supplement to implement applicable (1) 

Bulletins and Generic Letters and (2) 

staff-accepted industry guidelines.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV C2-11 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

C2 Reactor Coolant System and Connected Lines (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.C2-25

(R-223)

IV.C2.5-f 

IV.C2.4-a 

IV.C2.2-a 

IV.C2.5-f 

IV.C2.3-a 

IV.C2.2-b 

IV.C2.1-b 

IV.C2.1-b 

IV.C2.5-a 

IV.C2.1-a 

IV.C2.1-a 

IV.C2.5-d 

IV.C2.2-a 

IV.C2.2-a 

IV.C2.4-a 

IV.C2.2-b 

IV.C2.3-a 

IV.C2.5-q 

IV.C2.2-c 

IV.C2.5-d 

IV.C2.5-e 

IV.C2.5-f 

IV.C2.2-a

Reactor coolant 

pressure 

boundary 

components:

Piping, piping 

components, 

and piping 

elements;

Flanges;

Nozzles and 

safe ends;

Pressurizer 

vessel shell 

heads and 

welds;

Heater sheaths 

and sleeves;

Penetrations; 

and

Thermal 

sleeves

Steel; 

stainless 

steel; steel 

with nickelalloy or 

stainless 

steel 

cladding; 

nickel-alloy

Reactor coolant Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be performed for the period of 

extended operation, and, for Class 1 

components, environmental effects on 

fatigue are to be addressed. See the 

Standard Review Plan, Section 4.3 

“Metal Fatigue,” for acceptable 

methods for meeting the requirements 

of 10 CFR 54.21(c)(1).

Yes,

TLAA
NUREG-1801, Rev. 1 IV C2-12 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

C2 Reactor Coolant System and Connected Lines (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.C2-26

(R-56)

IV.C2.1-c Reactor coolant 

system piping 

and fittings

Cold leg

Hot leg

Surge line

Spray line

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Reactor coolant Cracking/ cyclic 

loading

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components

No

IV.C2-27

(R-30)

IV.C2.1-c Reactor coolant 

system piping 

and fittings

Cold leg

Hot leg

Surge line

Spray line

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Reactor coolant Cracking/ stress 

corrosion cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No
September 2005 IV D1-1 NUREG-1801, Rev. 1

D1. STEAM GENERATOR (RECIRCULATING)

Systems, Structures, and Components

This section addresses the recirculating-type steam generators, as found in Westinghouse and 

Combustion Engineering pressurized water reactors (PWRs), including all internal components 

and water/steam nozzles and safe ends. Based on Regulatory Guide 1.26, “Quality Group 

Classifications and Standards for Water-, Steam-, and Radioactive-Waste-Containing 

Components of Nuclear Power Plants,” the primary water side (tube side) of the steam 

generator is governed by Group A Quality Standards, and the secondary water side is governed 

by Group B Quality Standards. 

Common miscellaneous material/environment combinations where aging effects are not 

expected to degrade the ability of the structure or component to perform its intended function for 

the extended period of operation are included in IV.E.

System Interfaces

The systems that interface with the steam generators include the reactor coolant system and 

connected lines (IV.C2), the containment isolation components (V.C), the main steam system 

(VIII.B1), the feedwater system (VIII.D1), the steam generator blowdown system (VIII.F), and the 

auxiliary feedwater system (VIII.G).
NUREG-1801, Rev. 1 IV D1-2 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

D1 Steam Generator (Recirculating)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.D1-1

(R-07)

IV.D1.1-i Class 1 piping, 

fittings, primary 

nozzles, safe 

ends, manways, 

and flanges

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Reactor coolant Cracking/ stress 

corrosion cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No

IV.D1-2

(R-10)

IV.D1.1-l Closure bolting Steel Air with reactor 

coolant leakage

Cracking/ stress 

corrosion cracking

Chapter XI.M18, “Bolting Integrity” No

IV.D1-3

(R-17)

IV.D1.1-k 

IV.D1.1-g

External 

surfaces

Steel Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid Corrosion” No

IV.D1-4

(R-01)

IV.D1.1-i 

IV.D1.1-j

Instrument 

penetrations 

and primary 

side nozzles, 

safe ends, and 

welds

Nickel alloy; 

steel with 

nickel-alloy 

cladding

Reactor coolant Cracking/ primary 

water stress 

corrosion cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components, and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water and

For nickel alloy, comply with applicable 

NRC Orders and provide a commitment 

in the FSAR supplement to submit a 

plant-specific AMP to implement 

applicable (1) Bulletins and Generic 

Letters and (2) staff-accepted industry 

guidelines.

No, but 

licensee 

commitment 

needs to be 

confirmed
September 2005 IV D1-3 NURE

G-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

D1 Steam Generator (Recirculating)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.D1-5

(R-37)

IV.D1.1-d Pressure 

boundary and 

structural

Steam nozzle 

and safe end

FW nozzle 

and safe end

Steel Secondary 

feedwater/ steam

Wall thinning/ 

flow-accelerated 

corrosion

Chapter XI.M17, “Flow-Accelerated 

Corrosion”

No

IV.D1-6

(RP-21)

IV.D1. Primary side

Divider Plate

Nickel alloy; 

steel with 

nickel-alloy 

cladding

Reactor coolant Cracking/ primary 

water stress 

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No

IV.D1-7

(RP-17)

IV.D1. Primary side

Divider Plate

Stainless 

steel

Reactor coolant Cracking/ stress 

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No

IV.D1-8

(R-221)

IV.D1.1-h Recirculating 

steam generator 

components:

Flanges; 

Penetrations; 

Nozzles;

Safe ends, 

lower heads 

and welds

Steel; 

stainless 

steel; steel 

with nickelalloy or 

stainless 

steel 

cladding; 

nickel-alloy

Reactor coolant Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be performed for the period of 

extended operation, and, for Class 1 

components, environmental effects on 

fatigue are to be addressed. See the 

Standard Review Plan, Section 4.3 

“Metal Fatigue,” for acceptable 

methods for meeting the requirements 

of 10 CFR 54.21(c)(1).

Yes,

TLAA
NUREG-1801, Rev. 1 IV D1-4 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

D1 Steam Generator (Recirculating)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.D1-9

(RP-16)

IV.D1. Steam 

generator

Tube bundle 

wrapper

Steel Secondary 

feedwater/ steam

Loss of material/ 

erosion, general, 

pitting, and 

crevice corrosion

Chapter XI.M19, “Steam Generator 

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No

IV.D1-10

(R-32)

IV.D1.1-f Steam 

generator 

closure bolting

Steel System 

temperature up to 

340°C (644°F)

Loss of preload/ 

thermal effects, 

gasket creep, and 

self-loosening

Chapter XI.M18, “Bolting Integrity” No

IV.D1-11

(R-33)

IV.D1.1-b 

IV.D1.1-a

Steam 

generator 

components

Top head;

Steam nozzle 

and safe end;

Upper and 

lower shell;

Feedwater and 

auxiliary 

feedwater 

nozzle and 

safe end;

feedwater

impingement 

plate and 

support

Steel Secondary 

feedwater/ steam

Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA
September 2005 IV D1-5 NURE

G-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

D1 Steam Generator (Recirculating)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.D1-12

(R-34)

IV.D1.1-c Steam 

generator 

components

Upper and 

lower shell, 

and transition 

cone

Steel Secondary 

feedwater/ steam

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 2 

components and

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water. As noted in 

NRC IN 90-04, if general and pitting 

corrosion of the shell is known to exist, 

the AMP guidelines in Chapter XI.M1 

may not be sufficient to detect general 

and pitting corrosion (and the resulting 

corrosion-fatigue cracking), and 

additional inspection procedures are to 

be developed. This issue is limited to 

Westinghouse Model 44 and 51 Steam 

Generators where a high stress region 

exists at the shell to transition cone 

weld.

Yes, detection 

of aging effects 

is to be 

evaluated

IV.D1-13

(R-39)

IV.D1.1-e Steam 

generator 

feedwater 

impingement 

plate and 

support

Steel Secondary 

feedwater

Loss of material/ 

erosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

IV.D1-14

(RP-14)

IV.D1. Steam 

generator 

structural

Anti-vibration 

bars

Chrome 

plated steel; 

stainless 

steel; Nickel 

alloy

Secondary 

feedwater/ steam

Cracking/ stress 

corrosion cracking

Chapter XI.M19, “Steam Generator 

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No
NUREG-1801, Rev. 1 IV D1-6 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

D1 Steam Generator (Recirculating)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.D1-15

(RP-15)

IV.D1. Steam 

generator 

structural

Anti-vibration 

bars

Chrome 

plated steel; 

stainless 

steel; Nickel 

alloy

Secondary 

feedwater/ steam

Loss of material/ 

crevice corrosion 

and fretting

Chapter XI.M19, “Steam Generator 

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No

IV.D1-16

(R-41)

IV.D1.2-h Steam 

generator 

structural

Tube support 

lattice bars

Steel Secondary 

feedwater/ steam

Wall thinning/ 

flow-accelerated 

corrosion

Chapter XI.M19, “Steam Generator 

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No

IV.D1-17

(R-42)

IV.D1.2-k Steam 

generator 

structural

Tube support 

plates

Steel Secondary 

feedwater/ steam

Ligament 

cracking/ 

corrosion

Chapter XI.M19, “Steam Generator

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No

IV.D1-18

(R-40)

IV.D1.2-j 

IV.D1.2-i

Tube plugs Nickel alloy Reactor coolant Cracking/ primary 

water stress 

corrosion cracking

Chapter XI.M19, “Steam Generator 

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No
September 2005 IV D1-7 NURE

G-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

D1 Steam Generator (Recirculating)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.D1-19

(R-43)

IV.D1.2-g Tubes Nickel alloy Secondary 

feedwater/ steam

Denting/ corrosion 

of carbon steel 

tube support plate

Chapter XI.M19, “Steam Generator 

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water.

For plants that could experience 

denting at the upper support plates, the 

applicant should evaluate potential for 

rapidly propagating cracks and then 

develop and take corrective actions 

consistent with Bulletin 88-02, 

“Rapidly Propagating Cracks in SG 

Tubes."

No

IV.D1-20

(R-44)

IV.D1.2-a Tubes and 

sleeves

Nickel alloy Reactor coolant Cracking/ primary 

water stress 

corrosion cracking

Chapter XI.M19, “Steam Generator 

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No

IV.D1-21

(R-46)

IV.D1.2-d Tubes and 

sleeves

Nickel alloy Reactor coolant 

and secondary 

feedwater/steam

Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA

IV.D1-22

(R-48)

IV.D1.2-c Tubes and 

sleeves

Nickel alloy Secondary 

feedwater/ steam

Cracking/ 

intergranular 

attack

Chapter XI.M19, “Steam Generator 

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No
NUREG-1801, Rev. 1 IV D1-8 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

D1 Steam Generator (Recirculating)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.D1-23

(R-47)

IV.D1.2-b Tubes and 

sleeves

Nickel alloy Secondary 

feedwater/ steam

Cracking/ outer 

diameter stress 

corrosion cracking

Chapter XI.M19, “Steam Generator 

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No

IV.D1-24

(R-49)

IV.D1.2-e Tubes and 

sleeves

Nickel alloy Secondary 

feedwater/ steam

Loss of material/ 

fretting and wear

Chapter XI.M19, “Steam Generator 

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No

IV.D1-25

(R-50)

IV.D1.2-f Tubes and 

sleeves 

(exposed to 

phosphate 

chemistry)

Nickel alloy Secondary 

feedwater/ steam

Loss of material/ 

wastage and 

pitting corrosion

Chapter XI.M19, “Steam Generator 

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No

IV.D1-26

(R-51)

IV.D1.3-a Upper assembly 

and separators

Feedwater 

inlet ring and 

support

Steel Secondary 

feedwater/ steam

Wall thinning/ 

flow-accelerated 

corrosion

A plant-specific aging management 

program is to be evaluated. Reference 

NRC IN 91-19, "Steam Generator 

Feedwater Distribution Piping 

Damage." 

Yes, plantspecific
September 2005 IV D2-1 NUREG-1801, Rev. 1

D2. STEAM GENERATOR (ONCE-THROUGH)

Systems, Structures, and Components

This section addresses the once-through type steam generators, as found in Babcock & Wilcox 

pressurized water reactors (PWRs), including all internal components and water/steam nozzles 

and safe ends. Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards 

for Water-, Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” 

the primary water side (tube side) of the steam generator is governed by Group A Quality 

Standards, and the secondary water side is governed by Group B Quality Standards.

Common miscellaneous material/environment combinations where aging effects are not 

expected to degrade the ability of the structure or component to perform its intended function for 

the extended period of operation are included in IV.E.

System Interfaces

The systems that interface with the steam generators include the reactor coolant system and 

connected lines (IV.C2), the main steam system (VIII.B1), the feedwater system (VIII.D1), the 

steam generator blowdown system (VIII.F), and the auxiliary feedwater system (VIII.G).
NUREG-1801, Rev. 1 IV D2-2 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

D2 Steam Generator (Once-Through)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.D2-1

(R-17)

IV.D2.1-j 

IV.D2.1-b

External 

surfaces

Steel Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid Corrosion” No

IV.D2-2

(R-01)

IV.D2.1-h Instrument 

penetrations and 

primary side 

nozzles, safe 

ends, and welds

Nickel alloy; 

steel with 

nickel-alloy 

cladding

Reactor coolant Cracking/ primary 

water stress 

corrosion cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components, and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water and

For nickel alloy, comply with applicable 

NRC Orders and provide a commitment 

in the FSAR supplement to submit a 

plant-specific AMP to implement 

applicable (1) Bulletins and Generic 

Letters and (2) staff-accepted industry 

guidelines.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.D2-3

(R-222)

IV.D2.1-c Once-through 

steam generator 

components:

Primary side 

nozzles

Safe ends and 

welds

Steel; 

stainless 

steel; steel 

with nickelalloy or 

stainless 

steel 

cladding; 

nickel-alloy

Reactor coolant Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be performed for the period of 

extended operation, and, for Class 1 

components, environmental effects on 

fatigue are to be addressed. See the 

Standard Review Plan, Section 4.3 

“Metal Fatigue,” for acceptable 

methods for meeting the requirements 

of 10 CFR 54.21(c)(1).

Yes,

TLAA
September 2005 IV D2-3 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

D2 Steam Generator (Once-Through)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.D2-4

(R-35)

IV.D2.1-a Primary side 

components

Upper and 

lower heads

Tube sheets 

and tube-totube sheet 

welds

Steel with 

stainless 

steel or 

nickel alloy 

cladding

Reactor coolant Cracking/ stress 

corrosion 

cracking, primary 

water stress 

corrosion cracking

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 1 

components, and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water and

For nickel alloy, comply with applicable 

NRC Orders and provide a commitment 

in the FSAR supplement to implement 

applicable (1) Bulletins and Generic 

Letters and (2) staff-accepted industry 

guidelines.

No, but 

licensee 

commitment 

needs to be 

confirmed

IV.D2-5

(R-31)

IV.D2.1-l Secondary 

manways and 

handholes 

(cover only)

Steel Air with leaking 

secondary-side 

water and/or 

steam

Loss of material/ 

erosion

Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD,” for Class 2 

components

No

IV.D2-6

(R-32)

IV.D2.1-k Steam generator 

closure bolting

Steel System 

temperature up to 

340°C (644°F)

Loss of preload/ 

thermal effects, 

gasket creep, and 

self-loosening

Chapter XI.M18, “Bolting Integrity” No
NUREG-1801, Rev. 1 IV D2-4 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

D2 Steam Generator (Once-Through)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.D2-7

(R-38)

IV.D2.1-f Steam generator 

components

feedwater and 

auxiliary 

feedwater 

nozzles and 

safe ends

Steam nozzles 

and safe ends

Steel Secondary 

feedwater/ steam

Wall thinning/ 

flow-accelerated 

corrosion

Chapter XI.M17, “Flow-Accelerated 

Corrosion”

No

IV.D2-8

(R-224)

IV.D2.1-e Steam generator 

components

Shell 

assembly

Steel Secondary 

feedwater/ steam

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

IV.D2-9

(R-36)

IV.D2.1-i Steam generator 

components

Such as 

secondary side 

nozzles (vent, 

drain, and 

instrumentatio

n)

Nickel alloy Secondary 

feedwater/ steam

Cracking/ stress 

corrosion cracking

Chapter XI.M2, "Water Chemistry" and

Chapter XI.M32 "One-Time Inspection" 

or Chapter XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, 

IWC, and IWD.” 

No
September 2005 IV D2-5 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

D2 Steam Generator (Once-Through)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.D2-10

(R-33)

IV.D2.1-g 

IV.D2.1-d

Steam generator 

components

Top head;

Steam nozzle 

and safe end;

Upper and 

lower shell;

FW and AFW 

nozzle and 

safe end;

FW 

impingement 

plate and 

support

Steel Secondary 

feedwater/ steam

Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA

IV.D2-11

(R-42)

IV.D2. Steam generator 

structural

Tube support 

plates

Steel Secondary 

feedwater/ steam

Ligament 

cracking/ 

corrosion

Chapter XI.M19, “Steam Generator 

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No

IV.D2-12

(R-40)

IV.D2.2-g 

IV.D2.2-f

Tube plugs Nickel alloy Reactor coolant Cracking/ primary 

water stress 

corrosion cracking

Chapter XI.M19, “Steam Generator 

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No
NUREG-1801, Rev. 1 IV D2-6 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

D2 Steam Generator (Once-Through)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.D2-13

(R-226)

IV.D2. Tubes Nickel alloy Secondary 

feedwater/ steam

Denting/ corrosion 

of carbon steel 

tube support plate

Chapter XI.M19, “Steam Generator 

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water. 

No

IV.D2-14

(R-44)

IV.D2.2-a Tubes and 

sleeves

Nickel alloy Reactor coolant Cracking/ primary 

water stress 

corrosion cracking

Chapter XI.M19, “Steam Generator 

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No

IV.D2-15

(R-46)

IV.D2.2-e Tubes and 

sleeves

Nickel alloy Reactor coolant 

and secondary 

feedwater/steam

Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA

IV.D2-16

(R-48)

IV.D2.2-c Tubes and 

sleeves

Nickel alloy Secondary 

feedwater/ steam

Cracking/ 

intergranular 

attack

Chapter XI.M19, “Steam Generator 

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No

IV.D2-17

(R-47)

IV.D2.2-b Tubes and 

sleeves

Nickel alloy Secondary 

feedwater/ steam

Cracking/ outer 

diameter stress 

corrosion cracking

Chapter XI.M19, “Steam Generator 

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No
September 2005 IV D2-7 NUREG-1801, Rev. 1

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

D2 Steam Generator (Once-Through)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.D2-18

(R-49)

IV.D2.2-d Tubes and 

sleeves

Nickel alloy Secondary 

feedwater/ steam

Loss of material/ 

fretting and wear

Chapter XI.M19, “Steam Generator 

Tubing Integrity” and

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No
NUREG-1801, Rev. 1 IV D2-8 September 2005

This Page Intentionally Left Blank
September 2005 IV E-1 NUREG-1801, Rev. 1

E. COMMON MISCELLANEOUS MATERIAL/ENVIRONMENT COMBINATIONS

Systems, Structures, and Components

This section addresses the aging management programs for miscellaneous 

material/environment combinations which may be found throughout the reactor vessel, internals 

and reactor coolant system’s structures and components. For the material/environment 

combinations in this part, aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation, therefore, no 

resulting aging management programs for these structures and components are required.

System Interfaces

The structures and components covered in this section belong to the engineered safety features 

in PWRs and BWRs. (For example, see System Interfaces in V.A to V.D2 for details.) 
NUREG-1801, Rev. 1 IV E-2 September 2005

IV REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM 

E Common Miscellaneous Material Environment Combinations

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

IV.E-1

(RP-03)

IV.E. Piping, piping 

components, 

and piping 

elements

Nickel alloy Air – indoor 

uncontrolled 

(External)

None None No

IV.E-2

(RP-04)

IV.E. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Air – indoor 

uncontrolled 

(External)

None None No

IV.E-3

(RP-05)

IV.E. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Air with borated 

water leakage

None None No

IV.E-4

(RP-06)

IV.E. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Concrete None None No

IV.E-5

(RP-07)

IV.E. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Gas None None No

IV.E-6

(RP-01)

IV.E. Piping, piping 

components, 

and piping 

elements

Steel Concrete None None No
September 2005 V-i NUREG-1801, Rev. 1

CHAPTER V

ENGINEERED SAFETY FEATURES
NUREG-1801, Rev. 1 V-ii September 2005

This Page Intentionally Left Blank
September 2005 V-iii NUREG-1801, Rev. 1

MAJOR PLANT SECTIONS

A. Containment Spray System (Pressurized Water Reactors)

B. Standby Gas Treatment System (Boiling Water Reactors)

C. Containment Isolation Components

D1. Emergency Core Cooling System (Pressurized Water Reactors)

D2. Emergency Core Cooling System (Boiling Water Reactors)

E. External Surfaces of Components and Miscellaneous Bolting

F. Common Miscellaneous Material/Environment Combinations
NUREG-1801, Rev. 1 V-iv September 2005

This Page Intentionally Left Blank
September 2005 V A-1 NUREG-1801, Rev. 1

A. CONTAINMENT SPRAY SYSTEM (PRESSURIZED WATER REACTORS)

Systems, Structures, and Components

This section addresses the containment spray system for pressurized water reactors (PWRs) 

designed to lower the pressure, temperature, and gaseous radioactivity (iodine) content of the 

containment atmosphere following a design basis event. Spray systems using chemically 

treated borated water are reviewed. The system consists of piping and valves, including 

containment isolation valves, flow elements, orifices, pumps, spray nozzles, eductors, and the 

containment spray system heat exchanger (for some plants). 

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” all 

components that comprise the containment spray system outside or inside the containment are 

governed by Group B Quality Standards. 

Pumps and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are also subject to replacement based on qualified life or a specified time 

period. Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in V.E. Common miscellaneous material/environment 

combinations, where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation, are included in 

V.F. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the containment spray system are the PWR emergency core 

cooling (V.D1), and open- or closed-cycle cooling water systems (VII.C1 or VII.C2). 
NUREG-1801, Rev. 1 V A-2 September 2005

V ENGINEERED SAFETY FEATURES

A Containment Spray System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.A-1

(E-26)

V.A.5-a 

V.A.2-a

Ducting, piping 

and 

components 

external 

surfaces

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

V.A-2

(EP-42)

V.A. Encapsulation 

Components

Steel Air – indoor 

uncontrolled 

(Internal)

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M38, "Inspection of Internal 

Surfaces in Miscellaneous Piping and 

Ducting Components"

No

V.A-3

(EP-43)

V.A. Encapsulation 

Components

Steel Air with borated 

water leakage 

(Internal)

Loss of material/ 

general, pitting, 

crevice and boric 

acid corrosion

Chapter XI.M38, "Inspection of Internal 

Surfaces in Miscellaneous Piping and 

Ducting Components"

No

V.A-4

(E-28)

V.A.6-d 

V.A.4-b 

V.A.3-b 

V.A.1-b 

V.A.5-b

External 

surfaces

Steel Air with borated 

water leakage

Loss of material/ 

boric acid corrosion

Chapter XI.M10, “Boric Acid Corrosion” No

V.A-5

(EP-13)

V.A. Heat 

exchanger 

components

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

V.A-6

(EP-37)

V.A. Heat 

exchanger 

components

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

V.A-7

(E-19)

V.A.6-c Heat 

exchanger 

components

Stainless 

steel

Closed cycle 

cooling water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No
September 2005 V A-3 NUREG-1801, Rev. 1

V ENGINEERED SAFETY FEATURES

A Containment Spray System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.A-8

(E-20)

V.A.6-a Heat 

exchanger 

components

Stainless 

steel

Raw water Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced 

corrosion, and 

fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

V.A-9

(E-17)

V.A.6-c Heat 

exchanger 

components

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, 

crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

V.A-10

(E-18)

V.A.6-a Heat 

exchanger 

components

Steel Raw water Loss of material/ 

general, pitting, 

crevice, galvanic, 

and 

microbiologically 

influenced 

corrosion, and 

fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

V.A-11

(EP-39)

V.A. Heat 

exchanger 

tubes

Copper alloy Closed cycle 

cooling water

Reduction of heat 

transfer/ fouling

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

V.A-12

(EP-47)

V.A. Heat 

exchanger 

tubes

Copper alloy Lubricating oil Reduction of heat 

transfer/ fouling

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
NUREG-1801, Rev. 1 V A-4 September 2005

V ENGINEERED SAFETY FEATURES

A Containment Spray System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.A-13

(EP-35)

V.A. Heat 

exchanger 

tubes

Stainless 

steel

Closed cycle 

cooling water

Reduction of heat 

transfer/ fouling

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

V.A-14

(EP-50)

V.A. Heat 

exchanger 

tubes

Stainless 

steel

Lubricating oil Reduction of heat 

transfer/ fouling

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.A-15

(E-21)

V.A.6-b Heat 

exchanger 

tubes

Stainless 

steel

Raw water Reduction of heat 

transfer/ fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

V.A-16

(EP-34)

V.A. Heat 

exchanger 

tubes

Stainless 

steel

Treated water Reduction of heat 

transfer/ fouling

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.A-17

(EP-40)

V.A. Heat 

exchanger 

tubes

Steel Lubricating oil Reduction of heat 

transfer/ fouling

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
September 2005 V A-5 NUREG-1801, Rev. 1

V ENGINEERED SAFETY FEATURES

A Containment Spray System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.A-18

(E-43)

V.A. Motor Cooler Gray cast 

iron

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

V.A-19

(E-29)

V.A.2-a 

V.A.5-a

Piping and 

components 

internal 

surfaces

Steel Air – indoor 

uncontrolled 

(Internal)

Loss of material/ 

general corrosion

Chapter XI.M38, "Inspection of Internal 

Surfaces in Miscellaneous Piping and 

Ducting Components"

No

V.A-20

(EP-36)

V.A. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

V.A-21

(EP-45)

V.A. Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.A-22

(EP-27)

V.A. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

V.A-23

(EP-33)

V.A. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed cycle 

cooling water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No
NUREG-1801, Rev. 1 V A-6 September 2005

V ENGINEERED SAFETY FEATURES

A Containment Spray System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.A-24

(EP-44)

V.A. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed cycle 

cooling water 

>60°C (>140°F)

Cracking/ stress 

corrosion cracking

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

V.A-25

(EP-46)

V.A. Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.A-26

(EP-53)

V.A. Piping, piping 

components, 

piping 

elements 

internal 

surfaces, and 

tanks 

Stainless 

steel

Condensation 

(Internal)

Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

V.A-27

(EP-41)

V.A. Piping, piping 

components, 

piping 

elements, and 

tanks

Stainless 

steel

Treated borated 

water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No

V.A-28

(E-12)

V.A.1-a 

V.A.3-a 

V.A.4-a 

V.A.1-c

Piping, piping 

components, 

piping 

elements, and 

tanks

Stainless 

steel

Treated borated 

water >60°C 

(>140°F)

Cracking/ stress 

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No
September 2005 V B-1 NUREG-1801, Rev. 1

B. STANDBY GAS TREATMENT SYSTEM (BOILING WATER REACTORS)

Systems, Structures, and Components

This section addresses the standby gas treatment system found in boiling water reactors 

(BWRs) and consists of ductwork, filters, and fans. Based on Regulatory Guide 1.26, “Quality 

Group Classifications and Standards for Water-, Steam-, and Radioactive-Waste-Containing 

Components of Nuclear Power Plants,” all components that comprise the standby gas treatment 

system are governed by Group B Quality Standards. 

Specifically, charcoal absorber filters are to be addressed consistent with the NRC position on 

consumables, provided in the NRC letter from Christopher I. Grimes to Douglas J. Walters of 

NEI, dated March 10, 2000. Components that function as system filters are typically replaced 

based on performance or condition monitoring that identifies whether these components are at 

the end of their qualified lives and may be excluded, from an aging management review (on a 

plant-specific basis), under 10 CFR 54.21(a)(1)(ii). As part of the methodology description, the 

application should identify the standards that are relied on for replacement, for example, National 

Fire Protection Association (NFPA) standards for fire protection equipment.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in V.E. Common miscellaneous material/environment 

combinations, where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation, are included in 

V.F.

System Interfaces

There are no system interfaces with the standby gas treatment system addressed in this 

section. 
NUREG-1801, Rev. 1 V B-2 September 2005

V ENGINEERED SAFETY FEATURES

B Standby Gas Treatment System (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.B-1

(E-25)

V.B.2-a Ducting and 

components 

internal 

surfaces

Steel Air – indoor 

uncontrolled 

(Internal)

Loss of material/ 

general corrosion

Chapter XI.M38, "Inspection of Internal 

Surfaces in Miscellaneous Piping and 

Ducting Components"

No

V.B-2

(E-40)

V.B.1-a Ducting

closure bolting

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

V.B-3

(E-26)

V.B.2-a 

V.B.1-a

Ducting, 

piping and 

components 

external 

surfaces

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

V.B-4

(E-06)

V.B.2-b 

V.B.1-b

Elastomer 

seals and 

components

Elastomers Air – indoor 

uncontrolled

Hardening and loss 

of strength/ 

elastomer 

degradation

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

V.B-5

(EP-37)

V.B. Heat 

exchanger 

components

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

V.B-6

(EP-36)

V.B. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

V.B-7

(EP-27)

V.B. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No
September 2005 V B-3 NUREG-1801, Rev. 1

V ENGINEERED SAFETY FEATURES

B Standby Gas Treatment System (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.B-8

(EP-54)

V.B. Piping, piping 

components, 

and piping 

elements

Gray cast

iron

Soil Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials" 

No

V.B-9

(E-42)

V.B. Piping, piping 

components, 

and piping 

elements

Steel (with or 

without 

coating or 

wrapping)

Soil Loss of material/ 

general, pitting, 

crevice, and 

microbiologically 

influenced 

corrosion

Chapter XI.M28, “Buried Piping and 

Tanks Surveillance,” or

Chapter XI.M34, “Buried Piping and 

Tanks Inspection”

No 

Yes, detection 

of aging 

effects and 

operating 

experience are 

to be further 

evaluated
NUREG-1801, Rev. 1 V B-4 September 2005

This Page Intentionally Left Blank
September 2005 V C-1 NUREG-1801, Rev. 1

C. CONTAINMENT ISOLATION COMPONENTS

Systems, Structures, and Components

This section addresses the containment isolation components found in all designs of boiling 

water reactors (BWR) and pressurized water reactors (PWR) in the United States. The system 

consists of isolation barriers in lines for BWR and PWR nonsafety systems such as the plant 

heating, waste gas, plant drain, liquid waste, and cooling water systems. Based on Regulatory 

Guide 1.26, “Quality Group Classifications and Standards for Water-, Steam-, and RadioactiveWaste-Containing Components of Nuclear Power Plants,” all components that comprise the 

containment isolation components are governed by Group A or B Quality Standards. 

The aging management programs for hatchways, hatch doors, penetration sleeves, penetration 

bellows, seals, gaskets, and anchors are addressed in II.A and II.B. The containment isolation 

valves for in-scope systems are addressed in the appropriate sections in IV, VII, and VIII. 

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in V.E. Common miscellaneous material/environment

combinations, where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation, are included in 

V.F.

System Interfaces

There are no system interfaces with the containment isolation components addressed in this 

section. 
NUREG-1801, Rev. 1 V C-2 September 2005

V ENGINEERED SAFETY FEATURES

C Containment Isolation Components

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.C-1

(E-35)

V.C.1-a Containment 

isolation piping 

and 

components 

external 

surfaces

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

V.C-2

(E-30)

V.C.1-a Containment 

isolation piping 

and 

components 

external 

surfaces

Steel Condensation 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

V.C-3

(E-34)

V.C.1-b Containment 

isolation piping 

and 

components 

internal 

surfaces

Stainless 

steel

Raw water Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced 

corrosion, and 

fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

V.C-4

(E-33)

V.C.1-b Containment 

isolation piping 

and 

components 

internal 

surfaces

Stainless 

steel

Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
September 2005 V C-3 NUREG-1801, Rev. 1

V ENGINEERED SAFETY FEATURES

C Containment Isolation Components

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.C-5

(E-22)

V.C.1-a Containment 

isolation piping 

and 

components 

internal 

surfaces

Steel Raw water Loss of material/ 

general, pitting, 

crevice, and 

microbiologically 

influenced 

corrosion, and 

fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

V.C-6

(E-31)

V.C.1-a Containment 

isolation piping 

and 

components 

internal 

surfaces

Steel Treated water Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.C-7

(EP-33)

V.C. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed cycle 

cooling water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

V.C-8

(EP-44)

V.C. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed cycle 

cooling water 

>60°C (>140°F)

Cracking/ stress 

corrosion cracking

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

V.C-9

(EP-48)

V.C. Piping, piping 

components, 

and piping 

elements

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No
NUREG-1801, Rev. 1 V C-4 September 2005

This Page Intentionally Left Blank
September 2005 V D1-1 NUREG-1801, Rev. 1

D1. EMERGENCY CORE COOLING SYSTEM (PRESSURIZED WATER REACTORS)

Systems, Structures, and Components

This section addresses the emergency core cooling systems for pressurized water reactors 

(PWRs) designed to cool the reactor core and provide safe shutdown following a design basis 

accident. They consist of the core flood system (CFS), residual heat removal (RHR) (or 

shutdown cooling (SDC)), high-pressure safety injection (HPSI), low-pressure safety injection 

(LPSI), and spent fuel pool (SFP) cooling systems, the lines to the chemical and volume control 

system (CVCS), the emergency sump, the HPSI and LPSI pumps, the pump seal coolers, the 

RHR heat exchanger, and the refueling water tank (RWT). 

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” all 

components that comprise the emergency core cooling system are governed by Group B 

Quality Standards. Portions of the RHR, HPSI, and LPSI systems and the CVCS extending from 

the reactor coolant system up to and including the second containment isolation valve are 

governed by Group A Quality Standards and covered in IV.C2.

Pumps and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are also subject to replacement based on qualified life or a specified time 

period. Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in V.E. Common miscellaneous material/environment

combinations, where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation, are included in 

VI.F. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the emergency core cooling system include the reactor coolant 

system and connected lines (IV.C2), the containment spray system (V.A), the spent fuel pool 

cooling and cleanup system (VII.A3), the closed-cycle cooling water system (VII.C2), the ultimate 

heat sink (VII.C3), the chemical and volume control system (VII.E1), and the open-cycle cooling 

water system (service water system) (VII.C1). 
NUREG-1801, Rev. 1 V D1-2 September 2005

V ENGINEERED SAFETY FEATURES

D1 Emergency Core Cooling System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

V.D1-1

(E-28)

V.D1.6-d 

V.D1.5-b 

V.D1.1-d 

V.D1.2-b 

V.D1.8-b 

V.D1.4-c 

V.D1.7-a 

V.D1.3-a

External 

surfaces

Steel Air with borated 

water leakage

Loss of material/ 

boric acid corrosion

Chapter XI.M10, “Boric Acid Corrosion” No

V.D1-2

(EP-13)

V.D1. Heat 

exchanger 

components

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

V.D1-3

(EP-37)

V.D1. Heat 

exchanger 

components

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

V.D1-4

(E-19)

V.D1.5-a 

V.D1.6-a

Heat 

exchanger 

components

Stainless 

steel

Closed cycle 

cooling water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

V.D1-5

(E-20)

V.D1.6-b Heat 

exchanger 

components

Stainless 

steel

Raw water Loss of material/ 

pitting, crevice, and 

microbiologically

influenced 

corrosion, and 

fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

V.D1-6

(E-17)

V.D1.6-a 

V.D1.5-a

Heat 

exchanger 

components

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, 

crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No
September 2005 V D1-3 NUREG-1801, Rev. 1

V ENGINEERED SAFETY FEATURES

D1 Emergency Core Cooling System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

V.D1-7

(E-18)

V.D1.6-b Heat 

exchanger 

components

Steel Raw water Loss of material/ 

general, pitting, 

crevice, galvanic, 

and 

microbiologically 

influenced 

corrosion, and 

fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

V.D1-8

(EP-47)

V.D1. Heat 

exchanger 

tubes

Copper alloy Lubricating oil Reduction of heat 

transfer/ fouling

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.D1-19

(EP-35)

V.D1. Heat 

exchanger 

tubes

Stainless 

steel

Closed cycle 

cooling water

Reduction of heat 

transfer/ fouling

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

V.D1-10

(EP-50)

V.D1. Heat 

exchanger 

tubes

Stainless 

steel

Lubricating oil Reduction of heat 

transfer/ fouling

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
NUREG-1801, Rev. 1 V D1-4 September 2005

V ENGINEERED SAFETY FEATURES

D1 Emergency Core Cooling System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

V.D1-11

(E-21)

V.D1.6-c Heat 

exchanger 

tubes

Stainless 

steel

Raw water Reduction of heat 

transfer/ fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

V.D1-12

(EP-40)

V.D1. Heat 

exchanger 

tubes

Steel Lubricating oil Reduction of heat 

transfer/ fouling

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.D1-13

(E-43)

V.D1. Motor Cooler Gray cast 

iron

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

V.D1-14

(E-24)

V.D1.2-c Orifice 

(miniflow 

recirculation)

Stainless 

steel

Treated borated 

water

Loss of material/ 

erosion

A plant-specific aging management 

program is to be evaluated for erosion 

of the orifice due to extended use of 

the centrifugal HPSI pump for normal 

charging. See Licensee Event Report 

50-275/94-023 for evidence of erosion.

Yes, plantspecific

V.D1-15

(E-01)

V.D1.8-c Partially 

encased tanks 

with breached 

moisture 

barrier

Stainless 

steel

Raw water Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated for pitting 

and crevice corrosion of tank bottom 

because moisture and water can 

egress under the tank due to cracking 

of the perimeter seal from weathering.

Yes, plantspecific
September 2005 V D1-5 NUREG-1801, Rev. 1

V ENGINEERED SAFETY FEATURES

D1 Emergency Core Cooling System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

V.D1-16

(E-47)

V.D1.1-b Piping, piping 

components, 

and piping 

elements

Cast 

austenitic 

stainless 

steel

Treated borated 

water >250°C 

(>482°F)

Loss of fracture 

toughness/ thermal 

aging embrittlement

Chapter XI.M12, “Thermal Aging 

Embrittlement of Cast Austenitic 

Stainless Steel (CASS)”

No

V.D1-17

(EP-36)

V.D1. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

V.D1-19

(EP-45)

V.D1. Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.D1-19

(EP-27)

V.D1. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

V.D1-20

(EP-52)

V.D1. Piping, piping 

components, 

piping 

elements

Gray cast 

iron

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

V.D1-21

(EP-54)

V.D1. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Soil Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials" 

No
NUREG-1801, Rev. 1 V D1-6 September 2005

V ENGINEERED SAFETY FEATURES

D1 Emergency Core Cooling System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

V.D1-22

(EP-33)

V.D1. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed cycle 

cooling water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

V.D1-23

(EP-44)

V.D1. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed cycle 

cooling water 

>60°C (>140°F)

Cracking/ stress 

corrosion cracking

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

V.D1-24

(EP-51)

V.D1. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Lubricating oil Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.D1-25

(EP-55)

V.D1. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Raw water Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced 

corrosion

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

V.D1-26

(EP-31)

V.D1. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Soil Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific
September 2005 V D1-7 NUREG-1801, Rev. 1

V ENGINEERED SAFETY FEATURES

D1 Emergency Core Cooling System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

V.D1-27

(E-13)

V.D1.1-c 

V.D1.4-a

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated borated 

water

Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluated for the 

period of extended operation. See the 

Standard Review Plan, Section 4.3 

“Metal Fatigue,” for acceptable 

methods for meeting the requirements 

of 10 CFR 54.21(c)(1).

Yes,

TLAA

V.D1-28

(EP-46)

V.D1. Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.D1-29

(EP-53)

V.D1. Piping, piping 

components, 

piping 

elements 

internal 

surfaces, and 

tanks 

Stainless 

steel

Condensation 

(Internal)

Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

V.D1-30

(EP-41)

V.D1. Piping, piping 

components, 

piping 

elements, and 

tanks

Stainless 

steel

Treated borated 

water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No
NUREG-1801, Rev. 1 V D1-8 September 2005

V ENGINEERED SAFETY FEATURES

D1 Emergency Core Cooling System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

V.D1-31

(E-12)

V.D1.1-a

V.D1.2-a 

V.D1.8-a 

V.D1.7-b 

V.D1.4-b

Piping, piping 

components, 

piping 

elements, and 

tanks

Stainless 

steel

Treated borated 

water >60°C 

(>140°F)

Cracking/ stress 

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No

V.D1-32

(EP-49)

V.D1. Pump Casings Steel with 

stainless 

steel 

cladding

Treated borated 

water

Loss of material/

cladding breach

A plant-specific aging management 

program is to be evaluated.

Reference NRC Information Notice 94-

63, “Boric Acid Corrosion of Charging 

Pump Casings Caused by Cladding 

Cracks."

Yes, verify 

that plantspecific 

program 

addresses 

cladding 

breach

V.D1-33

(E-38)

V.D1.7-b Safety 

injection tank 

(accumulator)

Steel with 

stainless 

steel 

cladding

Treated borated 

water >60°C 

(>140°F)

Cracking/ stress 

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No
September 2005 V D2-1 NUREG-1801, Rev. 1

D2. EMERGENCY CORE COOLING SYSTEM (BOILING WATER REACTORS)

Systems, Structures, and Components

This section addresses the emergency core cooling systems for boiling water reactors (BWRs) 

designed to cool the reactor core and provide safe shutdown following a design basis accident. 

They consist of the high-pressure coolant injection (HPCI), reactor core isolation cooling (RCIC), 

high-pressure core spray (HPCS), automatic depressurization (ADS), low-pressure core spray 

(LPCS), low-pressure coolant injection (LPCI) and residual heat removal (RHR) systems, 

including various pumps and valves, the RHR heat exchangers, and the drywell and suppression 

chamber spray system (DSCSS). The auxiliary area ventilation system includes RCIC, HPCI, 

RHR, and core spray pump room cooling.

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” all 

components that comprise the emergency core cooling system outside the containment are 

governed by Group B Quality Standards and the portion of the DSCSS inside the containment up 

to the isolation valve is governed by Group A Quality Standards. Portions of the HPCI, RCIC, 

HPCS, LPCS, and LPCI (or RHR) systems extending from the reactor vessel up to and including 

the second containment isolation valve are governed by Group A Quality Standards and covered 

in IV.C1. 

Pumps and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are also subject to replacement based on qualified life or a specified time 

period. Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

The system piping includes all pipe sizes, including instrument piping.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in V.E. Common miscellaneous material/environment

combinations, where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation, are included in 

VI.F.

System Interfaces

The systems that interface with the emergency core cooling system include the reactor vessel 

(IV.A1), the reactor coolant pressure boundary (IV.C1), the feedwater system (VIII.D2), the 

condensate system (VIII.E), the closed-cycle cooling water system (VII.C2), the open-cycle 

cooling water system (VII.C1), and the ultimate heat sink (VII.C3). 
NUREG-1801, Rev. 1 V D2-2 September 2005

V ENGINEERED SAFETY FEATURES

D2 Emergency Core Cooling System (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.D2-1

(E-04)

V.D2.5-b Drywell and 

suppression 

chamber 

spray system 

(internal 

surfaces):

Flow orifice

 Spray 

nozzles

Steel Air – indoor 

uncontrolled 

(Internal)

Loss of material/ 

general corrosion 

and fouling

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

V.D2-2

(E-26)

V.D2.5-a 

V.D2.1-e

Ducting, 

piping and 

components 

external 

surfaces

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

V.D2-3

(EP-13)

V.D2. Heat 

exchanger 

components

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

V.D2-4

(EP-37)

V.D2. Heat 

exchanger 

components

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

V.D2-5

(E-19)

V.D2.4-c Heat 

exchanger 

components

Stainless 

steel

Closed cycle 

cooling water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

V.D2-6

(E-20)

V.D2.4-a Heat 

exchanger 

components

Stainless 

steel

Raw water Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced 

corrosion, and 

fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No
September 2005 V D2-3 NUREG-1801, Rev. 1

V ENGINEERED SAFETY FEATURES

D2 Emergency Core Cooling System (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.D2-7

(E-17)

V.D2.4-c Heat 

exchanger 

components

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, 

crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

V.D2-8

(E-18)

V.D2.4-a Heat 

exchanger 

components

Steel Raw water Loss of material/ 

general, pitting, 

crevice, galvanic, 

and 

microbiologically 

influenced 

corrosion, and 

fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

V.D2-9

(EP-47)

V.D2. Heat 

exchanger 

tubes

Copper alloy Lubricating oil Reduction of heat 

transfer/ fouling

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.D2-10

(EP-35)

V.D2. Heat 

exchanger 

tubes

Stainless 

steel

Closed cycle 

cooling water

Reduction of heat 

transfer/ fouling

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No
NUREG-1801, Rev. 1 V D2-4 September 2005

V ENGINEERED SAFETY FEATURES

D2 Emergency Core Cooling System (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.D2-11

(EP-50)

V.D2. Heat 

exchanger 

tubes

Stainless 

steel

Lubricating oil Reduction of heat 

transfer/ fouling

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.D2-12

(E-21)

V.D2.4-b Heat 

exchanger 

tubes

Stainless 

steel

Raw water Reduction of heat 

transfer/ fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

V.D2-13

(EP-34)

V.D2. Heat 

exchanger 

tubes

Stainless 

steel

Treated water Reduction of heat 

transfer/ fouling

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.D2-14

(EP-40)

V.D2. Heat 

exchanger 

tubes

Steel Lubricating oil Reduction of heat 

transfer/ fouling

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.D2-15

(E-23)

V.D2.4-b Heat 

exchanger 

tubes

Steel Raw water Reduction of heat 

transfer/ fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No
September 2005 V D2-5 NUREG-1801, Rev. 1

V ENGINEERED SAFETY FEATURES

D2 Emergency Core Cooling System (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.D2-16

(E-29)

V.D2.5-a Piping and 

components 

internal 

surfaces

Steel Air – indoor 

uncontrolled 

(Internal)

Loss of material/ 

general corrosion

Chapter XI.M38, "Inspection of Internal 

Surfaces in Miscellaneous Piping and 

Ducting Components"

No

V.D2-17

(E-27)

V.D2.1-e Piping and 

components 

internal 

surfaces

Steel Condensation 

(Internal)

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M38, "Inspection of Internal 

Surfaces in Miscellaneous Piping and 

Ducting Components"

No

V.D2-18

(EP-2)

V.D2. Piping, piping 

components, 

and piping 

elements

Aluminum Air with borated 

water leakage

Loss of material/ 

boric acid corrosion

Chapter XI.M10, “Boric Acid Corrosion” No

V.D2-19

(EP-26)

V.D2. Piping, piping 

components, 

and piping 

elements

Aluminum Treated water Loss of material/

pitting and crevice 

corrosion

Chapter XI.M2, "Water Chemistry" for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.D2-20

(E-11)

V.D2.1-d Piping, piping 

components, 

and piping 

elements

Cast 

austenitic 

stainless 

steel

Treated water 

>250°C 

(>482°F)

Loss of fracture 

toughness/ thermal 

aging embrittlement

Chapter XI.M12, “Thermal Aging 

Embrittlement of Cast Austenitic 

Stainless Steel (CASS)”

No

V.D2-21

(EP-36)

V.D2. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No
NUREG-1801, Rev. 1 V D2-6 September 2005

V ENGINEERED SAFETY FEATURES

D2 Emergency Core Cooling System (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.D2-22

(EP-45)

V.D2. Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.D2-23

(EP-27)

V.D2. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

V.D2-24

(EP-54)

V.D2. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Soil Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials" 

No

V.D2-25

(EP-33)

V.D2. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed cycle 

cooling water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

V.D2-26

(EP-44)

V.D2. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed cycle 

cooling water 

>60°C (>140°F)

Cracking/ stress 

corrosion cracking

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

V.D2-27

(EP-31)

V.D2. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Soil Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific
September 2005 V D2-7 NUREG-1801, Rev. 1

V ENGINEERED SAFETY FEATURES

D2 Emergency Core Cooling System (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.D2-28

(EP-32)

V.D2. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.D2-29

(E-37)

V.D2.1-c 

V.D2.3-c

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking/ stress 

corrosion cracking 

and intergranular 

stress corrosion 

cracking

Chapter XI.M7, “BWR Stress 

Corrosion Cracking,” and

Chapter XI.M2, “Water Chemistry,” for 

BWR water

No

V.D2-30

(EP-46)

V.D2. Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.D2-31

(E-07)

V.D2.1-f Piping, piping 

components, 

and piping 

elements

Steel Steam Wall thinning/ flowaccelerated 

corrosion

Chapter XI.M17, “Flow-Accelerated 

Corrosion”

No
NUREG-1801, Rev. 1 V D2-8 September 2005

V ENGINEERED SAFETY FEATURES

D2 Emergency Core Cooling System (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.D2-32

(E-10)

V.D2.1-b Piping, piping 

components, 

and piping 

elements

Steel Treated water Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluated for the 

period of extended operation. See the 

Standard Review Plan, Section 4.3 

“Metal Fatigue,” for acceptable 

methods for meeting the requirements 

of 10 CFR 54.21(c)(1).

Yes,

TLAA

V.D2-33

(E-08)

V.D2.3-b 

V.D2.1-a 

V.D2.2-a

Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

V.D2-34

(E-09)

V.D2.3-a Piping, piping 

components, 

and piping 

elements

Steel Treated water Wall thinning/ flowaccelerated 

corrosion

Chapter XI.M17, “Flow-Accelerated 

Corrosion”

No

V.D2-35

(E-14)

V.D2.1-e Piping, piping 

components, 

and piping 

elements 

internal 

surfaces

Stainless 

steel

Condensation 

(Internal)

Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific
September 2005 V E-1 NUREG-1801, Rev. 1

E. EXTERNAL SURFACES OF COMPONENTS AND MISCELLANEOUS BOLTING

Systems, Structures, and Components

This section addresses the aging management programs for the degradation of external 

surfaces of all steel structures and components including closure boltings in the engineered 

safety features in pressurized water reactors (PWRs) and boiling water reactors (BWRs). For 

the steel components in PWRs, this section addresses only boric acid corrosion of external 

surfaces as a result of dripping borated water leaking from an adjacent PWR component. Boric 

acid corrosion can also occur for steel components containing borated water due to leakage,

such components and the related aging management program are covered in the appropriate 

major plant sections in V.

System Interfaces

The structures and components covered in this section belong to the engineered safety features 

in PWRs and BWRs. (For example, see System Interfaces in V.A to V.D2 for details.) 
NUREG-1801, Rev. 1 V E-2 September 2005

V ENGINEERED SAFETY FEATURES

E External Surfaces of Components and Miscellaneous Bolting

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.E-1

(EP-1)

V.E. Bolting Steel Air – outdoor 

(External)

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M18, “Bolting Integrity” No

V.E-2

(E-41)

V.E. Bolting Steel Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid Corrosion” No

V.E-3

(E-03)

V.E.2-b Closure bolting Highstrength 

steel

Air with steam 

or water leakage

Cracking/ cyclic 

loading, stress 

corrosion 

cracking

Chapter XI.M18, “Bolting Integrity” No

V.E-4

(EP-25)

V.E. Closure bolting Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M18, “Bolting Integrity” No

V.E-5

(EP-24)

V.E. Closure bolting Steel Air – indoor 

uncontrolled 

(External)

Loss of preload/ 

thermal effects, 

gasket creep, and 

self-loosening 

Chapter XI.M18, “Bolting Integrity” No

V.E-6

(E-02)

V.E.2-a Closure bolting Steel Air with steam 

or water leakage

Loss of material/ 

general corrosion

Chapter XI.M18, “Bolting Integrity” No

V.E-7

(E-44)

V.E. External 

surfaces

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

V.E-8

(E-45)

V.E. External 

surfaces

Steel Air – outdoor 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

V.E-9

(E-28)

V.E.1-a External 

surfaces

Steel Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid Corrosion” No
September 2005 V E-3 NUREG-1801, Rev. 1

V ENGINEERED SAFETY FEATURES

E External Surfaces of Components and Miscellaneous Bolting

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.E-10

(E-46)

V.E.1-b External 

surfaces

Steel Condensation 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

V.E-11

(EP-38)

V.E. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid Corrosion” No
NUREG-1801, Rev. 1 V E-4 September 2005

This Page Intentionally Left Blank
September 2005 V F-1 NUREG-1801, Rev. 1

F. COMMON MISCELLANEOUS MATERIAL/ENVIRONMENT COMBINATIONS

Systems, Structures, and Components

This section addresses the aging management programs for miscellaneous 

material/environment combinations which may be found throughout the emergency safety 

feature system’s structures and components. For the material/environment combinations in this 

part, aging effects are not expected to degrade the ability of the structure or component to 

perform its intended function for the extended period of operation, and therefore, no resulting 

aging management programs for these structures and components are required.

System Interfaces

The structures and components covered in this section belong to the engineered safety features 

in pressurized water reactors (PWRs) and boiling water reactors (BWRs). (For example, see 

System Interfaces in V.A to V.D2 for details.) 
NUREG-1801, Rev. 1 V F-2 September 2005

V ENGINEERED SAFETY FEATURES

F Common Miscellaneous Material/Environment Combinations

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.F-1

(EP-14)

V.F. Ducting Galvanized 

steel

Air – indoor 

controlled 

(External)

None None No

V.F-2

(EP-3)

V.F. Piping, piping 

components, 

and piping 

elements

Aluminum Air – indoor 

uncontrolled 

(Internal/External)

None None No

V.F-3

(EP-10)

V.F. Piping, piping 

components, 

and piping 

elements

Copper alloy Air – indoor 

uncontrolled 

(External)

None None No

V.F-4

(EP-9)

V.F. Piping, piping 

components, 

and piping 

elements

Copper alloy Gas None None No

V.F-5

(EP-12)

V.F. Piping, piping 

components, 

and piping 

elements

Copper alloy 

<15% Zn

Air with borated 

water leakage

None None No

V.F-6

(EP-15)

V.F. Piping 

elements

Glass Air – indoor 

uncontrolled 

(External)

None None No

V.F-7

(EP-16)

V.F. Piping 

elements

Glass Lubricating oil None None No
September 2005 V F-3 NUREG-1801, Rev. 1

V ENGINEERED SAFETY FEATURES

F Common Miscellaneous Material/Environment Combinations

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.F-8

(EP-28)

V.F. Piping 

elements

Glass Raw water None None No

V.F-9

(EP-30)

V.F. Piping 

elements

Glass Treated borated 

water

None None No

V.F-10

(EP-29)

V.F. Piping 

elements

Glass Treated water None None No

V.F-11

(EP-17)

V.F. Piping, piping 

components, 

and piping 

elements

Nickel alloy Air – indoor 

uncontrolled 

(External)

None None No

V.F-12

(EP-18)

V.F. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Air – indoor 

uncontrolled 

(External)

None None No

V.F-13

(EP-19)

V.F. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Air with borated 

water leakage

None None No

V.F-14

(EP-20)

V.F. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Concrete None None No
NUREG-1801, Rev. 1 V F-4 September 2005

V ENGINEERED SAFETY FEATURES

F Common Miscellaneous Material/Environment Combinations

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

V.F-15

(EP-22)

V.F. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Gas None None No

V.F-16

(EP-4)

V.F. Piping, piping 

components, 

and piping 

elements

Steel Air – indoor 

controlled 

(External)

None None No

V.F-17

(EP-5)

V.F. Piping, piping 

components, 

and piping 

elements

Steel Concrete None None No

V.F-18

(EP-7)

V.F. Piping, piping 

components, 

and piping 

elements

Steel Gas None None No
September 2005 VI-i NUREG-1801, Rev. 1

CHAPTER VI

ELECTRICAL COMPONENTS
NUREG-1801, Rev. 1 VI-ii September 2005

This Page Intentionally Left Blank
September 2005 VI-iii NUREG-1801, Rev. 1

ELECTRICAL COMPONENTS

A. Equipment Not Subject to 10 CFR 50.49 Environmental Qualification Requirements

B. Equipment Subject to 10 CFR 50.49 Environmental Qualification Requirements

 
NUREG-1801, Rev. 1 VI-iv September 2005

This Page Intentionally Left Blank
September 2005 VI A-1 NUREG-1801, Rev. 1

A. EQUIPMENT NOT SUBJECT TO 10 CFR 50.49 ENVIRONMENTAL QUALIFICATION 

REQUIREMENTS

Systems, Structures and Components

This section addresses electrical cables and connections that are not subject to the 

environmental qualification requirements of 10 CFR 50.49, and that are installed in power and 

instrumentation and control (I&C) applications. The power cables and connections addressed 

are low-voltage (<1000V) and medium-voltage (2 kV to 35 kV). High voltage (>35 kV) power 

cables and connections have unique, specialized constructions and must be evaluated on an 

application specific basis.

This section also addresses components that are relied upon to meet the station blackout (SBO) 

requirements for restoration of offsite power. The plant system portion of the offsite power 

system that is used to connect the plant to the offsite power source is included in the SBO 

restoration equipment scope. This path typically includes the switchyard circuit breakers that 

connect to the offsite system power transformers (startup transformers), the transformers 

themselves, the intervening overhead or underground circuits between circuit breaker and 

transformer and transformer and onsite electrical distribution system (including bus ducts or 

cables), and associated control circuits and structures. 

Electrical cables and their required terminations (i.e., connections) are typically reviewed as a 

single commodity. The types of connections included in this review are splices, mechanical 

connectors, fuse holders, and terminal blocks. This common review is translated into program 

actions, which treat cables and connections in the same manner. 

Electrical cables and connections that are in the plant’s environmental qualification (EQ) 

program are addressed in VI.B. 

System Interfaces

Electrical cables and connections functionally interface with all plant systems that rely on 

electric power or instrumentation and control. Electrical cables and connections also interface 

with and are supported by structural commodities (e.g., cable trays, conduit, cable trenches, 

cable troughs, duct banks, cable vaults and manholes) that are reviewed, as appropriate, in the 

Structures and Components Supports section.
NUREG-1801, Rev. 1 VI A-2 September 2005

VI ELECTRICAL COMPONENTS

A Equipment Not Subject to 10 CFR 50.49 Environmental Qualification Requirements

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

VI.A-1

(LP-12)

VI.A. Cable Connections 

(Metallic Parts)

Various 

metals used 

for electrical 

contacts

Air – indoor and 

outdoor

Loosening of bolted 

connections due to 

thermal cycling, ohmic 

heating, electrical 

transients, vibration, 

chemical contamination, 

corrosion, and oxidation

Chapter XI.E6, "Electrical 

Connections Not Subject to 10 

CFR 50.49 Environmental 

Qualification Requirements"

No

VI.A-2

(L-01)

VI.A.1-a Conductor insulation 

for electrical cables 

and connections

Various 

organic 

polymers 

(e.g., EPR, 

SR, EPDM, 

XLPE)

Adverse localized 

environment 

caused by heat, 

radiation, or 

moisture in the 

presence of 

oxygen

Embrittlement, cracking, 

melting, discoloration, 

swelling, or loss of 

dielectric strength 

leading to reduced 

insulation resistance 

(IR); electrical failure/ 

degradation of organics 

(Thermal/ 

thermoxidative), 

radiolysis and 

photolysis (UV sensitive 

materials only) of 

organics; radiationinduced oxidation, and 

moisture intrusion

Chapter XI.E1, “Electrical 

Cables and Connections Not 

Subject to 10 CFR 50.49 

Environmental Qualification 

Requirements” 

No
September 2005 VI A-3 NUREG-1801, Rev. 1

VI ELECTRICAL COMPONENTS

A Equipment Not Subject to 10 CFR 50.49 Environmental Qualification Requirements

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

VI.A-3

(L-02)

VI.A.1-b Conductor insulation 

for electrical cables 

and connections used 

in instrumentation 

circuits that are 

sensitive to reduction 

in conductor 

insulation resistance 

(IR)

Various 

organic 

polymers 

(e.g., EPR, 

SR, EPDM, 

XLPE)

Adverse localized 

environment 

caused by heat, 

radiation, or 

moisture in the 

presence of 

oxygen

Embrittlement, cracking, 

melting, discoloration, 

swelling, or loss of 

dielectric strength 

leading to reduced 

insulation resistance 

(IR); electrical failure/ 

degradation of organics 

(Thermal/ 

thermoxidative), 

radiolysis and 

photolysis (UV sensitive 

materials only) of 

organics; radiationinduced oxidation, and 

moisture intrusion

Chapter XI.E2, "Electrical 

Cables and Connections Not 

Subject to 10 CFR 50.49 

Environmental Qualification 

Requirements Used in 

Instrumentation Circuits"

No

VI.A-4

(L-03)

VI.A.1-c Conductor insulation 

for inaccessible 

medium-voltage (2kV 

to 35kV) cables 

(e.g., installed in 

conduit or direct 

buried)

Various 

organic 

polymers 

(e.g., EPR, 

SR, EPDM, 

XLPE)

Adverse localized 

environment 

caused by 

exposure to 

moisture and 

voltage

Localized damage and 

breakdown of insulation 

leading to electrical 

failure/ moisture 

intrusion, water trees

Chapter XI.E3, "Inaccessible 

Medium Voltage Cables Not 

Subject to 10 CFR 50.49 

Environmental Qualification 

Requirements"

No
NUREG-1801, Rev. 1 VI A-4 September 2005

VI ELECTRICAL COMPONENTS

A Equipment Not Subject to 10 CFR 50.49 Environmental Qualification Requirements

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

VI.A-5

(L-04)

VI.A.2-a Connector contacts 

for electrical 

connectors exposed 

to borated water 

leakage

Various 

metals used 

for electrical 

contacts

Air with borated 

water leakage

Corrosion of connector 

contact surfaces/ 

intrusion of borated 

water

Chapter XI.M10, “Boric Acid 

Corrosion”

No

VI.A-6

(LP-03)

VI.A. Fuse Holders (Not 

Part of a Larger 

Assembly);

Insulation

Insulation 

material –

bakelite, 

phenolic 

melamine or 

ceramic, 

molded 

polycarbonate 

and other

Adverse localized 

environment 

caused by heat, 

radiation, or 

moisture in the 

presence of 

oxygen or > 60-

year service 

limiting 

temperature

Embrittlement, cracking, 

melting, discoloration, 

swelling, or loss of 

dielectric strength 

leading to reduced 

insulation resistance 

(IR); electrical failure/ 

degradation (Thermal/ 

thermoxidative) of 

organics/thermoplastics, 

radiation-induced 

oxidation, moisture 

intrusion and ohmic 

heating

Chapter XI.E1, “Electrical 

Cables and Connections Not 

Subject to 10 CFR 50.49 

Environmental Qualification 

Requirements” 

No
September 2005 VI A-5 NUREG-1801, Rev. 1

VI ELECTRICAL COMPONENTS

A Equipment Not Subject to 10 CFR 50.49 Environmental Qualification Requirements

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

VI.A-7

(LP-02)

VI.A. Fuse Holders (Not 

Part of a Larger 

Assembly);

Insulation

Insulation 

material –

bakelite, 

phenolic 

melamine or 

ceramic, 

molded 

polycarbonate 

and other

Air – indoor 

uncontrolled 

(Internal/External)

None None No

VI.A-8

(LP-01)

VI.A. Fuse Holders (Not 

Part of a Larger 

Assembly);

Metallic Clamp

Copper alloy Air – indoor Fatigue/ohmic heating, 

thermal cycling, 

electrical transients, 

frequent manipulation, 

vibration, chemical 

contamination, 

corrosion, and oxidation

Chapter XI.E5, "Fuse Holders" No

VI.A-9

(LP-07)

VI.A. High voltage 

insulators

Porcelain,

Malleable 

iron, 

aluminum, 

galvanized 

steel, cement

Air – outdoor Degradation of insulator 

quality/presence of any 

salt deposits or surface 

contamination

A plant-specific aging 

management program is to be 

evaluated for plants located 

such that the potential exists for 

salt deposits or surface 

contamination (e.g., in the 

vicinity of salt water bodies or 

industrial pollution). 

Yes, plantspecific
NUREG-1801, Rev. 1 VI A-6 September 2005

VI ELECTRICAL COMPONENTS

A Equipment Not Subject to 10 CFR 50.49 Environmental Qualification Requirements

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

VI.A-10

(LP-11)

VI.A. High voltage 

insulators

Porcelain,

Malleable 

iron, 

aluminum, 

galvanized 

steel, cement

Air – outdoor Loss of material/ 

mechanical wear due to 

wind blowing on 

transmission conductors

A plant-specific aging 

management program is to be 

evaluated.

Yes, plantspecific

VI.A-11

(LP-04)

VI.A. Metal enclosed bus

Bus/connections

Aluminum/ 

Silver Plated 

Aluminum 

Copper/ Silver 

Plated 

Copper; 

Stainless 

steel, steel

Air – indoor and 

outdoor

Loosening of bolted 

connections/ thermal 

cycling and ohmic 

heating

Chapter XI.E4, "Metal Enclosed 

Bus"

No

VI.A-12

(LP-10)

VI.A. Metal enclosed bus

Enclosure 

assemblies

Elastomers Air – indoor and 

outdoor

Hardening and loss of 

strength/ elastomer 

degradation

Chapter XI.S6, “Structures 

Monitoring Program”

No

VI.A-13

(LP-06)

VI.A. Metal enclosed bus

Enclosure 

assemblies

Steel; 

galvanized 

steel

Air – indoor and 

outdoor

Loss of material/ 

general corrosion

Chapter XI.S6, “Structures 

Monitoring Program”

No
September 2005 VI A-7 NUREG-1801, Rev. 1

VI ELECTRICAL COMPONENTS

A Equipment Not Subject to 10 CFR 50.49 Environmental Qualification Requirements

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

VI.A-14

(LP-05)

VI.A. Metal enclosed bus

Insulation/insulators

Porcelain,

xenoy, 

thermo-plastic 

organic 

polymers

Air – indoor and 

outdoor

Embrittlement, cracking, 

melting, discoloration, 

swelling, or loss of 

dielectric strength 

leading to reduced 

insulation resistance 

(IR); electrical failure/ 

thermal/thermoxidative 

degradation of 

organics/thermoplastics, 

radiation-induced 

oxidation; 

moisture/debris 

intrusion, and ohmic 

heating

Chapter XI.E4, "Metal Enclosed 

Bus"

No

VI.A-15

(LP-09)

VI.A. Switchyard bus and 

connections

Aluminum, 

copper, 

bronze, 

stainless 

steel, 

galvanized 

steel

Air – outdoor Loss of material/ wind 

induced abrasion and 

fatigue

Loss of conductor 

strength/ corrosion

Increased resistance of 

connection/ oxidation or 

loss of pre-load

A plant-specific aging 

management program is to be 

evaluated.

Yes, plantspecific
NUREG-1801, Rev. 1 VI A-8 September 2005

VI ELECTRICAL COMPONENTS

A Equipment Not Subject to 10 CFR 50.49 Environmental Qualification Requirements

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

VI.A-16

(LP-08)

VI.A. Transmission 

conductors and 

connections

Aluminum, 

steel

Air – outdoor Loss of material/ wind 

induced abrasion and 

fatigue

Loss of conductor 

strength/ corrosion

Increased resistance of 

connection/ oxidation or 

loss of pre-load

A plant-specific aging 

management program is to be 

evaluated.

Yes, plantspecific
September 2005 VI B-1 NUREG-1801, Rev. 1

B. EQUIPMENT SUBJECT TO 10 CFR 50.49 ENVIRONMENTAL QUALIFICATION 

REQUIREMENTS

Systems, Structures and Components

The Nuclear Regulatory Commission (NRC) has established nuclear station environmental 

qualification (EQ) requirements in 10 CFR Part 50 Appendix A, Criterion 4, and in 

10 CFR 50.49. 10 CFR 50.49 specifically requires that an EQ program be established to 

demonstrate that certain electrical components located in harsh plant environments (i.e., 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. 

10 CFR 50.49 requires that the effects of significant aging mechanisms be addressed as part of 

environmental qualification. Components in the EQ program have a qualified life, and the 

components are replaced at the end of that qualified life, if it is shorter than the current 

operating term. The qualified life may be extended by methods such as refurbishment or 

reanalysis, but the licensee is required by the EQ regulation (10 CFR 50.49) to replace the 

component when its qualified life has expired.

Similarly, some nuclear power plants have mechanical equipment that was qualified in 

accordance with the provisions of Criterion 4 of Appendix A to 10 CFR Part 50.

System Interfaces

Equipment subject to 10 CFR 50.49 environmental qualification requirements functionally 

interfaces with all plant systems that rely on electric power or instrumentation and control.
NUREG-1801, Rev. 1 VI B-2 September 2005

VI ELECTRICAL COMPONENTS

B Equipment Subject to 10 CFR 50.49 Environmental Qualification Requirements

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VI.B-1

(L-05)

VI.B.1-a Electrical 

equipment 

subject to 

10 CFR 50.49 

EQ 

requirements

Various 

polymeric 

and metallic 

materials

Adverse 

localized 

environment 

caused by heat, 

radiation, 

oxygen, 

moisture, or 

voltage

Various 

degradation/ 

various 

mechanisms

EQ is a time-limited aging analysis 

(TLAA) to be evaluated for the period 

of extended operation. See the 

Standard Review Plan, Section 4.4, 

"Environmental Qualification (EQ) of 

Electrical Equipment," for acceptable 

methods for meeting the requirements 

of 10 CFR 54.21(c)(1)(i) and (ii).

See Chapter X.E1, “Environmental 

Qualification (EQ) of Electric 

Components,” of this report for meeting 

the requirements of 10 CFR 

54.21(c)(1)(iii).

Yes,

TLAA
September 2005 VII-i NUREG-1801, Rev. 1

CHAPTER VII

AUXILIARY SYSTEMS 
NUREG-1801, Rev. 1 VII-ii September 2005

This Page Intentionally Left Blank
September 2005 VII-iii NUREG-1801, Rev. 1

MAJOR PLANT SECTIONS

A1. New Fuel Storage

A2. Spent Fuel Storage

A3. Spent Fuel Pool Cooling and Cleanup (PWR)

A4. Spent Fuel Pool Cooling and Cleanup (BWR)

A5. Suppression Pool Cleanup System (BWR)

B. Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems

C1. Open-Cycle Cooling Water System (Service Water System)

C2. Closed-Cycle Cooling Water System

C3. Ultimate Heat Sink

D. Compressed Air System

E1. Chemical and Volume Control System (PWR)

E2. Standby Liquid Control System (BWR)

E3. Reactor Water Cleanup System (BWR)

E4. Shutdown Cooling System (Older BWR)

F1. Control Room Area Ventilation System

F2. Auxiliary and Radwaste Area Ventilation System

F3. Primary Containment Heating and Ventilation System

F4. Diesel Generator Building Ventilation System

G. Fire Protection

H1. Diesel Fuel Oil System

H2. Emergency Diesel Generator System

I. External Surfaces of Components and Miscellaneous Bolting

J. Common Miscellaneous Material/Environment Combinations
NUREG-1801, Rev. 1 VII-iv September 2005

This Page Intentionally Left Blank
September 2005 VII A1-1 NUREG-1801, Rev. 1

A1. NEW FUEL STORAGE

Systems, Structures, and Components

This section discusses those structures and components used for new fuel storage which 

include carbon steel new fuel storage racks located in the auxiliary building or the fuel handling 

building. The racks are exposed to the temperature and humidity in the auxiliary building. The 

racks are generally painted with a protective coating. Based on Regulatory Guide 1.26, “Quality 

Group Classifications and Standards for Water-, Steam-, and Radioactive-Waste-Containing 

Components of Nuclear Power Plants,” all components used for new fuel storage are governed 

by Group C Quality Standards. 

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

System Interfaces

No other systems discussed in this report interface with those used for new fuel storage. 
NUREG-1801, Rev. 1 VII A1-2 September 2005

VII AUXILIARY SYSTEMS 

A1 New Fuel Storage

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.A1-1

(A-94)

VII.A1.1-a Structural 

Steel

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.S6, “Structures Monitoring 

Program”

No
September 2005 VII A2-1 NUREG-1801, Rev. 1

A2. SPENT FUEL STORAGE

Systems, Structures, and Components

This section discusses those structures and components used for spent fuel storage and 

include stainless steel spent fuel storage racks and neutron absorbing materials (e.g., Boraflex, 

Boral, or boron-steel sheets, if used) submerged in chemically treated oxygenated boiling water 

reactor (BWR) or borated pressurized water reactor (PWR) water. The intended function of a 

spent fuel rack is to separate spent fuel assemblies. Boraflex sheets fastened to the storage 

cells provide for neutron absorption and help maintain subcriticality of spent fuel assemblies in 

the spent fuel pool. 

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” all 

components used for spent fuel storage are governed by Group C Quality Standards. In some 

plants, the Boraflex has been replaced by Boral or boron steel. 

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

System Interfaces

No other systems discussed in this report interface with those used for spent fuel storage. 
NUREG-1801, Rev. 1 VII A2-2 September 2005

VII AUXILIARY SYSTEMS 

A2 Spent Fuel Storage

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.A2-1

(AP-79)

VII.A2. Piping, piping 

components, 

and piping 

elements

Stainless 

Steel; Steel 

with 

stainless 

steel 

cladding

Treated borated 

water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No

VII.A2-2

(A-87)

VII.A2.1-a Spent fuel

storage racks

Neutronabsorbing 

sheets -

BWR

Boraflex Treated water Reduction of 

neutron-absorbing 

capacity/ boraflex 

degradation

Chapter XI.M22, “Boraflex Monitoring” No

VII.A2-3

(A-89)

VII.A2.1-b Spent fuel 

storage racks

Neutronabsorbing 

sheets -

BWR

Boral,

boron steel

Treated water Reduction of 

neutron-absorbing 

capacity and loss 

of material/ 

general corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.A2-4

(A-86)

VII.A2.1-a Spent fuel 

storage racks

Neutronabsorbing 

sheets -

PWR

Boraflex Treated borated 

water

Reduction of 

neutron-absorbing 

capacity/ boraflex 

degradation

Chapter XI.M22, “Boraflex Monitoring” No
September 2005 VII A2-3 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

A2 Spent Fuel Storage

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.A2-5

(A-88)

VII.A2.1-b Spent fuel 

storage racks

Neutronabsorbing 

sheets -

PWR

Boral,

boron steel

Treated borated 

water

Reduction of 

neutron-absorbing 

capacity and loss 

of material/ 

general corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.A2-6

(A-96)

VII.A2.1-c Spent fuel 

storage racks

Storage 

racks - BWR

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking/ stress 

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

BWR water

No

VII.A2-7

(A-97)

VII.A2.1-c Spent fuel 

storage racks

Storage 

racks - PWR

Stainless 

steel

Treated borated 

water >60°C 

(>140°F)

Cracking/ stress 

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No
NUREG-1801, Rev. 1 VII A2-4 September 2005

This Page Intentionally Left Blank
September 2005 VII A3-1 NUREG-1801, Rev. 1

A3. SPENT FUEL POOL COOLING AND CLEANUP (PRESSURIZED WATER REACTOR)

Systems, Structures, and Components

This section discusses the pressurized water reactor (PWR) spent fuel pool cooling and 

cleanup system and consists of piping, valves, heat exchangers, filters, linings, demineralizers, 

and pumps. The system contains borated water. The system removes heat from the spent fuel 

pool and transfers heat to the closed-cycle cooling water system, which in turn transfers heat to 

the open-cycle cooling water system. Based on Regulatory Guide 1.26, “Quality Group 

Classifications and Standards for Water-, Steam-, and Radioactive-Waste-Containing 

Components of Nuclear Power Plants,” all components that comprise the PWR spent fuel pool 

cooling and cleanup system are governed by Group C Quality Standards. 

With respect to filters, these items are to be addressed consistent with the Nuclear Regulatory 

Commission (NRC) position on consumables, provided in the NRC letter from Christopher I. 

Grimes to Douglas J. Walters of the Nuclear Energy Institute (NEI), dated March 10, 2000. 

Specifically, components that function as system filters are typically replaced based on 

performance or condition monitoring that identifies whether these components are at the end of 

their qualified lives and may be excluded, on a plant-specific basis, from an aging management 

review under 10 CFR 54.21(a)(1)(ii). As part of the methodology description, the application 

should identify the standards that are relied on for replacement, for example, National Fire 

Protection Association (NFPA) standards for fire protection equipment.

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are also subject to replacement based on qualified life or specified time 

period. Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the PWR spent fuel cooling and cleanup system are the PWR 

emergency core cooling system (V.D1), the closed-cycle cooling water system (VII.C2), and the 

PWR chemical and volume control system (VII.E1). 
NUREG-1801, Rev. 1 VII A3-2 September 2005

VII AUXILIARY SYSTEMS 

A3 Spent Fuel Pool Cooling and Cleanup (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.A3-1

(A-15)

VII.A3.3-a 

VII.A3.2-d 

VII.A3.5-c 

VII.A3.5-a 

VII.A3.3-d 

VII.A3.2-a

Elastomer 

lining

Elastomers Treated borated 

water

Hardening and 

loss of strength/ 

elastomer 

degradation

A plant-specific aging management 

program that determines and assesses 

the qualified life of the linings in the 

environment is to be evaluated.

Yes, plantspecific

VII.A3-2

(A-79)

VII.A3.1-a 

VII.A3.5-b 

VII.A3.3-c 

VII.A3.2-c 

VII.A3.2-b 

VII.A3.4-b 

VII.A3.6-a

External 

surfaces

Steel Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid Corrosion” No

VII.A3-3

(A-63)

VII.A3.4-a Heat 

exchanger 

components

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, 

crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No
September 2005 VII A3-3 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

A3 Spent Fuel Pool Cooling and Cleanup (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.A3-4

(AP-1)

VII.A3. Piping, piping 

components, 

and piping 

elements

Aluminum Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid Corrosion” No

VII.A3-5

(AP-12)

VII.A3. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.A3-6

(AP-43)

VII.A3. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.A3-7

(AP-31)

VII.A3. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.A3-8

(AP-79)

VII.A3. Piping, piping 

components, 

and piping 

elements

Stainless 

Steel; Steel 

with stainless 

steel cladding

Treated borated 

water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No

VII.A3-9

(A-39)

VII.A3.5-a 

VII.A3.3-a 

VII.A3.2-a

Piping, piping 

components, 

and piping 

elements

Steel with 

elastomer 

lining

Treated borated 

water

Loss of material/ 

pitting and crevice 

corrosion (only for 

steel after lining 

degradation)

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter XI.M32, 

“One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated
NUREG-1801, Rev. 1 VII A3-4 September 2005

VII AUXILIARY SYSTEMS 

A3 Spent Fuel Pool Cooling and Cleanup (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.A3-10

(A-56)

VII.A3.3-b Piping, piping 

components, 

and piping 

elements

Steel with 

stainless 

steel cladding

Treated borated 

water >60°C 

(>140°F)

Cracking/ stress 

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No
September 2005 VII A4-1 NUREG-1801, Rev. 1

A4. SPENT FUEL POOL COOLING AND CLEANUP (BOILING WATER REACTOR)

Systems, Structures, and Components

This section discusses the boiling water reactor (BWR) spent fuel pool cooling and cleanup

system and consists of piping, valves, heat exchangers, filters, linings, demineralizers, and 

pumps. The system contains chemically treated oxygenated water. The system removes heat 

from the spent fuel pool, and transfers the heat to the closed-cycle cooling water system, which 

in turn transfers the heat to the open-cycle cooling water system. Based on Regulatory Guide 

1.26, “Quality Group Classifications and Standards for Water-, Steam-, and Radioactive-WasteContaining Components of Nuclear Power Plants,” all components that comprise the BWR 

spent fuel pool cooling and cleanup system are governed by Group C Quality Standards.

With respect to filters, these items are to be addressed consistent with the Nuclear Regulatory 

Commission (NRC) position on consumables, provided in the NRC letter from Christopher I. 

Grimes to Douglas J. Walters of the Nuclear Energy Institute (NEI), dated March 10, 2000.

Specifically, components that function as system filters are typically replaced based on 

performance or condition monitoring that identifies whether these components are at the end of 

their qualified lives and may be excluded, on a plant-specific basis, from an aging management 

review under 10 CFR 54.21(a)(1)(ii). As part of the methodology description, the application 

should identify the standards that are relied on for replacement, for example, National Fire 

Protection Association (NFPA) standards for fire protection equipment. 

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are also subject to replacement based on qualified life or specified time 

period. Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the BWR spent fuel cooling and cleanup system are the closedcycle cooling water system (VII.C2) and the condensate system (VIII.E). 
NUREG-1801, Rev. 1 VII A4-2 September 2005

VII AUXILIARY SYSTEMS 

A4 Spent Fuel Pool Cooling and Cleanup (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.A4-1

(A-16)

VII.A4.5-b 

VII.A4.3-b 

VII.A4.3-a 

VII.A4.2-b 

VII.A4.5-a 

VII.A4.2-a

Elastomer 

lining

Elastomers Treated water Hardening and loss 

of strength/ 

elastomer 

degradation

A plant-specific aging management 

program that determines and assesses 

the qualified life of the linings in the 

environment is to be evaluated.

Yes, plantspecific

VII.A4-2

(A-70)

VII.A4.4-b Heat 

exchanger 

components

Stainless 

steel; steel 

with stainless 

steel cladding

Treated water Loss of material/ 

Pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.A4-3

(A-63)

VII.A4.4-a Heat 

exchanger 

components

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, 

crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.A4-4

(AP-62)

VII.A4. Heat 

exchanger 

tubes

Stainless 

steel

Treated water Reduction of heat 

transfer/ fouling

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated
September 2005 VII A4-3 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

A4 Spent Fuel Pool Cooling and Cleanup (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.A4-5

(AP-38)

VII.A4. Piping, piping 

components, 

and piping 

elements

Aluminum Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, "Water Chemistry"

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.A4-6

(AP-12)

VII.A4. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.A4-7

(AP-64)

VII.A4. Piping, piping 

components, 

and piping 

elements

Copper alloy Treated water Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.A4-8

(AP-43)

VII.A4. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.A4-9

(AP-32)

VII.A4. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.A4-10

(AP-31)

VII.A4. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No
NUREG-1801, Rev. 1 VII A4-4 September 2005

VII AUXILIARY SYSTEMS 

A4 Spent Fuel Pool Cooling and Cleanup (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.A4-11

(A-58)

VII.A4.1-a 

VII.A4.6-a

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.A4-12

(A-40)

VII.A4.5-a 

VII.A4.2-a 

VII.A4.3-a

Piping, piping 

components, 

and piping 

elements

Steel with 

elastomer 

lining or 

stainless 

steel cladding

Treated water Loss of material/ 

pitting and crevice 

corrosion (only for 

steel after 

lining/cladding 

degradation)

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated
September 2005 VII A5-1 NUREG-1801, Rev. 1

A5. SUPPRESSION POOL CLEANUP SYSTEM (BOILING WATER REACTOR)

Systems, Structures, and Components

This section discusses the suppression pool cleanup system, which maintains water quality in 

the suppression pool in boiling water reactors (BWRs). The components of this system include 

piping, filters, valves, and pumps. These components are fabricated of carbon, low-alloy, or 

austenitic stainless steel. Based on Regulatory Guide 1.26, “Quality Group Classifications and 

Standards for Water-, Steam-, and Radioactive-Waste-Containing Components of Nuclear 

Power Plants,” the components that comprise the suppression pool cleanup system are 

governed by the same Group C Quality Standards Group as the corresponding components in 

the spent fuel pool cooling and cleanup system (VII.A4).

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are also subject to replacement based on qualified life or specified time 

period. Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The system that interfaces with the suppression pool cleanup system is the BWR containment 

(II.B), or BWR emergency core cooling system (V.D2). 

Evaluation Summary

There are no tables associated with this section because the suppression pool cleanup system 

in BWRs is similar to the spent fuel pool cooling and cleanup system (VII.A4), and the 

components in the two systems are identical or very similar. Therefore, the reader is referred to 

the section for the spent fuel storage pool system for a listing of aging effects, aging 

mechanisms, and aging management programs that are to be applied to the suppression pool 

cleanup system components. (The only component in VII.A4 that may not be applicable to the 

suppression pool cleanup system is the heat exchanger [VII.A4.4].)
NUREG-1801, Rev. 1 VII A5-2 September 2005

This Page Intentionally Left Blank
September 2005 VII B-1 NUREG-1801, Rev. 1

B. OVERHEAD HEAVY LOAD AND LIGHT LOAD (RELATED TO REFUELING) 

HANDLING SYSTEMS

Systems, Structures, and Components

Most commercial nuclear facilities have between fifty and one hundred cranes. Many of these 

cranes are industrial grade cranes that must meet the requirements of 29 CFR Volume XVII, 

Part 1910, and Section 1910.179. They do not fall within the scope of 10 CFR Part 54.4 and 

therefore are not required to be part of the integrated plant assessment (IPA). Normally fewer 

than ten cranes fall within the scope of 10 CFR Part 54.4. These cranes must comply with the 

requirements provided in 10 CFR Part 50.65 and Reg. Guide 1.160 for monitoring the 

effectiveness of maintenance at nuclear power plants. 

The Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems (the Program) must demonstrate that the testing and the monitoring of the 

maintenance programs have been completed to ensure that the structures, systems, and 

components of these cranes are capable of sustaining their rated loads during the period of 

extended operation. The inspection is also to evaluate whether the usage of the cranes or hoists 

has been sufficient to warrant additional fatigue analysis. It should be noted that many of the 

systems and components of these cranes can be classified as moving parts or as components 

which change configuration, or they may be subject to replacement based on a qualified life. In 

any of these cases, they will not fall within the scope of this Aging Management Review (AMR). 

The primary components that this program is concerned with are the structural girders and 

beams that make up the bridge and the trolley. 

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” all 

components that comprise the overhead heavy load and light load handling systems are 

governed by Group C Quality Standards.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

System Interfaces

No other systems discussed in this report interface with the overhead heavy load and light load 

(related to refueling) handling systems. Physical interfaces exist with the supporting structure. 

The direct interface is at the connection to the structure. 
NUREG-1801, Rev. 1 VII B-2 September 2005

VII AUXILIARY SYSTEMS 

B Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.B-1

(A-05)

VII.B.2-a Cranes - rails Steel Air – indoor

uncontrolled 

(External)

Loss of material/ 

wear

Chapter XI.M23, “Inspection of Overhead 

Heavy Load and Light Load (Related to 

Refueling) Handling Systems”

No

VII.B-2

(A-06)

VII.B.1-a Cranes -

Structural 

girders

Steel Air – indoor 

uncontrolled 

(External)

Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation for structural girders 

of cranes that fall within the scope of 10 

CFR 54. See the Standard Review Plan, 

Section 4.7, “Other Plant-Specific TimeLimited Aging Analyses,” for generic 

guidance for meeting the requirements of 

10 CFR 54.21(c)(1).

Yes,

TLAA

VII.B-3

(A-07)

VII.B.1-b Cranes -

Structural 

girders

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

General corrosion

Chapter XI.M23, “Inspection of Overhead 

Heavy Load and Light Load (Related to 

Refueling) Handling Systems”

No
September 2005 VII C1-1 NUREG-1801, Rev. 1

C1. OPEN-CYCLE COOLING WATER SYSTEM (SERVICE WATER SYSTEM)

Systems, Structures, and Components

This section discusses the open-cycle cooling water (OCCW) (or service water) system, which 

consists of piping, heat exchangers, pumps, flow orifices, basket strainers, and valves, including 

containment isolation valves. Because the characteristics of an OCCW system may be unique 

to each facility, the OCCW system is defined as a system or systems that transfer heat from 

safety-related systems, structures, and components (SSCs) to the ultimate heat sink (UHS) 

such as a lake, ocean, river, spray pond, or cooling tower. The AMPs described in this section 

apply to any such system, provided the service conditions and materials of construction are 

identical to those identified in the section. The system removes heat from the closed-cycle 

cooling water system and, in some plants, other auxiliary systems and components such as 

steam turbine bearing oil coolers, or miscellaneous coolers in the condensate system. The only 

heat exchangers addressed in this section are those removing heat from the closed-cycle 

cooling system. Heat exchangers for removing heat from other auxiliary systems and 

components are addressed in their respective systems, such as those for the steam turbine 

bearing oil coolers (VIII.A) and for the condensate system coolers (VIII.E). 

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” all 

components that comprise the open-cycle cooling water system are governed by Group C 

Quality Standards, with the exception of those forming part of the containment penetration 

boundary which are governed by Group B Quality Standards.

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are also subject to replacement based on qualified life or specified time 

period. Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that may interface with the open-cycle cooling water system include the closedcycle cooling water system (VII.C2), the ultimate heat sink (VII.C3), the emergency diesel 

generator system (VII.H2), the containment spray system (V.A), the PWR steam generator 

blowdown system (VIII.F), the condensate system (VIII.E), the auxiliary feedwater system (PWR) 

(VIII.G), the emergency core cooling system (PWR) (V.D1), and the emergency core cooling 

system (BWR) (V.D2). 
NUREG-1801, Rev. 1 VII C1-2 September 2005

VII AUXILIARY SYSTEMS 

C1 Open-Cycle Cooling Water System (Service Water System)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.C1-1

(AP-75)

VII.C1. Elastomer 

seals and 

components

Elastomers Raw water Hardening and loss 

of strength/ 

elastomer 

degradation

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VII.C1-2

(AP-76)

VII.C1. Elastomer 

seals and 

components

Elastomers Raw water Loss of material/ 

erosion

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VII.C1-3

(A-65)

VII.C1.3-a Heat 

exchanger 

components

Copper alloy Raw water Loss of material/ 

pitting, crevice, 

galvanic, and 

microbiologically 

influenced 

corrosion, and 

fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VII.C1-4

(A-66)

VII.C1.3-a Heat 

exchanger 

components

Copper alloy 

>15% Zn

Raw water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.C1-5

(A-64)

VII.C1.3-a Heat 

exchanger 

components

Steel Raw water Loss of material/ 

general, pitting, 

crevice, galvanic, 

and 

microbiologically 

influenced 

corrosion, and 

fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VII.C1-6

(A-72)

VII.C1.3-b Heat 

exchanger 

tubes

Copper alloy Raw water Reduction of heat 

transfer/ fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VII.C1-7

(AP-61)

VII.C1. Heat 

exchanger 

tubes

Stainless 

steel

Raw water Reduction of heat 

transfer/ fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No
September 2005 VII C1-3 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

C1 Open-Cycle Cooling Water System (Service Water System)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.C1-8

(AP-47)

VII.C1. Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VII.C1-9

(A-44)

VII.C1.2-a 

VII.C1.1-a

Piping, piping 

components, 

and piping 

elements

Copper alloy Raw water Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced 

corrosion, and 

fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VII.C1-10

(A-47)

VII.C1.1-a 

VII.C1.2-a

Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Raw water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.C1-11

(A-51)

VII.C1.5-a Piping, piping 

components, 

and piping 

elements

Gray cast iron Raw water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.C1-12

(A-02)

VII.C1.1-c Piping, piping 

components, 

and piping 

elements

Gray cast iron Soil Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials" 

No

VII.C1-13

(AP-53)

VII.C1. Piping, piping 

components, 

and piping 

elements

Nickel alloy Raw water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No
NUREG-1801, Rev. 1 VII C1-4 September 2005

VII AUXILIARY SYSTEMS 

C1 Open-Cycle Cooling Water System (Service Water System)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.C1-14

(AP-59)

VII.C1. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Lubricating oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VII.C1-15

(A-54)

VII.C1.2-a 

VII.C1.6-a 

VII.C1.1-a 

VII.C1.4-a

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Raw water Loss of material/ 

pitting and crevice 

corrosion, and 

fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VII.C1-16

(AP-56)

VII.C1. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Soil Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.C1-17

(AP-30)

VII.C1. Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
September 2005 VII C1-5 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

C1 Open-Cycle Cooling Water System (Service Water System)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.C1-18

(A-01)

VII.C1.1-b Piping, piping 

components, 

and piping 

elements

Steel (with or 

without 

coating or 

wrapping)

Soil Loss of material/ 

general, pitting, 

crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M28, “Buried Piping and 

Tanks Surveillance,” or

Chapter XI.M34, “Buried Piping and 

Tanks Inspection”

No 

Yes, detection 

of aging 

effects and 

operating 

experience are 

to be further 

evaluated

VII.C1-19

(A-38)

VII.C1.6-a 

VII.C1.2-a 

VII.C1.1-a 

VII.C1.5-a

Piping, piping 

components, 

and piping 

elements

Steel (with or 

without 

lining/coating 

or with 

degraded 

lining/coating)

Raw water Loss of material/ 

general, pitting, 

crevice, and 

microbiologically 

influenced 

corrosion, fouling, 

and lining/coating 

degradation

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No
NUREG-1801, Rev. 1 VII C1-6 September 2005

This Page Intentionally Left Blank
September 2005 VII C2-1 NUREG-1801, Rev. 1

C2. CLOSED-CYCLE COOLING WATER SYSTEM

Systems, Structures, and Components

This section discusses the closed-cycle cooling water (CCCW) system, which consists of 

piping, radiation elements, temperature elements, heat exchangers, pumps, tanks, flow orifices, 

and valves, including containment isolation valves. The system contains chemically treated 

demineralized water. The closed-cycle cooling water system is designed to remove heat from 

various auxiliary systems and components such as the chemical and volume control system 

and the spent fuel cooling system to the open-cycle cooling water system (VII.C1). A CCCW 

system is defined as part of the service water system that does not reject heat directly to a heat 

sink, has water chemistry control, and is not subject to significant sources of contamination. 

Based on RG 1.26, “Quality Group Classifications and Standards for Water-, Steam-, and 

Radioactive-Waste-Containing Components of Nuclear Power Plants,” all components in the 

closed-cycle cooling water system are classified as Group C Quality Standards, with the 

exception of those forming part of the containment penetration boundary which are Group B.

The aging management programs (AMPs) for the heat exchanger between the closed-cycle and 

the open-cycle cooling water systems are addressed in the open-cycle cooling water system 

(VII.C1). The AMPs for the heat exchangers between the closed-cycle cooling water system and 

the interfacing auxiliary systems are included in the evaluations of their respective systems, 

such as those for the pressurized water reactor (PWR) and boiling water reactor (BWR) spent 

fuel pool cooling and cleanup systems (VII.A3 and VII.A4, respectively) and the chemical and 

volume control system (VII.E1).

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are also subject to replacement based on qualified life or specified time 

period. Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the closed-cycle cooling water system include the open-cycle 

cooling water system (VII.C1), the PWR spent fuel pool cooling and cleanup system (VII.A3), the 

BWR spent fuel pool cooling and cleanup system (VII.A4), the chemical and volume control 

system (VII.E1), the BWR reactor water cleanup system (VII.E3), the shutdown cooling system 

(older BWR, VII.E4), the primary containment heating and ventilation system (VII.F3), fire 

protection (VII.G), the emergency diesel generator system (VII.H2), the PWR containment spray 

system (V.A), the PWR and BWR emergency core cooling systems (V.D1 and V.D2), the PWR 
NUREG-1801, Rev. 1 VII C2-2 September 2005

steam generator blowdown system (VIII.F), the condensate system (VIII.E), and the PWR 

auxiliary feedwater system (VIII.G). 
September 2005 VII C2-3 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

C2 Closed-Cycle Cooling Water System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.C2-1

(A-63)

VII.C2. Heat 

exchanger 

components

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, 

crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.C2-2

(AP-80)

VII.C2. Heat 

exchanger 

tubes

Copper Alloy Closed cycle 

cooling water

Reduction of heat 

transfer/ fouling

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.C2-3

(AP-63)

VII.C2. Heat 

exchanger 

tubes

Stainless 

steel

Closed cycle 

cooling water

Reduction of heat 

transfer/ fouling

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.C2-4

(AP-12)

VII.C2. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.C2-5

(AP-47)

VII.C2. Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time Inspection,” 

for an acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.C2-6

(AP-43)

VII.C2. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.C2-7

(AP-32)

VII.C2. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No
NUREG-1801, Rev. 1 VII C2-4 September 2005

VII AUXILIARY SYSTEMS 

C2 Closed-Cycle Cooling Water System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.C2-8

(A-50)

VII.C2.3-a Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.C2-9

(AP-31)

VII.C2. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.C2-10

(A-52)

VII.C2.2-a Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed cycle 

cooling water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.C2-11

(AP-60)

VII.C2. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed cycle 

cooling water 

>60°C (>140°F)

Cracking/ stress 

corrosion cracking

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.C2-12

(AP-59)

VII.C2. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Lubricating oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time Inspection,” 

for an acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated
September 2005 VII C2-5 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

C2 Closed-Cycle Cooling Water System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.C2-13

(AP-30)

VII.C2. Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time Inspection,” 

for an acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.C2-14

(A-25)

VII.C2.3-a 

VII.C2.2-a 

VII.C2.5-a 

VII.C2.4-a 

VII.C2.1-a

Piping, piping 

components, 

piping 

elements, and 

tanks

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No
NUREG-1801, Rev. 1 VII C2-6 September 2005

This Page Intentionally Left Blank
September 2005 VII C3-1 NUREG-1801, Rev. 1

C3. ULTIMATE HEAT SINK

Systems, Structures, and Components

The ultimate heat sink (UHS) consists of a lake, ocean, river, spray pond, or cooling tower. The 

UHS provides sufficient cooling water for safe reactor shutdown and reactor cooldown via the 

residual heat removal system or other similar system. Due to the varying configurations of 

connections to lakes, oceans, and rivers, a plant specific aging management program (AMP) is 

required. Appropriate AMPs shall be provided to trend and project (1) deterioration of earthen 

dams and impoundments; (2) rate of silt deposition; (3) meteorological, climatological, and 

oceanic data since obtaining the Final Safety Analysis Report (FSAR) data; (4) water level 

extremes for plants located on rivers; and (5) aging degradation of all upstream and downstream 

dams affecting the UHS.

The systems, structures, and components included in this section consist of piping, valves, and 

pumps. The cooling tower is addressed in this report on water-control structures (III.A6). The 

ultimate heat sink absorbs heat from the residual heat removal system or other similar system. 

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” the piping 

and valves used for the ultimate heat sink are governed by Group C Quality Standards. 

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are also subject to replacement based on qualified life or specified time 

period. Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the ultimate heat sink include the open-cycle cooling water 

system (VII.C1) and the PWR and BWR emergency core cooling systems (V.D1 and V.D2). 
NUREG-1801, Rev. 1 VII C3-2 September 2005

VII AUXILIARY SYSTEMS 

C3 Ultimate Heat Sink

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.C3-1

(AP-61)

VII.C3. Heat 

exchanger 

tubes

Stainless 

steel

Raw water Reduction of heat 

transfer/ fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VII.C3-2

(A-43)

VII.C3.1-a 

VII.C3.2-a

Piping, piping 

components, 

and piping 

elements

Copper alloy Raw water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VII.C3-3

(A-47)

VII.C3.2-a 

VII.C3.1-a

Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Raw water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.C3-4

(A-51)

VII.C3. Piping, piping 

components, 

and piping 

elements

Gray cast iron Raw water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.C3-5

(A-02)

VII.C3. Piping, piping 

components, 

and piping 

elements

Gray cast iron Soil Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials" 

No

VII.C3-6

(AP-53)

VII.C3. Piping, piping 

components, 

and piping 

elements

Nickel alloy Raw water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VII.C3-7

(A-53)

VII.C3.2-a Piping, piping

components, 

and piping 

elements

Stainless 

steel

Raw water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No
September 2005 VII C3-3 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

C3 Ultimate Heat Sink

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.C3-8

(AP-56)

VII.C3. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Soil Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.C3-9

(A-01)

VII.C3. Piping, piping 

components, 

and piping 

elements

Steel (with or 

without 

coating or 

wrapping)

Soil Loss of material/ 

general, pitting, 

crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M28, “Buried Piping and 

Tanks Surveillance,” or

Chapter XI.M34, “Buried Piping and 

Tanks Inspection”

No 

Yes, detection 

of aging 

effects and 

operating 

experience are 

to be further 

evaluated

VII.C3-10

(A-38)

VII.C3.1-a 

VII.C3.2-a 

VII.C3.3-a

Piping, piping 

components, 

and piping 

elements

Steel (with or 

without 

lining/coating 

or with 

degraded 

lining/coating)

Raw water Loss of material/ 

general, pitting, 

crevice, and 

microbiologically 

influenced 

corrosion, fouling, 

and lining/coating 

degradation

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No
NUREG-1801, Rev. 1 VII C3-4 September 2005

This Page Intentionally Left Blank
September 2005 VII D-1 NUREG-1801, Rev. 1

D. COMPRESSED AIR SYSTEM

Systems, Structures, and Components

This section discusses the compressed air system, which consists of piping, valves (including 

containment isolation valves), air receiver, pressure regulators, filters, and dryers. The system 

components and piping are located in various buildings at most nuclear power plants. Based on 

Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, Steam-, and 

Radioactive-Waste-Containing Components of Nuclear Power Plants,” all components of the 

compressed air system are classified as Group D Quality Standards, with the exception of those 

forming part of the containment penetration boundary which are Group B. However, the 

cleanliness of these components and high air quality is to be maintained because the air 

provides the motive power for instruments and active components (some of them safety-related) 

that may not function properly if nonsafety Group D equipment is contaminated. 

With respect to filters, these items are to be addressed consistent with the Nuclear Regulatory 

Commission (NRC) position on consumables, provided in the NRC letter from Christopher I. 

Grimes to Douglas J. Walters of Nuclear Energy Institute (NEI), dated March 10, 2000. 

Specifically, components that function as system filters are typically replaced based on 

performance or condition monitoring that identifies whether these components are at the end of 

their qualified lives and may be excluded, on a plant-specific basis, from an aging management 

review under 10 CFR 54.21(a)(1)(ii). As part of the methodology description, the application 

should identify the standards that are relied on for replacement, for example, National Fire 

Protection Association (NFPA) standards for fire protection equipment.

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are also subject to replacement based on qualified life or specified time 

period. Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

Various other systems discussed in this report may interface with the compressed air system. 
NUREG-1801, Rev. 1 VII D-2 September 2005

VII AUXILIARY SYSTEMS 

D Compressed Air System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.D-1

(A-103)

VII.D.2-a Closure bolting Steel Condensation Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M18, “Bolting Integrity” No

VII.D-2

(A-26)

VII.D.5-a 

VII.D.6-a 

VII.D.3-a 

VII.D.2-a 

VII.D.4-a 

VII.D.1-a

Compressed 

air system

Piping, piping 

components, 

and piping 

elements

Steel Condensation 

(Internal)

Loss of material/ 

general and pitting 

corrosion

Chapter XI.M24, “Compressed Air 

Monitoring”

No

VII.D-3

(A-80)

VII.D.3-a 

VII.D.5-a 

VII.D.6-a 

VII.D.4-a 

VII.D.2-a 

VII.D.1-a

Piping and 

components 

external 

surfaces

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.D-4

(AP-81)

VII.D. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Condensation 

(Internal)

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M24, “Compressed Air 

Monitoring”

No
September 2005 VII E1-1 NUREG-1801, Rev. 1

E1. CHEMICAL AND VOLUME CONTROL SYSTEM (PRESSURIZED WATER REACTOR)

Systems, Structures, and Components

This section discusses a portion of the pressurized water reactor (PWR) chemical and volume 

control system (CVCS). The portion of the PWR CVCS covered in this section extends from the 

isolation valves associated with the reactor coolant pressure boundary (and Code change as 

discussed below) to the volume control tank. This portion of the PWR CVCS consists of highand low-pressure piping and valves (including the containment isolation valves), regenerative 

and letdown heat exchangers, pumps, basket strainers, and the volume control tank. The 

system contains chemically treated borated water; the shell side of the letdown heat exchanger 

contains closed-cycle cooling water (treated water).

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” all 

components that comprise the CVCS are governed by Group C Quality Standards. Portions of 

the CVCS extending from the reactor coolant system up to and including the isolation valves 

associated with reactor coolant pressure boundary are governed by Group A Quality Standards 

and covered in IV.C2.

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are also subject to replacement based on qualified life or specified time 

period. Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the chemical and volume control system include the reactor 

coolant system (IV.C2), the emergency core cooling system (V.D1), the spent fuel pool cooling 

system (VII.A3), and the closed-cycle cooling water system (VII.C2). 
NUREG-1801, Rev. 1 VII E1-2 September 2005

VII AUXILIARY SYSTEMS 

E1 Chemical and Volume Control System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.E1-1

(A-79)

VII.E1.9-a 

VII.E1.3-b 

VII.E1.10-a 

VII.E1.5-b 

VII.E1.7-b 

VII.E1.6-a 

VII.E1.1-b 

VII.E1.4-a 

VII.E1.2-a 

VII.E1.8-d

External 

surfaces

Steel Air with borated 

water leakage

Loss of material/ 

boric acid corrosion

Chapter XI.M10, “Boric Acid Corrosion” No

VII.E1-2

(AP-34)

VII.E1. Heat 

exchanger 

components

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.E1-3

(AP-65)

VII.E1. Heat 

exchanger 

components

Copper alloy 

>15% Zn

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No
September 2005 VII E1-3 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

E1 Chemical and Volume Control System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.E1-4

(A-100)

VII.E1.8-a Heat 

exchanger 

components

Stainless 

steel

Treated borated 

water

Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA

VII.E1-5

(A-84)

VII.E1.7-c Heat 

exchanger 

components

Stainless 

steel

Treated borated 

water >60°C 

(>140°F)

Cracking/ stress 

corrosion cracking, 

cyclic loading

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

The AMP is to be augmented by 

verifying the absence of cracking due 

to stress corrosion cracking and cyclic 

loading. A plant specific aging 

management program is to be 

evaluated.

Yes, plantspecific

VII.E1-6

(A-63)

VII.E1.8-c Heat 

exchanger 

components

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, 

crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.E1-7

(A-76)

VII.E1.5-a High-pressure 

pump

Casing

Stainless 

steel

Treated borated 

water

Cracking/ stress 

corrosion cracking, 

cyclic loading

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

The AMP is to be augmented by 

verifying the absence of cracking due 

to stress corrosion cracking and cyclic 

loading. A plant specific aging 

management program is to be 

evaluated.

Yes, plantspecific
NUREG-1801, Rev. 1 VII E1-4 September 2005

VII AUXILIARY SYSTEMS 

E1 Chemical and Volume Control System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.E1-8

(A-104)

VII.E1.5-a High-pressure 

pump

Closure 

bolting

Highstrength 

steel

Air with steam or 

water leakage

Cracking/ cyclic 

loading, stress 

corrosion cracking

Chapter XI.M18, “Bolting Integrity.”

The AMP is to be augmented by 

appropriate inspection to detect 

cracking if the bolts are not otherwise 

replaced during maintenance.

Yes, if the 

bolts are not 

replaced during 

maintenance

VII.E1-9

(A-69)

VII.E1.8-b Nonregenerative 

heat 

exchanger 

components

Stainless 

steel

Treated borated 

water >60°C 

(>140°F)

Cracking/ stress 

corrosion cracking, 

cyclic loading

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water.

The AMP is to be augmented by 

verifying the absence of cracking due 

to stress corrosion cracking and cyclic 

loading, or loss of material due to 

pitting and crevice corrosion. An 

acceptable verification program is to 

include temperature and radioactivity 

monitoring of the shell side water, and 

eddy current testing of tubes.

Yes, plantspecific

VII.E1-10

(AP-1)

VII.E1. Piping, piping 

components, 

and piping 

elements

Aluminum Air with borated 

water leakage

Loss of material/ 

boric acid corrosion

Chapter XI.M10, “Boric Acid Corrosion” No

VII.E1-11

(AP-12)

VII.E1. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No
September 2005 VII E1-5 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

E1 Chemical and Volume Control System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.E1-12

(AP-47)

VII.E1. Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time Inspection,” 

for an acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.E1-13

(AP-43)

VII.C2. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.E1-14

(AP-31)

VII.E1. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.E1-15

(AP-59)

VII.E1. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Lubricating oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time Inspection,” 

for an acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated
NUREG-1801, Rev. 1 VII E1-6 September 2005

VII AUXILIARY SYSTEMS 

E1 Chemical and Volume Control System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.E1-16

(A-57)

VII.E1.1-a 

VII.E1.8-a 

VII.E1.7-a 

VII.E1.3-a

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated borated 

water

Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA

VII.E1-17

(AP-79)

VII.E1. Piping, piping 

components, 

and piping 

elements

Stainless 

Steel; Steel 

with 

stainless 

steel 

cladding

Treated borated 

water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No

VII.E1-18

(A-34)

VII.E1.1-a 

VII.E1.8-a 

VII.E1.7-a 

VII.E1.3-a

Piping, piping 

components, 

and piping 

elements

Steel Air – indoor 

uncontrolled

Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA

VII.E1-19

(AP-30)

VII.E1. Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time Inspection,” 

for an acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated
September 2005 VII E1-7 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

E1 Chemical and Volume Control System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.E1-20

(AP-82)

VII.E1. Piping, piping 

components, 

piping 

elements, and 

tanks

Stainless 

steel

Treated borated 

water >60°C 

(>140°F)

Cracking/ stress 

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

No

VII.E1-21

(AP-85)

VII.E1. Pump Casings Steel with 

stainless 

steel 

cladding

Treated borated 

water

Loss of material/

cladding breach

A plant-specific aging management 

program is to be evaluated.

Reference NRC Information Notice 94-

63, “Boric Acid Corrosion of Charging 

Pump Casings Caused by Cladding 

Cracks."

Yes, verify 

plant-specific 

program 

addresses 

cladding 

breach
NUREG-1801, Rev. 1 VII E1-8 September 2005

This Page Intentionally Left Blank
September 2005 VII E2-1 NUREG-1801, Rev. 1

E2.STANDBY LIQUID CONTROL SYSTEM (BOILING WATER REACTOR)

Systems, Structures, and Components

This section discusses the portion of the standby liquid control (SLC) system extending from the 

containment isolation valve to the solution storage tank. The system serves as a backup 

reactivity control system in all boiling water reactors (BWRs). The major components of this 

system are the piping, the solution storage tank, the solution storage tank heaters, valves, and 

pumps. All of the components from the storage tank to the explosive actuated discharge valve 

operate in contact with a sodium pentaborate (Na2B10O16•10H2O) solution.

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” all 

components that comprise the standby liquid control system are governed by Group B Quality 

Standards. The portions of the standby liquid control system extending from the reactor coolant 

pressure boundary up to and including the containment isolation valves are governed by Group A

Quality Standards and are covered in IV.C1.

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are also subject to replacement based on qualified life or specified time 

period. Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The system that interfaces with the SLC system is the BWR reactor pressure vessel (IV.A1). If 

used, the SLC system would inject sodium pentaborate solution into the pressure vessel near 

the bottom of the reactor core. 
NUREG-1801, Rev. 1 VII E2-2 September 2005

VII AUXILIARY SYSTEMS 

E2 Standby Liquid Control System (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.E2-1

(AP-73)

VII.E2. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Sodium 

pentaborate 

solution

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter XI.M32, 

“One-Time Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.E2-2

(A-59)

VII.E2.4-a 

VII.E2.1-a 

VII.E2.2-a 

VII.E2.3-a

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Sodium 

pentaborate 

solution >60°C 

(>140°F)

Cracking/ stress 

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter XI.M32, 

“One-Time Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging effects 

is to be 

evaluated
September 2005 VII E3-1 NUREG-1801, Rev. 1

E3. REACTOR WATER CLEANUP SYSTEM (BOILING WATER REACTOR)

Systems, Structures, and Components

This section discusses the reactor water cleanup (RWCU) system, which provides for cleanup 

and particulate removal from the recirculating reactor coolant in all boiling water reactors 

(BWRs). Some plants may not include the RWCU system in the scope of license renewal, while 

other plants may include the RWCU system because it is associated with safety-related 

functions. 

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” the portion 

of the RWCU system extending from the reactor coolant recirculation system up to and including 

the containment isolation valves for are covered in IV.C1. The remainder of the system outboard 

of the isolation valves is governed by Group C Quality Standards. In this table, only aging 

management programs for RWCU-related piping and components outboard of the isolation 

valves are evaluated. The aging management program for containment isolation valves in the 

RWCU system is evaluated in IV.C1, which concerns the reactor coolant pressure boundary in 

BWRs.

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are also subject to replacement based on qualified life or specified time 

period. Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the BWR reactor water cleanup system include the reactor 

coolant pressure boundary (IV.C1), the closed-cycle cooling water system (VII.C2), and the 

condensate system (VIII.E). 
NUREG-1801, Rev. 1 VII E3-2 September 2005

VII AUXILIARY SYSTEMS 

E3 Reactor Water Cleanup System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) FurtherEvaluation

VII.E3-1

(A-67)

VII.E3.4-b Heat 

exchanger 

components

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Closed cycle 

cooling water

Loss of material/ 

microbiologically 

influenced corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.E3-2

(A-68)

VII.E3.4-a Heat 

exchanger 

components

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Closed cycle 

cooling water 

>60°C (>140°F)

Cracking/ stress 

corrosion cracking

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.E3-3

(A-71)

VII.E3.4-a Heat 

exchanger 

components

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Treated water 

>60°C (>140°F)

Cracking/ stress 

corrosion cracking

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.E3-4

(A-63)

VII.E3. Heat 

exchanger 

components

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, 

crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.E3-5

(AP-63)

VII.E3. Heat 

exchanger 

tubes

Stainless 

steel

Closed cycle 

cooling water

Reduction of heat 

transfer/ fouling

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No
September 2005 VII E3-3 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

E3 Reactor Water Cleanup System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) FurtherEvaluation

VII.E3-6

(AP-62)

VII.E3. Heat 

exchanger 

tubes

Stainless 

steel

Treated water Reduction of heat 

transfer/ fouling

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.E3-7

(AP-38)

VII.E3. Piping, piping 

components, 

and piping 

elements

Aluminum Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, "Water Chemistry"

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.E3-8

(AP-12)

VII.E3. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.E3-9

(AP-64)

VII.E3. Piping, piping 

components, 

and piping 

elements

Copper alloy Treated water Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.E3-10

(AP-43)

VII.E3. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No
NUREG-1801, Rev. 1 VII E3-4 September 2005

VII AUXILIARY SYSTEMS 

E3 Reactor Water Cleanup System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) FurtherEvaluation

VII.E3-11

(AP-32)

VII.E3. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.E3-12

(AP-31)

VII.E3. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.E3-13

(AP-60)

VII.E3. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed cycle 

cooling water 

>60°C (>140°F)

Cracking/ stress

corrosion cracking

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.E3-14

(A-62)

VII.E3.1-b 

VII.E3.2-b

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA

VII.E3-15

(A-58)

VII.E3. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated
September 2005 VII E3-5 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

E3 Reactor Water Cleanup System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) FurtherEvaluation

VII.E3-16

(A-60)

VII.E3.1-a 

VII.E3.2-a

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking/ stress 

corrosion cracking, 

intergranular stress 

corrosion cracking

Chapter XI.M25, “BWR Reactor Water 

Cleanup System”

No

VII.E3-17

(A-34)

VII.E3.2-c Piping, piping 

components, 

and piping 

elements

Steel Air – indoor 

uncontrolled

Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA

VII.E3-18

(A-35)

VII.E3. Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.E3-19

(A-85)

VII.E3.3-d Regenerative 

heat 

exchanger 

components

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking/ stress 

corrosion cracking

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific
NUREG-1801, Rev. 1 VII E3-6 September 2005

This Page Intentionally Left Blank
September 2005 VII E4-1 NUREG-1801, Rev. 1

E4. SHUTDOWN COOLING SYSTEM (OLDER BWR)

Systems, Structures, and Components

This section discusses the shutdown cooling (SDC) system for older vintage boiling water 

reactors (BWRs) and consists of piping and fittings, the SDC system pump, the heat exchanger, 

and valves. 

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” all 

components that comprise the SDC system are governed by Group B Quality Standards. 

Portions of the SDC system extending from the reactor coolant pressure boundary up to and 

including the containment isolation valves are governed by Group A Quality Standards and are

covered in IV.C1.

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are also subject to replacement based on qualified life or specified time 

period. Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the SDC system include the reactor coolant pressure boundary 

(IV.C1) and the closed-cycle cooling water system (VII.C2). 
NUREG-1801, Rev. 1 VII E4-2 September 2005

VII AUXILIARY SYSTEMS 

E4 Shutdown Cooling System (Older BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.E4-1

(A-67)

VII.E4.4-a Heat 

exchanger 

components

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Closed cycle 

cooling water

Loss of material/ 

microbiologically 

influenced corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.E4-2

(A-63)

VII.E4.4-a Heat 

exchanger 

components

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, 

crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.E4-3

(AP-63)

VII.E4. Heat 

exchanger 

tubes

Stainless 

steel

Closed cycle 

cooling water

Reduction of heat 

transfer/ fouling

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.E4-4

(AP-38)

VII.E4. Piping, piping 

components, 

and piping 

elements

Aluminum Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, "Water Chemistry"

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.E4-5

(AP-12)

VII.E4. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No
September 2005 VII E4-3 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

E4 Shutdown Cooling System (Older BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.E4-6

(AP-47)

VII.E4. Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time Inspection,” 

for an acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.E4-7

(AP-64)

VII.E4. Piping, piping 

components, 

and piping 

elements

Copper alloy Treated water Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.E4-8

(AP-43)

VII.E4. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.E4-9

(AP-32)

VII.E4. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.E4-10

(AP-31)

VII.E4. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No
NUREG-1801, Rev. 1 VII E4-4 September 2005

VII AUXILIARY SYSTEMS 

E4 Shutdown Cooling System (Older BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.E4-11

(AP-60)

VII.E4. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed cycle 

cooling water 

>60°C (>140°F)

Cracking/ stress 

corrosion cracking

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.E4-12

(AP-59)

VII.E4. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Lubricating oil Loss of material/

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time Inspection,” 

for an acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.E4-13

(A-62)

VII.E4.1-b Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA

VII.E4-14

(A-58)

VII.E4.1-a Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated
September 2005 VII E4-5 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

E4 Shutdown Cooling System (Older BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.E4-15

(A-61)

VII.E4.3-a 

VII.E4.1-c

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking/ stress 

corrosion cracking

Chapter XI.M7, “BWR Stress Corrosion 

Cracking,” and

Chapter XI.M2, “Water Chemistry,” for 

BWR water

No

VII.E4-16

(AP-30)

VII.E4. Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time Inspection,” 

for an acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.E4-17

(A-35)

VII.E4.1-a 

VII.E4.2-a

Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated
NUREG-1801, Rev. 1 VII E4-6 September 2005

This Page Intentionally Left Blank
September 2005 VII F1-1 NUREG-1801, Rev. 1

F1. CONTROL ROOM AREA VENTILATION SYSTEM

Systems, Structures, and Components

This section discusses the control room area ventilation system (with warm moist air as the 

normal environment), which contains ducts, piping and fittings, equipment frames and housings, 

flexible collars and seals, filters, and heating and cooling air handlers. Based on Regulatory 

Guide 1.26, “Quality Group Classifications and Standards for Water-, Steam-, and RadioactiveWaste-Containing Components of Nuclear Power Plants,” all components that comprise the 

control room area ventilation system are governed by Group B Quality Standards. 

With respect to filters and seals, these items are to be addressed consistent with the Nuclear 

Regulatory Commission (NRC) position on consumables, provided in the NRC letter from 

Christopher I. Grimes to Douglas J. Walters of Nuclear Energy Institute (NEI), dated March 10, 

2000. Specifically, components that function as system filters and seals are typically replaced 

based on performance or condition monitoring that identifies whether these components are at 

the end of their qualified lives and may be excluded, on a plant-specific basis, from an aging 

management review under 10 CFR 54.21(a)(1)(ii). As part of the methodology description, the 

application should identify the standards that are relied on for replacement, for example, National 

Fire Protection Association (NFPA) standards for fire protection equipment.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The system that interfaces with the control room area ventilation system is the auxiliary and 

radwaste area ventilation system (VII.F2). The cooling coils receive their cooling water from other 

systems, such as the hot water heating system or the chilled water cooling system. 
NUREG-1801, Rev. 1 VII F1-2 September 2005

VII AUXILIARY SYSTEMS 

F1 Control Room Area Ventilation System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.F1-1

(A-09)

VII.F1.4-a Ducting and 

components

Stainless 

steel

Condensation Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F1-2

(A-10)

VII.F1.4-a 

VII.F1.1-a

Ducting and 

components 

external 

surfaces

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.F1-3

(A-08)

VII.F1.4-a 

VII.F1.1-a

Ducting and 

components 

internal 

surfaces

Steel Condensation 

(Internal)

Loss of material/ 

general, pitting, 

crevice, and (for drip 

pans and drain 

lines) 

microbiologically 

influenced corrosion 

Chapter XI.M38, "Inspection of Internal 

Surfaces in Miscellaneous Piping and 

Ducting Components"

No

VII.F1-4

(A-105)

VII.F1.1-a Ducting 

closure bolting

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.F1-5

(A-73)

VII.F1.1-c Elastomer 

seals and 

components

Elastomers Air – indoor 

uncontrolled 

(External)

Loss of material/ 

wear

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F1-6

(A-18)

VII.F1.1-c Elastomer 

seals and 

components

Elastomers Air – indoor 

uncontrolled 

(Internal)

Loss of material/ 

wear

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F1-7

(A-17)

VII.F1.4-b 

VII.F1.1-b

Elastomer 

seals and 

components

Elastomers Air – indoor 

uncontrolled 

(Internal/ 

External)

Hardening and loss 

of strength/ 

elastomer 

degradation

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F1-8

(AP-34)

VII.F1. Heat 

exchanger

components

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No
September 2005 VII F1-3 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

F1 Control Room Area Ventilation System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.F1-9

(AP-65)

VII.F1. Heat 

exchanger 

components

Copper alloy 

>15% Zn

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.F1-10

(AP-41)

VII.F1. Heat 

exchanger 

components

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.F1-11

(A-63)

VII.F1. Heat 

exchanger 

components

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, 

crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.F1-12

(AP-80)

VII.F1. Heat 

exchanger 

tubes

Copper Alloy Closed cycle 

cooling water

Reduction of heat 

transfer/ fouling

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.F1-13

(AP-77)

VII.F1. Heat 

exchanger 

tubes

Steel Closed cycle 

cooling water

Reduction of heat 

transfer/ fouling

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.F1-14

(AP-74)

VII.F1. Piping, piping 

components, 

and piping 

elements

Aluminum Condensation Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F1-15

(AP-12)

VII.F1. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.F1-16

(A-46)

VII.F1.2-a Piping, piping 

components, 

and piping 

elements

Copper alloy Condensation 

(External)

Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific
NUREG-1801, Rev. 1 VII F1-4 September 2005

VII AUXILIARY SYSTEMS 

F1 Control Room Area Ventilation System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.F1-17

(AP-43)

VII.F1. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.F1-18

(AP-31)

VII.F1. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.F1-19

(AP-30)

VII.F1. Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time Inspection,” 

for an acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VII.F1-20

(A-25)

VII.F1.3-a Piping, piping 

components, 

piping 

elements, and 

tanks

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No
September 2005 VII F2-1 NUREG-1801, Rev. 1

F2. Auxiliary and Radwaste Area Ventilation System

Systems, Structures, and Components

This section discusses the auxiliary and radwaste areas ventilation systems (with warm moist 

air as the normal environment) and contains ducts, piping and fittings, equipment frames and 

housings, flexible collars and seals, filters, and heating and cooling air handlers. Based on 

Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, Steam-, and 

Radioactive-Waste-Containing Components of Nuclear Power Plants,” all components that 

comprise the auxiliary and radwaste area ventilation system are governed by Group B Quality 

Standards. 

With respect to filters and seals, these items are to be addressed consistent with the NRC 

position on consumables, provided in the NRC letter from Christopher I. Grimes to 

Douglas J. Walters of Nuclear Energy Institute (NEI), dated March 10, 2000. Specifically, 

components that function as system filters and seals are typically replaced based on 

performance or condition monitoring that identifies whether these components are at the end of 

their qualified lives and may be excluded, on a plant-specific basis, from an aging management 

review under 10 CFR 54.21(a)(1)(ii). As part of the methodology description, the application 

should identify the standards that are relied on for replacement, for example, National Fire 

Protection Association (NFPA) standards for fire protection equipment.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the auxiliary and radwaste area ventilation system are the 

control room area ventilation system (VII.F1) and the diesel generator building ventilation system 

(VII.F4). The cooling coils receive their cooling water from other systems, such as the hot water 

heating system or the chilled water cooling system. 
NUREG-1801, Rev. 1 VII F2-2 September 2005

VII AUXILIARY SYSTEMS 

F2 Auxiliary and Radwaste Area Ventilation System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.F2-1

(A-09)

VII.F2.4-a Ducting and 

components

Stainless 

steel

Condensation Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F2-2

(A-10)

VII.F2.1-a 

VII.F2.4-a

Ducting and 

components 

external

surfaces

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.F2-3

(A-08)

VII.F2.1-a 

VII.F2.4-a

Ducting and 

components 

internal 

surfaces

Steel Condensation 

(Internal)

Loss of material/ 

general, pitting, 

crevice, and (for drip 

pans and drain 

lines) 

microbiologically 

influenced corrosion 

Chapter XI.M38, "Inspection of Internal 

Surfaces in Miscellaneous Piping and 

Ducting Components"

No

VII.F2-4

(A-105)

VII.F2.1-a Ducting 

closure bolting

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.F2-5

(A-73)

VII.F2.1-c Elastomer 

seals and 

components

Elastomers Air – indoor 

uncontrolled 

(External)

Loss of material/ 

wear

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F2-6

(A-18)

VII.F2.1-c Elastomer 

seals and 

components

Elastomers Air – indoor 

uncontrolled 

(Internal)

Loss of material/ 

wear

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F2-7

(A-17)

VII.F2.1-b 

VII.F2.4-b

Elastomer 

seals and 

components

Elastomers Air – indoor 

uncontrolled 

(Internal/ 

External)

Hardening and loss 

of strength/ 

elastomer 

degradation

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F2-8

(AP-41)

VII.F2. Heat 

exchanger 

components

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No
September 2005 VII F2-3 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

F2 Auxiliary and Radwaste Area Ventilation System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.F2-9

(A-63)

VII.F2. Heat 

exchanger 

components

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, 

crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.F2-10

(AP-80)

VII.F2. Heat 

exchanger 

tubes

Copper Alloy Closed cycle 

cooling water

Reduction of heat 

transfer/ fouling

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.F2-11

(AP-77)

VII.F2. Heat 

exchanger 

tubes

Steel Closed cycle 

cooling water

Reduction of heat 

transfer/ fouling

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.F2-12

(AP-74)

VII.F2. Piping, piping 

components, 

and piping 

elements

Aluminum Condensation Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F2-13

(AP-12)

VII.F2. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.F2-14

(A-46)

VII.F2.2-a Piping, piping 

components, 

and piping 

elements

Copper alloy Condensation 

(External)

Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F2-15

(AP-43)

VII.F2. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.F2-16

(AP-31)

VII.F2. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No
NUREG-1801, Rev. 1 VII F2-4 September 2005

VII AUXILIARY SYSTEMS 

F2 Auxiliary and Radwaste Area Ventilation System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.F2-17

(AP-30)

VII.F2. Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time Inspection,” 

for an acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VII.F2-18

(A-25)

VII.F2.3-a Piping, piping 

components, 

piping 

elements, and 

tanks

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No
September 2005 VII F3-1 NUREG-1801, Rev. 1

F3. PRIMARY CONTAINMENT HEATING AND VENTILAT ION SYSTEM

Systems, Structures, and Components

This section discusses the primary containment heating and ventilation system (with warm 

moist air as the normal environment), which contains ducts, piping and fittings, equipment 

frames and housings, flexible collars and seals, filters, and heating and cooling air handlers. 

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” all 

components that comprise the primary containment heating and ventilation system are governed 

by Group C Quality Standards. 

With respect to filters and seals, these items are to be addressed consistent with the Nuclear 

Regulatory Commission (NRC) position on consumables, provided in the NRC letter from 

Christopher I. Grimes to Douglas J. Walters of the Nuclear Energy Institute (NEI), dated March 

10, 2000. Specifically, components that function as system filters and seals are typically 

replaced based on performance or condition monitoring that identifies whether these 

components are at the end of their qualified lives and may be excluded, on a plant-specific basis, 

from an aging management review under 10 CFR 54.21(a)(1)(ii). As part of the methodology 

description, the application should identify the standards that are relied on for replacement, for 

example, National Fire Protection Association (NFPA) standards for fire protection equipment.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the primary containment heating and ventilation system are the 

closed-cycle cooling water system (VII.C2) and the PWR and BWR containments (II.A and II.B, 

respectively). The cooling coils receive their cooling water from other systems, such as the hot 

water heating system or the chilled water cooling system. 
NUREG-1801, Rev. 1 VII F3-2 September 2005

VII AUXILIARY SYSTEMS 

F3 Primary Containment Heating and Ventilation System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.F3-1

(A-09)

VII.F3.4-a Ducting and 

components

Stainless 

steel

Condensation Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F3-2

(A-10)

VII.F3.1-a 

VII.F3.4-a

Ducting and 

components 

external 

surfaces

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.F3-3

(A-08)

VII.F3.4-a 

VII.F3.1-a

Ducting and 

components 

internal 

surfaces

Steel Condensation 

(Internal)

Loss of material/ 

general, pitting, 

crevice, and (for drip 

pans and drain 

lines) 

microbiologically 

influenced corrosion 

Chapter XI.M38, "Inspection of Internal 

Surfaces in Miscellaneous Piping and 

Ducting Components"

No

VII.F3-4

(A-105)

VII.F3.1-a Ducting 

closure bolting

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.F3-5

(A-73)

VII.F3.1-c Elastomer 

seals and 

components

Elastomers Air – indoor 

uncontrolled 

(External)

Loss of material/ 

wear

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F3-6

(A-18)

VII.F3.1-c Elastomer 

seals and 

components

Elastomers Air – indoor 

uncontrolled 

(Internal)

Loss of material/

wear

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F3-7

(A-17)

VII.F3.1-b 

VII.F3.4-b

Elastomer 

seals and 

components

Elastomers Air – indoor 

uncontrolled 

(Internal/ 

External)

Hardening and loss 

of strength/ 

elastomer 

degradation

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F3-8

(AP-34)

VII.F3. Heat 

exchanger 

components

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No
September 2005 VII F3-3 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

F3 Primary Containment Heating and Ventilation System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.F3-9

(AP-65)

VII.F3. Heat 

exchanger 

components

Copper alloy 

>15% Zn

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.F3-10

(AP-41)

VII.F3. Heat 

exchanger 

components

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.F3-11

(A-63)

VII.F3. Heat 

exchanger 

components

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, 

crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.F3-12

(AP-80)

VII.F3. Heat 

exchanger 

tubes

Copper Alloy Closed cycle 

cooling water

Reduction of heat 

transfer/ fouling

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.F3-13

(AP-77)

VII.F3. Heat 

exchanger 

tubes

Steel Closed cycle 

cooling water

Reduction of heat 

transfer/ fouling

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.F3-14

(AP-74)

VII.F3. Piping, piping 

components, 

and piping 

elements

Aluminum Condensation Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F3-15

(AP-12)

VII.F3. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.F3-16

(A-46)

VII.F3.2-a Piping, piping 

components, 

and piping 

elements

Copper alloy Condensation 

(External)

Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific
NUREG-1801, Rev. 1 VII F3-4 September 2005

VII AUXILIARY SYSTEMS 

F3 Primary Containment Heating and Ventilation System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.F3-17

(AP-43)

VII.F3. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.F3-18

(A-50)

VII.F3. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.F3-19

(AP-30)

VII.F3. Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time Inspection,” 

for an acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VII.F3-20

(A-25)

VII.F3.3-a Piping, piping 

components, 

piping 

elements, and 

tanks

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No
September 2005 VII F4-1 NUREG-1801, Rev. 1

F4. DIESEL GENERATOR BUILDING VENTILATION SYSTEM

Systems, Structures, and Components

This section discusses the diesel generator building ventilation system (with warm moist air as 

the normal environment), which contains ducts, piping and fittings, equipment frames and 

housings, flexible collars and seals, and heating and cooling air handlers. Based on Regulatory 

Guide 1.26, “Quality Group Classifications and Standards for Water-, Steam-, and RadioactiveWaste-Containing Components of Nuclear Power Plants,” all components that comprise the 

diesel generator building ventilation system are governed by Group C Quality Standards. 

With respect to seals, these items are to be addressed consistent with the Nuclear Regulatory 

Commission (NRC) position on consumables, provided in the NRC letter from Christopher I. 

Grimes to Douglas J. Walters of Nuclear Energy Institute (NEI), dated March 10, 2000. 

Specifically, components that function as system seals are typically replaced based on 

performance or condition monitoring that identifies whether these components are at the end of 

their qualified lives and may be excluded, on a plant-specific basis, from an aging management 

review under 10 CFR 54.21(a)(1)(ii). As part of the methodology description, the application 

should identify the standards that are relied on for replacement, for example, National Fire 

Protection Association (NFPA) standards for fire protection equipment.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The system that interfaces with the diesel generator building system is the auxiliary and 

radwaste area ventilation system (VII.F2). The cooling coils receive their cooling water from other 

systems, such as the hot water heating system or the chilled water cooling system. 
NUREG-1801, Rev. 1 VII F4-2 September 2005

VII AUXILIARY SYSTEMS 

F4 Diesel Generator Building Ventilation System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.F4-1

(A-10)

VII.F4.1-a Ducting and 

components 

external 

surfaces

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.F4-2

(A-08)

VII.F4.1-a Ducting and 

components 

internal 

surfaces

Steel Condensation 

(Internal)

Loss of material/ 

general, pitting, 

crevice, and (for drip 

pans and drain 

lines) 

microbiologically 

influenced corrosion 

Chapter XI.M38, "Inspection of Internal 

Surfaces in Miscellaneous Piping and 

Ducting Components"

No

VII.F4-3

(A-105)

VII.F4.1-a Ducting 

closure bolting

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.F4-4

(A-73)

VII.F4.1-c Elastomer 

seals and 

components

Elastomers Air – indoor 

uncontrolled 

(External)

Loss of material/ 

wear

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F4-5

(A-18)

VII.F4.1-c Elastomer 

seals and 

components

Elastomers Air – indoor 

uncontrolled 

(Internal)

Loss of material/ 

wear

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F4-6

(A-17)

VII.F4.1-b Elastomer 

seals and 

components

Elastomers Air – indoor 

uncontrolled 

(Internal/ 

External)

Hardening and loss 

of strength/ 

elastomer 

degradation

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F4-7

(AP-41)

VII.F4. Heat 

exchanger 

components

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No
September 2005 VII F4-3 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

F4 Diesel Generator Building Ventilation System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.F4-8

(A-63)

VII.F4. Heat 

exchanger 

components

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, 

crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.F4-9

(AP-77)

VII.F4. Heat 

exchanger 

tubes

Steel Closed cycle 

cooling water

Reduction of heat 

transfer/ fouling

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.F4-10

(AP-74)

VII.F4. Piping, piping 

components, 

and piping 

elements

Aluminum Condensation Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F4-11

(AP-12)

VII.F4. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.F4-12

(A-46)

VII.F4.2-a Piping, piping 

components, 

and piping 

elements

Copper alloy Condensation 

(External)

Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.F4-13

(AP-43)

VII.F4. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.F4-14

(AP-31)

VII.F4. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No
NUREG-1801, Rev. 1 VII F4-4 September 2005

VII AUXILIARY SYSTEMS 

F4 Diesel Generator Building Ventilation System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.F4-15

(AP-30)

VII.F4. Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time Inspection,” 

for an acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VII.F4-16

(A-25)

VII.F4.3-a Piping, piping 

components, 

piping 

elements, and 

tanks

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No
September 2005 VII G-1 NUREG-1801, Rev. 1

G. FIRE PROTECTION

Systems, Structures, and Components

This section discusses the fire protection systems for both boiling water reactors (BWRs) and 

pressurized water reactors (PWRs), which consist of several Class 1 structures, mechanical 

systems, and electrical components. The Class 1 structures include the intake structure, the 

turbine building, the auxiliary building, the diesel generator building, and the primary containment. 

Structural components include fire barrier walls, ceilings, floors, fire doors, and penetration 

seals. Mechanical systems include the high pressure service water system, the reactor coolant 

pump oil collect system, and the diesel fire system. Mechanical components include piping and 

fittings, filters, fire hydrants, mulsifiers, pumps, sprinklers, strainers, and valves (including 

containment isolation valves). Based on Regulatory Guide 1.26, “Quality Group Classifications 

and Standards for Water-, Steam-, and Radioactive-Waste-Containing Components of Nuclear 

Power Plants,” all components that comprise the fire protection system are governed by Group 

C Quality Standards. 

With respect to filters, seals, portable fire extinguishers, and fire hoses, these items are to be 

addressed consistent with the NRC position on consumables, provided in the NRC letter from 

Christopher I. Grimes to Douglas J. Walters of Nuclear Energy Institute (NEI), dated March 10, 

2000. Specifically, components that function as system filters, seals, portable fire extinguishers, 

and fire hoses are typically replaced based on performance or condition monitoring that identifies 

whether these components are at the end of their qualified lives and may be excluded, on a 

plant-specific basis, from an aging management review under 10 CFR 54.21(a)(1)(ii). As part of 

the methodology description, the application should identify the standards that are relied on for 

replacement, for example, National Fire Protection Association (NFPA) standards for fire 

protection equipment.

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are also subject to replacement based on qualified life or specified time 

period. Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems and structures that interface with the fire protection system include various Class 1 

structures and component supports (III.A and III.B), the electrical components (VI.A and VI.B), the 

closed-cycle cooling water system (VII.C2), and the diesel fuel oil system (VII.H1).
NUREG-1801, Rev. 1 VII G-2 September 2005

VII AUXILIARY SYSTEMS 

G Fire Protection

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.G-1

(A-19)

VII.G.3-a 

VII.G.1-a 

VII.G.2-a 

VII.G.4-a

Fire barrier 

penetration 

seals

Elastomers Air – indoor 

uncontrolled

Increased hardness, 

shrinkage and loss 

of strength/ 

weathering

Chapter XI.M26, “Fire Protection” No

VII.G-2

(A-20)

VII.G.1-a 

VII.G.3-a 

VII.G.4-a 

VII.G.2-a

Fire barrier 

penetration 

seals

Elastomers Air – outdoor Increased hardness, 

shrinkage and loss 

of strength/ 

weathering

Chapter XI.M26, “Fire Protection” No

VII.G-3

(A-21)

VII.G.2-d 

VII.G.5-c 

VII.G.3-d 

VII.G.4-d 

VII.G.1-d

Fire rated 

doors

Steel Air – indoor 

uncontrolled

Loss of material/ 

wear

Chapter XI.M26, “Fire Protection” No

VII.G-4

(A-22)

VII.G.1-d 

VII.G.2-d 

VII.G.4-d 

VII.G.3-d

Fire rated 

doors

Steel Air – outdoor Loss of material/ 

wear

Chapter XI.M26, “Fire Protection” No

VII.G-5

(AP-41)

VII.G. Heat 

exchanger 

components

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.G-6

(AP-40)

VII.G. Heat 

exchanger 

components

Steel Air – outdoor 

(External)

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.G-7

(AP-61)

VII.G. Heat 

exchanger 

tubes

Stainless 

steel

Raw water Reduction of heat 

transfer/ fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VII.G-8

(AP-83)

VII.G. Piping, piping 

components, 

and piping 

elements

Aluminum Raw water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M26, “Fire Protection” No
September 2005 VII G-3 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

G Fire Protection

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.G-9

(AP-78)

VII.G. Piping, piping 

components, 

and piping 

elements

Copper alloy Condensation 

(Internal)

Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.G-10

(AP-44)

VII.G. Piping, piping 

components, 

and piping 

elements

Copper alloy Fuel oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M30, “Fuel Oil Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of fuel oil 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.G-11

(AP-47)

VII.G. Piping, piping

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time Inspection,” 

for an acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.G-12

(A-45)

VII.G.6-b Piping, piping 

components, 

and piping 

elements

Copper alloy Raw water Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced 

corrosion, and 

fouling

Chapter XI.M27, “Fire Water System” No

VII.G-13

(A-47)

VII.G.6-b Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Raw water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No
NUREG-1801, Rev. 1 VII G-4 September 2005

VII AUXILIARY SYSTEMS 

G Fire Protection

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.G-14

(A-51)

VII.G. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Raw water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.G-15

(A-02)

VII.G. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Soil Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials" 

No

VII.G-16

(AP-31)

VII.G. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.G-17

(AP-54)

VII.G. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Fuel oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M30, “Fuel Oil Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of fuel oil 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.G-18

(AP-59)

VII.G. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Lubricating oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time Inspection,” 

for an acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.G-19

(A-55)

VII.G.6-b 

VII.G.6-a

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Raw water Loss of material/ 

pitting and crevice 

corrosion, and 

fouling

Chapter XI.M27, “Fire Water System” No
September 2005 VII G-5 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

G Fire Protection

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.G-20

(AP-56)

VII.G. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Soil Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.G-21

(A-28)

VII.G.8-a Piping, piping 

components, 

and piping 

elements

Steel Fuel oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M26, “Fire Protection,” and 

Chapter XI.M30, “Fuel Oil Chemistry” 

No

VII.G-22

(AP-30)

VII.G. Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time Inspection,” 

for an acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.G-23

(A-23)

VII.G. Piping, piping 

components, 

and piping 

elements

Steel Moist air or 

condensation 

(Internal)

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M38, "Inspection of Internal 

Surfaces in Miscellaneous Piping and 

Ducting Components"

No

VII.G-24

(A-33)

VII.G.6-a 

VII.G.6-b

Piping, piping 

components, 

and piping 

elements

Steel Raw water Loss of material/ 

general, pitting, 

crevice, and 

microbiologically 

influenced 

corrosion, and 

fouling

Chapter XI.M27, “Fire Water System” No
NUREG-1801, Rev. 1 VII G-6 September 2005

VII AUXILIARY SYSTEMS 

G Fire Protection

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.G-25

(A-01)

VII.G. Piping, piping 

components, 

and piping 

elements

Steel (with or 

without 

coating or 

wrapping)

Soil Loss of material/ 

general, pitting, 

crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M28, “Buried Piping and 

Tanks Surveillance,” or

Chapter XI.M34, “Buried Piping and 

Tanks Inspection”

No 

Yes, detection 

of aging effects 

and operating 

experience are 

to be further 

evaluated

VII.G-26

(A-83)

VII.G.7-b Reactor 

coolant pump 

oil collection 

system

Piping, 

tubing, valve 

bodies

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time Inspection,” 

for an acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.G-27

(A-82)

VII.G.7-a Reactor 

coolant pump 

oil collection 

system

Tank

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented to 

evaluate the thickness of the lower 

portion of the tank. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.G-28

(A-90)

VII.G.2-b 

VII.G.3-b 

VII.G.5-a 

VII.G.4-b 

VII.G.1-b

Structural fire 

barriers:

Walls, 

ceilings and 

floors

Reinforced 

concrete

Air – indoor 

uncontrolled

Concrete cracking 

and spalling/ 

aggressive chemical 

attack, and reaction 

with aggregates

Chapter XI.M26, “Fire Protection” and 

Chapter XI.S6, “Structures Monitoring 

Program”

No
September 2005 VII G-7 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

G Fire Protection

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.G-29

(A-91)

VII.G.4-c 

VII.G.3-c 

VII.G.2-c 

VII.G.1-c 

VII.G.5-b

Structural fire 

barriers:

Walls, 

ceilings and 

floors

Reinforced 

concrete

Air – indoor 

uncontrolled

Loss of material/ 

corrosion of 

embedded steel

Chapter XI.M26, “Fire Protection” and 

Chapter XI.S6, “Structures Monitoring 

Program”

No

VII.G-30

(A-92)

VII.G.1-b 

VII.G.3-b 

VII.G.2-b 

VII.G.4-b

Structural fire 

barriers:

Walls, 

ceilings and 

floors

Reinforced 

concrete

Air – outdoor Concrete cracking 

and spalling/ freezethaw, aggressive 

chemical attack, 

and reaction with 

aggregates

Chapter XI.M26, “Fire Protection” and 

Chapter XI.S6, “Structures Monitoring 

Program”

No

VII.G-31

(A-93)

VII.G.4-c 

VII.G.3-c 

VII.G.1-c 

VII.G.2-c

Structural fire 

barriers:

Walls, 

ceilings and 

floors

Reinforced 

concrete

Air – outdoor Loss of material/ 

corrosion of 

embedded steel

Chapter XI.M26, “Fire Protection” and 

Chapter XI.S6, “Structures Monitoring 

Program”

No
NUREG-1801, Rev. 1 VII G-8 September 2005

This Page Intentionally Left Blank
September 2005 VII H1-1 NUREG-1801, Rev. 1

H1. DIESEL FUEL OIL SYSTEM

Systems, Structures, and Components

This section discusses the diesel fuel oil system, which consists of aboveground and 

underground piping, valves, pumps, and tanks. Based on Regulatory Guide 1.26, “Quality Group 

Classifications and Standards for Water-, Steam-, and Radioactive-Waste-Containing 

Components of Nuclear Power Plants,” all components that comprise the diesel fuel oil system 

are governed by Group C Quality Standards.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the diesel fuel oil system are the fire protection (VII.G) and 

emergency diesel generator systems (VII.H2). 
NUREG-1801, Rev. 1 VII H1-2 September 2005

VII AUXILIARY SYSTEMS 

H1 Diesel Fuel Oil System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.H1-1

(AP-35)

VII.H1. Piping, piping 

components, 

and piping 

elements

Aluminum Fuel oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M30, “Fuel Oil Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of fuel oil 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.H1-2

(AP-12)

VII.H1. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.H1-3

(AP-44)

VII.H1. Piping, piping 

components, 

and piping 

elements

Copper alloy Fuel oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M30, “Fuel Oil Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of fuel oil 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.H1-4

(AP-43)

VII.H1. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.H1-5

(A-02)

VII.H1. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Soil Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of

Materials" 

No
September 2005 VII H1-3 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

H1 Diesel Fuel Oil System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.H1-6

(AP-54)

VII.H1. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Fuel oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M30, “Fuel Oil Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of fuel oil 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.H1-7

(AP-56)

VII.H1. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Soil Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.H1-8

(A-24)

VII.H1.1-a 

VII.H1.3-a 

VII.H1.2-a

Piping, piping 

components, 

and piping 

elements

Steel Air – outdoor 

(External)

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.H1-9

(A-01)

VII.H1.1-b Piping, piping 

components, 

and piping 

elements

Steel (with or 

without 

coating or 

wrapping)

Soil Loss of material/ 

general, pitting, 

crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M28, “Buried Piping and 

Tanks Surveillance,” or

Chapter XI.M34, “Buried Piping and 

Tanks Inspection”

No 

Yes, detection 

of aging effects 

and operating 

experience are 

to be further 

evaluated
NUREG-1801, Rev. 1 VII H1-4 September 2005

VII AUXILIARY SYSTEMS 

H1 Diesel Fuel Oil System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.H1-10

(A-30)

VII.H1.4-a Piping, piping 

components, 

piping 

elements, and 

tanks

Steel Fuel oil Loss of material/ 

general, pitting, 

crevice, and 

microbiologically 

influenced 

corrosion, and 

fouling

Chapter XI.M30, “Fuel Oil Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of fuel oil 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging effects 

is to be 

evaluated

VII.H1-11

(A-95)

VII.H1.4-b Tanks Steel Air – outdoor 

(External)

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M29, “Aboveground Steel 

Tanks”

No
September 2005 VII H2-1 NUREG-1801, Rev. 1

H2. EMERGENCY DIESEL GENERATOR SYSTEM

Systems, Structures, and Components

This section discusses the emergency diesel generator system, which contains piping, valves, 

filters, mufflers, strainers, and tanks. Based on Regulatory Guide 1.26, “Quality Group 

Classifications and Standards for Water-, Steam-, and Radioactive-Waste-Containing 

Components of Nuclear Power Plants,” all components that comprise the emergency diesel 

generator system are governed by Group C Quality Standards. 

With respect to filters, these items are to be addressed consistent with the NRC position on 

consumables, provided in the NRC letter from Christopher I. Grimes to Douglas J. Walters of 

Nuclear Energy Institute (NEI), dated March 10, 2000. Specifically, components that function as 

system filters are typically replaced based on performance or condition monitoring that identifies 

whether these components are at the end of their qualified lives and may be excluded, on a 

plant-specific basis, from an aging management review under 10 CFR 54.21(a)(1)(ii). As part of 

the methodology description, the application should identify the standards that are relied on for 

replacement, for example, National Fire Protection Association (NFPA) standards for fire 

protection equipment.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VII.I. Common miscellaneous material/environment 

combinations where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the emergency diesel generator system include the diesel fuel 

oil system (VII.H1), the closed-cycle cooling water system (VII.C2) and the open-cycle cooling 

water system (VII.C1) for some plants.
NUREG-1801, Rev. 1 VII H2-2 September 2005

VII AUXILIARY SYSTEMS 

H2 Emergency Diesel Generator System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.H2-1

(AP-33)

VII.H2. Diesel engine 

exhaust

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Diesel exhaust Cracking/ stress 

corrosion cracking

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.H2-2

(A-27)

VII.H2.4-a Diesel engine 

exhaust

Piping, piping 

components, 

and piping 

elements

Stainless 

steel; steel

Diesel exhaust Loss of material/ 

general (steel only), 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.H2-3

(AP-41)

VII.H2. Heat 

exchanger 

components

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.H2-4

(AP-40)

VII.H2. Heat 

exchanger 

components

Steel Air – outdoor 

(External)

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.H2-5

(AP-39)

VII.H2. Heat 

exchanger 

components

Steel Lubricating oil Loss of material/ 

general, pitting, 

crevice, and 

microbiologically 

influenced 

corrosion, and 

fouling

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
September 2005 VII H2-3 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

H2 Emergency Diesel Generator System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.H2-6

(AP-61)

VII.H2. Heat 

exchanger 

tubes

Stainless 

steel

Raw water Reduction of heat 

transfer/ fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VII.H2-7

(AP-35)

VII.H2. Piping, piping 

components, 

and piping 

elements

Aluminum Fuel oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M30, “Fuel Oil Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of fuel oil 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VII.H2-8

(AP-12)

VII.H2. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.H2-9

(AP-44)

VII.H2. Piping, piping 

components, 

and piping 

elements

Copper alloy Fuel oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M30, “Fuel Oil Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of fuel oil 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VII.H2-10

(AP-47)

VII.H2. Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
NUREG-1801, Rev. 1 VII H2-4 September 2005

VII AUXILIARY SYSTEMS 

H2 Emergency Diesel Generator System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.H2-11

(AP-45)

VII.H2. Piping, piping 

components, 

and piping 

elements

Copper alloy Raw water Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VII.H2-12

(AP-43)

VII.H2. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.H2-13

(A-47)

VII.H2. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Raw water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.H2-14

(A-51)

VII.H2. Piping, piping 

components, 

and piping 

elements

Gray cast iron Raw water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VII.H2-15

(A-02)

VII.H2. Piping, piping 

components, 

and piping 

elements

Gray cast iron Soil Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials" 

No

VII.H2-16

(AP-54)

VII.H2. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Fuel oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M30, “Fuel Oil Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of fuel oil 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
September 2005 VII H2-5 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

H2 Emergency Diesel Generator System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.H2-17

(AP-59)

VII.H2. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Lubricating oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VII.H2-18

(AP-55)

VII.H2. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Raw water Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VII.H2-19

(AP-56)

VII.H2. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Soil Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VII.H2-20

(AP-30)

VII.H2. Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VII.H2-21

(A-23)

VII.H2.3-a 

VII.H2.2-a

Piping, piping 

components, 

and piping 

elements

Steel Moist air or 

condensation 

(Internal)

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M38, "Inspection of Internal 

Surfaces in Miscellaneous Piping and 

Ducting Components"

No
NUREG-1801, Rev. 1 VII H2-6 September 2005

VII AUXILIARY SYSTEMS 

H2 Emergency Diesel Generator System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.H2-22

(A-38)

VII.H2.1-b Piping, piping 

components, 

and piping 

elements

Steel (with or 

without 

lining/coating 

or with 

degraded 

lining/coating)

Raw water Loss of material/ 

general, pitting, 

crevice, and 

microbiologically 

influenced 

corrosion, fouling, 

and lining/coating 

degradation

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VII.H2-23

(A-25)

VII.H2.1-a Piping, piping 

components, 

piping 

elements, and 

tanks

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VII.H2-24

(A-30)

VII.H2.5-a Piping, piping 

components, 

piping 

elements, and 

tanks

Steel Fuel oil Loss of material/ 

general, pitting, 

crevice, and 

microbiologically 

influenced 

corrosion, and 

fouling

Chapter XI.M30, “Fuel Oil Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of fuel oil 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
September 2005 VII I-1 NUREG-1801, Rev. 1

I. EXTERNAL SURFACES OF COMPONENTS AND MISCELLANEOUS BOLTING

Systems, Structures, and Components

This section addresses the aging management programs for the external surfaces of all steel 

structures and components including closure boltings in the Auxiliary Systems in pressurized 

water reactors (PWRs) and boiling water reactors (BWRs). For the steel components in PWRs, 

this section addresses only boric acid corrosion of external surface as a result of dripping 

borated water that is leaking from an adjacent PWR component. Boric acid corrosion can also 

occur for steel components containing borated water due to leakage; such components and the 

related aging management program are covered in the appropriate major plant sections in VII.

System Interfaces

The structures and components covered in this section belong to the Auxiliary Systems in 

PWRs and BWRs. (For example, see System Interfaces in VII.A1 to VII.H2 for details.)
NUREG-1801, Rev. 1 VII I-2 September 2005

VII AUXILIARY SYSTEMS 

I External Surfaces of Components and Miscellaneous Bolting

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.I-1

(AP-28)

VII.I. Bolting Steel Air – outdoor 

(External)

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M18, “Bolting Integrity” No

VII.I-2

(A-102)

VII.I. Bolting Steel Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid Corrosion” No

VII.I-3

(A-04)

VII.I.2-b Closure bolting Highstrength 

steel

Air with steam or 

water leakage

Cracking/ cyclic 

loading, stress 

corrosion cracking

Chapter XI.M18, “Bolting Integrity” No

VII.I-4

(AP-27)

VII.I. Closure bolting Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M18, “Bolting Integrity” No

VII.I-5

(AP-26)

VII.I. Closure bolting Steel Air – indoor 

uncontrolled 

(External)

Loss of preload/ 

thermal effects, 

gasket creep, and 

self-loosening 

Chapter XI.M18, “Bolting Integrity” No

VII.I-6

(A-03)

VII.I.2-a Closure bolting Steel Air with steam or 

water leakage

Loss of material/ 

general corrosion

Chapter XI.M18, “Bolting Integrity” No

VII.I-7

(A-105)

VII.I. Ducting 

closure bolting

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.I-8

(A-77)

VII.I.1-b External 

surfaces

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.I-9

(A-78)

VII.I.1-b External 

surfaces

Steel Air – outdoor 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No
September 2005 VII I-3 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

I External Surfaces of Components and Miscellaneous Bolting

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.I-10

(A-79)

VII.I.1-a External 

surfaces

Steel Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid Corrosion” No

VII.I-11

(A-81)

VII.I.1-b External 

surfaces

Steel Condensation 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VII.I-12

(AP-66)

VII.I. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid Corrosion” No
NUREG-1801, Rev. 1 VII I-4 September 2005

This Page Intentionally Left Blank
September 2005 VII J-1 NUREG-1801, Rev. 1

J. COMMON MISCELLANEOUS MATERIAL/ENVIRONMENT COMBINAT IONS

Systems, Structures, and Components

This section addresses the aging management programs for miscellaneous 

material/environment combinations which may be found throughout structures and components

for auxiliary systems. For the material/environment combinations in this part, aging effects are 

not expected to degrade the ability of the structure or component to perform its intended function 

for the extended period of operation. Therefore, no resulting aging management programs for 

these structures and components are required.

System Interfaces

The structures and components covered in this section belong to the auxiliary systems in 

pressurized water reactors (PWRs) and boiling water reactors (BWRs). (For example, see 

System Interfaces in VII.A to VII.I for details) 
NUREG-1801, Rev. 1 VII J-2 September 2005

VII AUXILIARY SYSTEMS 

J Common Miscellaneous Material/Environment Combinations

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.J-1

(AP-36)

VII.J. Piping, piping 

components, 

and piping 

elements

Aluminum Air – indoor 

controlled 

(External)

None None No

VII.J-2

(AP-37)

VII.J. Piping, piping 

components, 

and piping 

elements

Aluminum Gas None None No

VII.J-3

(AP-8)

VII.J. Piping, piping 

components, 

and piping 

elements

Copper alloy Dried Air None None No

VII.J-4

(AP-9)

VII.J. Piping, piping 

components, 

and piping 

elements

Copper alloy Gas None None No

VII.J-5

(AP-11)

VII.J. Piping, piping 

components, 

and piping 

elements

Copper alloy 

<15% Zn

Air with borated 

water leakage

None None No

VII.J-6

(AP-13)

VII.J. Piping, piping 

components, 

and piping 

elements

Galvanized 

steel

Air – indoor 

uncontrolled

None None No

VII.J-7

(AP-48)

VII.J. Piping 

elements

Glass Air None None No
September 2005 VII J-3 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

J Common Miscellaneous Material/Environment Combinations

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.J-8

(AP-14)

VII.J. Piping 

elements

Glass Air – indoor 

uncontrolled 

(External)

None None No

VII.J-9

(AP-49)

VII.J. Piping 

elements

Glass Fuel oil None None No

VII.J-10

(AP-15)

VII.J. Piping 

elements

Glass Lubricating oil None None No

VII.J-11

(AP-50)

VII.J. Piping 

elements

Glass Raw water None None No

VII.J-12

(AP-52)

VII.J. Piping 

elements

Glass Treated borated 

water

None None No

VII.J-13

(AP-51)

VII.J. Piping 

elements

Glass Treated water None None No

VII.J-14

(AP-16)

VII.J. Piping, piping 

components, 

and piping 

elements

Nickel alloy Air – indoor 

uncontrolled 

(External)

None None No
NUREG-1801, Rev. 1 VII J-4 September 2005

VII AUXILIARY SYSTEMS 

J Common Miscellaneous Material/Environment Combinations

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.J-15

(AP-17)

VII.J. Piping, piping 

components, 

and piping 

elements

Stainless

steel

Air – indoor 

uncontrolled 

(External)

None None No

VII.J-16

(AP-18)

VII.J. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Air with borated 

water leakage

None None No

VII.J-17

(AP-19)

VII.J. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Concrete None None No

VII.J-18

(AP-20)

VII.J. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Dried Air None None No

VII.J-19

(AP-22)

VII.J. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Gas None None No

VII.J-20

(AP-2)

VII.J. Piping, piping 

components, 

and piping 

elements

Steel Air – indoor 

controlled 

(External)

None None No

VII.J-21

(AP-3)

VII.J. Piping, piping 

components, 

and piping 

elements

Steel Concrete None None No
September 2005 VII J-5 NUREG-1801, Rev. 1

VII AUXILIARY SYSTEMS 

J Common Miscellaneous Material/Environment Combinations

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VII.J-22

(AP-4)

VII.J. Piping, piping 

components, 

and piping 

elements

Steel Dried Air None None No

VII.J-23

(AP-6)

VII.J. Piping, piping 

components, 

and piping 

elements

Steel Gas None None No
NUREG-1801, Rev. 1 VII J-6 September 2005

This Page Intentionally Left Blank
 

September 2005 VIII-i NUREG-1801, Rev. 1

CHAPTER VIII

STEAM AND POWER CONVERSION SYSTEM
NUREG-1801, Rev. 1 VIII-ii September 2005

This Page Intentionally Left Blank
 

September 2005 VIII-iii NUREG-1801, Rev. 1

MAJOR PLANT SECTIONS

A. Steam Turbine System

B1. Main Steam System (PWR)

B2. Main Steam System (BWR)

C. Extraction Steam System

D1. Feedwater System (PWR)

D2. Feedwater System (BWR)

E. Condensate System

F. Steam Generator Blowdown System (PWR)

G. Auxiliary Feedwater System (PWR)

H. External Surfaces of Components and Miscellaneous Bolting

I. Common Miscellaneous Material/Environment Combinations
NUREG-1801, Rev. 1 VIII-iv September 2005

This Page Intentionally Left Blank
 

September 2005 VIII A-1 NUREG-1801, Rev. 1

A. STEAM TURBINE SYSTEM

Systems, Structures, and Components

This section addresses the piping and fittings in the steam turbine system for both pressurized 

water reactors (PWRs) and boiling water reactors (BWRs) and consists of the lines from the 

high-pressure (HP) turbine to the moisture separator/reheater (MSR), and the lines from the 

MSR to the low-pressure (LP) turbine. Based on Regulatory Guide 1.26, “Quality Group 

Classifications and Standards for Water-, Steam-, and Radioactive-Waste-Containing 

Components of Nuclear Power Plants,” all components that comprise the steam turbine system 

are governed by Group D Quality Standards. 

The steam turbine performs its intended functions with moving parts. They are subject to 

replacement based on qualified life or specified time period. Pursuant to 10 CFR 54.2(a)(1), 

therefore, they are not subject to an aging management review.

Aging management programs for the degradation of external surfaces of components and 

miscellaneous bolting are included in VIII.H. Common miscellaneous material/environment

combinations, where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation, are included in 

VIII.I. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the steam turbine system include the PWR and BWR main 

steam system (VIII.B1 and VIII.B2), the extraction steam system (VIII.C), and the condensate 

system (VIII.E).
NUREG-1801, Rev. 1 VIII A-2 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

A Steam Turbine System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.A-1

(S-23)

VIII.A. Heat 

exchanger 

components

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, 

crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VIII.A-2

(SP-64)

VIII.A. Heat 

exchanger 

tubes

Steel Closed cycle 

cooling water

Reduction of heat 

transfer/ fouling

Chapter XI.M21, “Closed-Cycle Cooling 

Water System”

No

VIII.A-3

(SP-32)

VIII.A. Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.A-4

(SP-31)

VIII.A. Piping, piping 

components, 

and piping 

elements

Copper alloy Raw water Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced 

corrosion

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VIII.A-5

(SP-61)

VIII.A. Piping, piping 

components, 

and piping 

elements

Copper alloy Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, "Water Chemistry"

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.A-6

(SP-30)

VIII.A. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Raw water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No
September 2005 VIII A-3 NUREG-1801, Rev 1 

VIII STEAM AND POWER CONVERSION SYSTEM

A Steam Turbine System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.A-7

(SP-28)

VIII.A. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Raw water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VIII.A-8

(SP-27)

VIII.A. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching of 

Materials”

No

VIII.A-9

(SP-38)

VIII.A. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Lubricating oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.A-10

(SP-44)

VIII.A. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Steam Cracking/stress 

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No

VIII.A-11

(SP-45)

VIII.A. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Steam Cracking/stress 

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
NUREG-1801, Rev. 1 VIII A-4 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

A Steam Turbine System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.A-12

(SP-43)

VIII.A. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Steam Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No

VIII.A-13

(SP-46)

VIII.A. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Steam Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

No

VIII.A-14

(SP-25)

VIII.A. Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.A-15

(S-04)

VIII.A.2-b 

VIII.A.1-b

Piping, piping 

components, 

and piping 

elements

Steel Steam Loss of material/

general, pitting, and 

crevice corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
September 2005 VIII A-5 NUREG-1801, Rev 1 

VIII STEAM AND POWER CONVERSION SYSTEM

A Steam Turbine System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.A-16

(S-06)

VIII.A.2-b 

VIII.A.1-b

Piping, piping 

components, 

and piping 

elements

Steel Steam Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.A-17

(S-15)

VIII.A.1-a 

VIII.A.2-a

Piping, piping 

components, 

and piping 

elements

Steel Steam Wall thinning/ flowaccelerated 

corrosion

Chapter XI.M17, “Flow-Accelerated 

Corrosion”

No
NUREG-1801, Rev. 1 VIII A-6 September 2005

This Page Intentionally Left Blank
September 2005 VIII B1-1 NUREG-1801, Rev. 1

B1. MAIN STEAM SYSTEM (PWR)

Systems, Structures, and Components

This section addresses the main steam system for pressurized water reactors (PWRs). The 

section includes the main steam lines from the steam generator to the steam turbine, and the 

turbine bypass lines from the main steam lines to the condenser. Also included are the lines to 

the main feedwater (FW) and auxiliary feedwater (AFW) pump turbines, steam drains, and 

valves, including the containment isolation valves on the main steam lines, and the lines to the 

AFW pump turbines. 

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” the portion 

of the main steam system extending from the steam generator up to the second containment 

isolation valve is governed by Group B or C Quality Standards, and all other components that 

comprise the main steam system located downstream of these isolation valves are governed by 

Group D Quality Standards. 

The internals of the valves perform their intended functions with moving parts or with a change 

in configuration. They are subject to replacement based on qualified life or specified time period. 

Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of the external surfaces of components and 

miscellaneous bolting are included in VIII.H. Common miscellaneous material/environment 

combinations, where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation, are included in 

VIII.I. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems and structures that interface with the main steam system include PWR concrete or 

steel containment structures (II.A1 and II.A2), common components (II.A3), the steam generator 

(IV.D1 and IV.D2), the steam turbine system (VIII.A), the feedwater system (VIII.D1), the 

condensate system (VIII.E), and the auxiliary feedwater system (VIII.G). 
NUREG-1801, Rev. 1 VIII B1-2 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

B1 Main Steam System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.B1-1

(SP-18)

VIII.B1. Piping, piping 

components, 

and piping 

elements

Nickelbased alloysSteam Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No

VIII.B1-2

(SP-44)

VIII.B1. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Steam Cracking/stress

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No

VIII.B1-3

(SP-43)

VIII.B1. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Steam Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No

VIII.B1-4

(SP-16)

VIII.B1. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.B1-5

(SP-17)

VIII.B1. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking/stress

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.B1-6

(SP-59)

VIII.B1. Piping, piping 

components, 

and piping 

elements

Steel Air – outdoor 

(Internal)

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M38, "Inspection of Internal 

Surfaces in Miscellaneous Piping and 

Ducting Components"

No
September 200

5 VIII B1-3 NUREG-1801, Rev. 1

VIII STEAM AND POWER CONVERSION SYSTEM

B1 Main Steam System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.B1-7

(SP-60)

VIII.B1. Piping, piping 

components, 

and piping 

elements

Steel Condensation 

(Internal)

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M38, "Inspection of Internal 

Surfaces in Miscellaneous Piping and 

Ducting Components"

No

VIII.B1-8

(S-07)

VIII.B1.1-a 

VIII.B1.2-a

Piping, piping 

components, 

and piping 

elements

Steel Steam Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

No

VIII.B1-9

(S-15)

VIII.B1.1-c 

VIII.B1.2-b

Piping, piping 

components, 

and piping 

elements

Steel Steam Wall thinning/ 

flow-accelerated 

corrosion

Chapter XI.M17, “Flow-Accelerated 

Corrosion”

No

VIII.B1-10

(S-08)

VIII.B1.1-b Piping, piping 

components, 

and piping 

elements

Steel Steam or treated 

water

Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA

VIII.B1-11

(S-10)

VIII.B1. Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
NUREG-1801, Rev. 1 VIII B1-4 September 2005

This Page Intentionally Left Blank
September 2005 VIII B2-1 NUREG-1801, Rev. 1

B2. MAIN STEAM SYSTEM (BWR)

Systems, Structures, and Components

This section addresses the main steam system for boiling water reactors (BWRs). The section 

includes the main steam lines from the outermost containment isolation valve to the steam 

turbines, and the turbine bypass lines from the main steam lines to the condenser. Also 

included are steam drains, lines to the main feedwater (FW), high-pressure coolant injection 

(HPCI), and reactor core isolation cooling (RCIC) turbines. 

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” portions of 

the main steam system extending from the outermost containment isolation valve up to and 

including the turbine stop and bypass valves, as well as connected piping up to and including 

the first valve that is either normally closed or capable of automatic closure during all modes of 

normal reactor operation, are governed by Group B Quality Standards. The remaining portions 

of the main steam system consist of components governed by Group D Quality Standards. For 

BWRs containing a shutoff valve in addition to the two containment isolation valves in the main 

steam line, Group B Quality Standards apply only to those portions of the system extending 

from the outermost containment isolation valves up to and including the shutoff valve. The 

portion of the main steam system extending from the reactor pressure vessel up to the second 

isolation valve and including the containment isolation valves is governed by Group A Quality 

Standards, and is covered in IV.C1. 

The internal of the valves perform their intended functions with moving parts or with a change in 

configuration. They are subject to replacement based on qualified life or specified time period. 

Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of the external surfaces of components and 

miscellaneous bolting are included in VIII.H. Common miscellaneous material/environment

combinations, where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation, are included in 

VIII.I. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the main steam system include the BWR Mark 1, Mark 2, or 

Mark 3 containment structures (II.B1, II.B2, and II.B3, respectively) and common components 

(II.B4), the reactor coolant pressure boundary (IV.C1), the steam turbine system (VIII.A), the 

feedwater system (VIII.D2), and the condensate system (VIII.E). 
NUREG-1801, Rev. 1 VIII B2-2 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

B2 Main Steam System (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.B2-1

(SP-45)

VIII.B2. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Steam Cracking/stress

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.B2-2

(SP-46)

VIII.B2. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Steam Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

No

VIII.B2-3

(S-05)

VIII.B2.1-a 

VIII.B2.2-b

Piping, piping 

components, 

and piping 

elements

Steel Steam Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

No

VIII.B2-4

(S-15)

VIII.B2.2-a 

VIII.B2.1-b

Piping, piping 

components, 

and piping 

elements

Steel Steam Wall thinning/ 

flow-accelerated 

corrosion

Chapter XI.M17, “Flow-Accelerated 

Corrosion”

No

VIII.B2-5

(S-08)

VIII.B2.1-c Piping, piping 

components, 

and piping 

elements

Steel Steam or treated 

water

Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period of 

extended operation. See the Standard 

Review Plan, Section 4.3 “Metal 

Fatigue,” for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c)(1).

Yes,

TLAA
September 2005 VIII B2-3 NUREG-1801, Rev. 1

VIII STEAM AND POWER CONVERSION SYSTEM

B2 Main Steam System (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.B2-6

(S-09)

VIII.B2. Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
NUREG-1801, Rev. 1 VIII B2-4 September 2005

This Page Intentionally Left Blank
September 2005 VIII C-1 NUREG-1801, Rev. 1

C. EXTRACTION STEAM SYSTEM

Systems, Structures, and Components

This section addresses the extraction steam lines for both pressurized water reactors (PWRs) 

and boiling water reactors (BWRs), which extend from the steam turbine to the feedwater 

heaters, including the drain lines. Based on Regulatory Guide 1.26, “Quality Group 

Classifications and Standards for Water-, Steam-, and Radioactive-Waste-Containing 

Components of Nuclear Power Plants,” all components that comprise the extraction steam 

system are governed by Group D Quality Standards. 

The internals of the valves perform their intended functions with moving parts or with a change 

in configuration. They are subject to replacement based on qualified life or specified time period. 

Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of the external surfaces of components and 

miscellaneous bolting are included in VIII.H. Common miscellaneous material/environment

combinations, where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation, are included in 

VIII.I. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the extraction steam system include the steam turbine system 

(VIII.A), the PWR and BWR feedwater system (VIII.D1 and VIII.D2), and the condensate system 

(VIII.E). 
NUREG-1801, Rev. 1 VIII C-2 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

C Extraction Steam System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.C-1

(SP-16)

VIII.C. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.C-2

(SP-17)

VIII.C. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking/stress

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection

of aging 

effects is to be 

evaluated

VIII.C-3

(S-04)

VIII.C.1-b 

VIII.C.2-b

Piping, piping 

components, 

and piping 

elements

Steel Steam Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.C-4

(S-06)

VIII.C.2-b 

VIII.C.1-b

Piping, piping 

components, 

and piping 

elements

Steel Steam Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
September 2005 VIII C-3 NURE

G-1801, Rev. 1

VIII STEAM AND POWER CONVERSION SYSTEM

C Extraction Steam System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.C-5

(S-15)

VIII.C.1-a 

VIII.C.2-a

Piping, piping 

components, 

and piping 

elements

Steel Steam Wall thinning/ 

flow-accelerated 

corrosion

Chapter XI.M17, “Flow-Accelerated 

Corrosion”

No

VIII.C-6

(S-09)

VIII.C. Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.C-7

(S-10)

VIII.C. Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
NUREG-1801, Rev. 1 VIII C-4 September 2005

This Page Intentionally Left Blank
September 2005 VIII D1-1 NUREG-1801, Rev. 1

D1. FEEDWATER SYSTEM (PWR)

Systems, Structures, and Components

This section addresses the main feedwater system for pressurized water reactors (PWRs), 

which extends from the condensate system to the steam generator. It consists of the main 

feedwater lines, feedwater pumps, and valves, including the containment isolation valves. 

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” the portion 

of the feedwater system extending from the secondary side of the steam generator up to the 

second containment isolation valve is governed by Group B or C Quality Standards. All other 

components in the feedwater system located downstream from these isolation valves are 

governed by Group D Quality Standards. 

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are subject to replacement based on qualified life or specified time period. 

Pursuant to 10 CFR 54.21(a)(1), therefore, they not subject to an aging management review.

Aging management programs for the degradation of the external surfaces of components and 

miscellaneous bolting are included in VIII.H. Common miscellaneous material/environment

combinations, where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation, are included in 

VIII.I. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems and structures that interface with the feedwater system include PWR concrete or 

steel containment structures (II.A1 and II.A2) and common components (II.A3), the steam 

generators (IV.D1 and IV.D2), the main steam system (VIII.B1), the extraction steam system 

(VIII.C), the condensate system (VIII.E), and the auxiliary feedwater system (VIII.G).
NUREG-1801, Rev. 1 VIII D1-2 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

D1 Feedwater Systems (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.D1-1

(SP-24)

VIII.D1. Piping, piping 

components, 

and piping 

elements

Aluminum Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, "Water Chemistry"

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable ve rification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.D1-2

(SP-32)

VIII.D1. Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M39, "Lubricating Oil

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.D1-3

(SP-38)

VIII.D1. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Lubricating oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.D1-4

(SP-16)

VIII.D1. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
September 2005 VIII D1-3 NUREG-1801, Rev. 1

VIII STEAM AND POWER CONVERSION SYSTEM

D1 Feedwater Systems (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.D1-5

(SP-17)

VIII.D1. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking/stress

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging

effects is to be 

evaluated

VIII.D1-6

(SP-25)

VIII.D1. Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.D1-7

(S-11)

VIII.D1.1-b Piping, piping 

components, 

and piping 

elements

Steel Treated water Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period 

of extended operation. See the 

Standard Review Plan, Section 4.3 

“Metal Fatigue,” for acceptable 

methods for meeting the requirements 

of 10 CFR 54.21(c)(1).

Yes,

TLAA

VIII.D1-8

(S-10)

VIII.D1.1-c 

VIII.D1.3-a 

VIII.D1.2-b

Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
NUREG-1801, Rev. 1 VIII D1-4 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

D1 Feedwater Systems (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.D1-9

(S-16)

VIII.D1.2-a 

VIII.D1.1-a 

VIII.D1.3-b

Piping, piping 

components, 

and piping 

elements

Steel Treated water Wall thinning/ flowaccelerated 

corrosion

Chapter XI.M17, “Flow-Accelerated 

Corrosion”

No
September 2005 VIII D2-1 NUREG-1801, Rev. 1

D2. FEEDWATER SYSTEM (BWR)

Systems, Structures, and Components

This section addresses the main feedwater system for boiling water reactors (BWRs), which 

extends from the condensate and condensate booster system to the outermost feedwater 

isolation valve on the feedwater lines to the reactor vessel. It consists of the main feedwater 

lines, feedwater pumps, and valves. 

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” the portions 

of the feedwater system extending from the outermost containment isolation valves up to and 

including the shutoff valve, or the first valve that is either normally closed or capable of closure 

during all modes of normal reactor operation, are governed by Group B Quality Standards. The 

remaining portions of the feedwater system consist of components governed by Group D 

Quality Standards. The portion of the feedwater system extending from the reactor vessel up to 

the second containment isolation valve, including the isolation valves, is governed by Group A 

Quality Standards and is covered in IV.C1. 

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are subject to replacement based on qualified life or specified time period. 

Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of the external surfaces of components and 

miscellaneous bolting are included in VIII.H. Common miscellaneous material/environment

combinations, where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation, are included in 

VIII.I. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the feedwater system include the BWR Mark 1, Mark 2, or Mark

3 containment structures (II.B1, II.B2, and II.B3, respectively) and common components 

(II.B4), the reactor coolant pressure boundary (IV.C1), the main steam system (VIII.B2), the 

extraction steam system (VIII.C), and the condensate system (VIII.E).
NUREG-1801, Rev. 1 VIII D2-2 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

D2 Feedwater Systems (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.D2-1

(SP-24)

VIII.D2. Piping, piping 

components, 

and piping 

elements

Aluminum Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, "Water Chemistry"

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.D2-2

(SP-32)

VIII.D2. Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.D2-3

(SP-38)

VIII.D2. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Lubricating oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.D2-4

(SP-16)

VIII.D2. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
September 2005 VIII D2-3 NUREG-1801, Rev. 1

VIII STEAM AND POWER CONVERSION SYSTEM

D2 Feedwater Systems (BWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.D2-5

(SP-25)

VIII.D2. Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.D2-6

(S-11)

VIII.D2.1-c Piping, piping 

components, 

and piping 

elements

Steel Treated water Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging analysis 

(TLAA) to be evaluated for the period 

of extended operation. See the 

Standard Review Plan, Section 4.3 

“Metal Fatigue,” for acceptable 

methods for meeting the requirements 

of 10 CFR 54.21(c)(1).

Yes,

TLAA

VIII.D2-7

(S-09)

VIII.D2.3-b 

VIII.D2.2-b 

VIII.D2.1-b

Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M2, “Water Chemistry,” for 

BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.D2-8

(S-16)

VIII.D2.2-a 

VIII.D2.1-a 

VIII.D2.3-a

Piping, piping 

components, 

and piping 

elements

Steel Treated water Wall thinning/ flowaccelerated 

corrosion

Chapter XI.M17, “Flow-Accelerated 

Corrosion”

No
NUREG-1801, Rev. 1 VIII D2-4 September 2005

This Page Intentionally Left Blank
September 2005 VIII E-1 NUREG-1801, Rev. 1

E. CONDENSATE SYSTEM

Systems, Structures, and Components

This section addresses the condensate system for both pressurized water reactors (PWRs) and 

boiling water reactors (BWRs), which extend from the condenser hotwells to the suction of 

feedwater pumps, including condensate and condensate booster pumps, condensate coolers, 

condensate cleanup system, and condensate storage tanks. Based on Regulatory Guide 1.26, 

“Quality Group Classifications and Standards for Water-, Steam-, and Radioactive-WasteContaining Components of Nuclear Power Plants,” all components that comprise the 

condensate system are governed by Group D Quality Standards. 

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are subject to replacement based on qualified life or specified time period. 

Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of the external surfaces of components and 

miscellaneous bolting are included in VIII.H. Common miscellaneous material/environment

combinations, where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation, are included in 

VIII.I. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the condensate system include the steam turbine system 

(VIII.A), the PWR and BWR main steam system (VIII.B1 and VIII.B2), the PWR and BWR 

feedwater system (VIII.D1 and VIII.D2), the auxiliary feedwater system (VIII.G, PWR only), the 

PWR and BWR reactor water cleanup system (VII.E3), the open or closed cycle cooling water 

systems (VII.C1 or VII.C2), and the condensate storage facility.
NUREG-1801, Rev. 1 VIII E-2 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

E Condensate System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

VIII.E-1

(S-01)

VIII.E.5-d Buried piping, 

piping 

components, 

piping 

elements, and 

tanks

Steel (with 

or without 

coating or 

wrapping)

Soil Loss of material/ 

general, pitting, 

crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M28, “Buried Piping and 

Tanks Surveillance,” or

Chapter XI.M34, “Buried Piping and 

Tanks Inspection”

No 

Yes, detection 

of aging 

effects and 

operating 

experience 

are to be 

further 

evaluated

VIII.E-2

(S-25)

VIII.E.4-e Heat 

exchanger 

components

Stainless 

steel

Closed cycle 

cooling water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

VIII.E-3

(S-26)

VIII.E.4-b Heat 

exchanger 

components

Stainless 

steel

Raw water Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion, 

and fouling

Chapter XI.M20, “Open-Cycle 

Cooling Water System”

No

VIII.E-4

(S-21)

VIII.E.4-d 

VIII.E.4-a

Heat 

exchanger 

components

Stainless 

steel

Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” 

for BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for 

an acceptable verification program.

Yes, detection 

of aging 

effects is to 

be evaluated

VIII.E-5

(S-23)

VIII.E.4-e Heat 

exchanger 

components

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, 

crevice, and galvanic 

corrosion

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No
September 2005 VIII E-3 NUREG-1801, Rev. 1

VIII STEAM AND POWER CONVERSION SYSTEM

E Condensate System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

VIII.E-6

(S-24)

VIII.E.4-b Heat 

exchanger 

components

Steel Raw water Loss of material/ 

general, pitting, 

crevice, galvanic, 

and microbiologically 

influenced corrosion, 

and fouling

Chapter XI.M20, “Open-Cycle 

Cooling Water System”

No

VIII.E-7

(S-18)

VIII.E.4-d 

VIII.E.4-a

Heat 

exchanger 

components

Steel Treated water Loss of material/ 

general, pitting, 

crevice, and galvanic 

corrosion

Chapter XI.M2, “Water Chemistry,” 

for BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for 

an acceptable verification program.

Yes, detection 

of aging 

effects is to 

be evaluated

VIII.E-8

(SP-57)

VIII.E. Heat 

exchanger 

tubes

Copper alloy Closed cycle 

cooling water

Reduction of heat 

transfer/fouling

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

VIII.E-9

(SP-56)

VIII.E. Heat 

exchanger 

tubes

Copper alloy Raw water Reduction of heat 

transfer/fouling

Chapter XI.M20, “Open-Cycle 

Cooling Water System”

No

VIII.E-10

(SP-58)

VIII.E. Heat 

exchanger 

tubes

Copper alloy Treated water Reduction of heat 

transfer/fouling

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for 

an acceptable verification program.

Yes, detection 

of aging 

effects is to 

be evaluated

VIII.E-11

(SP-41)

VIII.E. Heat 

exchanger 

tubes

Stainless 

steel

Closed cycle 

cooling water

Reduction of heat 

transfer/fouling

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No
NUREG-1801, Rev. 1 VIII E-4 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

E Condensate System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

VIII.E-12

(S-28)

VIII.E.4-c Heat 

exchanger 

tubes

Stainless 

steel

Raw water Reduction of heat 

transfer/fouling

Chapter XI.M20, “Open-Cycle 

Cooling Water System”

No

VIII.E-13

(SP-40)

VIII.E. Heat 

exchanger 

tubes

Stainless 

steel

Treated water Reduction of heat 

transfer/fouling

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for 

an acceptable verification program.

Yes, detection 

of aging 

effects is to 

be evaluated

VIII.E-14

(SP-64)

VIII.E.4-e Heat 

exchanger 

tubes

Steel Closed cycle 

cooling water

Reduction of heat 

transfer/fouling

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

VIII.E-15

(SP-24)

VIII.E. Piping, piping 

components, 

and piping 

elements

Aluminum Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, "Water Chemistry"

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for 

an acceptable verification program.

Yes, detection 

of aging 

effects is to 

be evaluated

VIII.E-16

(SP-8)

VIII.E. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No
September 2005 VIII E-5 NUREG-1801, Rev. 1

VIII STEAM AND POWER CONVERSION SYSTEM

E Condensate System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

VIII.E-17

(SP-32)

VIII.E. Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to 

be evaluated

VIII.E-18

(SP-31)

VIII.E. Piping, piping 

components, 

and piping 

elements

Copper alloy Raw water Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M20, “Open-Cycle 

Cooling Water System”

No

VIII.E-19

(SP-29)

VIII.E. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching 

of Materials”

No

VIII.E-20

(SP-30)

VIII.E. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Raw water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching 

of Materials”

No

VIII.E-21

(SP-55)

VIII.E. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching 

of Materials”

No

VIII.E-22

(SP-26)

VIII.E. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Soil Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching 

of Materials" 

No
NUREG-1801, Rev. 1 VIII E-6 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

E Condensate System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

VIII.E-23

(SP-27)

VIII.E. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching 

of Materials”

No

VIII.E-24

(SP-39)

VIII.E. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed cycle 

cooling water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

VIII.E-25

(SP-54)

VIII.E. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed cycle 

cooling water 

>60°C (>140°F)

Cracking/stress

corrosion cracking

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

VIII.E-26

(SP-38)

VIII.E. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Lubricating oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to 

be evaluated

VIII.E-27

(SP-36)

VIII.E. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Raw water Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M20, “Open-Cycle 

Cooling Water System”

No

VIII.E-28

(SP-37)

VIII.E. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Soil Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific
September 2005 VIII E-7 NUREG-1801, Rev. 1

VIII STEAM AND POWER CONVERSION SYSTEM

E Condensate System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

VIII.E-29

(SP-16)

VIII.E. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for 

an acceptable verification program.

Yes, detection 

of aging 

effects is to 

be evaluated

VIII.E-30

(SP-17)

VIII.E. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking/stress

corrosion cracking

Chapter XI.M2, “Water Chemistry,” 

for PWR secondary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for 

an acceptable verification program.

Yes, detection 

of aging 

effects is to 

be evaluated

VIII.E-31

(SP-19)

VIII.E. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking/stress

corrosion cracking

Chapter XI.M2, “Water Chemistry,” 

for BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for 

an acceptable verification program.

Yes, detection 

of aging 

effects is to 

be evaluated

VIII.E-32

(SP-25)

VIII.E. Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to 

be evaluated
NUREG-1801, Rev. 1 VIII E-8 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

E Condensate System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

VIII.E-33

(S-09)

VIII.E.5-a 

VIII.E.1-b 

VIII.E.3-a 

VIII.E.6-a 

VIII.E.2-b

Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M2, “Water Chemistry,” 

for BWR water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for 

an acceptable verification program.

Yes, detection 

of aging 

effects is to 

be evaluated

VIII.E-34

(S-10)

VIII.E.2-b 

VIII.E.1-b 

VIII.E.5-a 

VIII.E.6-a 

VIII.E.3-a

Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M2, “Water Chemistry,” 

for PWR secondary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for 

an acceptable verification program.

Yes, detection 

of aging 

effects is to 

be evaluated

VIII.E-35

(S-16)

VIII.E.2-a 

VIII.E.1-a

Piping, piping 

components, 

and piping 

elements

Steel Treated water Wall thinning/ flowaccelerated corrosionChapter XI.M17, “Flow-Accelerated 

Corrosion”

No

VIII.E-36

(S-22)

VIII.E.4-d 

VIII.E.4-a

PWR heat 

exchanger 

components

Stainless 

steel

Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” 

for PWR primary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for 

an acceptable verification program.

Yes, detection 

of aging 

effects is to 

be evaluated
September 2005 VIII E-9 NUREG-1801, Rev. 1

VIII STEAM AND POWER CONVERSION SYSTEM

E Condensate System

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism

Aging Management Program 

(AMP)

Further 

Evaluation

VIII.E-37

(S-19)

VIII.E.4-d 

VIII.E.4-a

PWR heat 

exchanger 

components

Steel Treated water Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M2, “Water Chemistry,” 

for PWR secondary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for 

an acceptable verification program.

Yes, detection 

of aging 

effects is to 

be evaluated

VIII.E-38

(SP-42)

VIII.E. Tanks Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking/stress

corrosion cracking

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for 

an acceptable verification program.

Yes, detection 

of aging 

effects is to 

be evaluated

VIII.E-39

(S-31)

VIII.E.5-c Tanks Steel Air – outdoor 

(External)

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M29, “Aboveground Steel 

Tanks”

No

VIII.E-40

(S-13)

VIII.E.5-b 

VIII.E.5-a

Tanks Steel, 

Stainless 

steel

Treated water Loss of material/ 

general (steel only), 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for 

an acceptable verification program.

Yes, detection 

of aging 

effects is to 

be evaluated
NUREG-1801, Rev. 1 VIII E-10 September 2005

This Page Intentionally Left Blank
September 2005 VIII F-1 NUREG-1801, Rev. 1

F. STEAM GENERAT OR BLOWDOWN SYSTEM (PWR)

Systems, Structures, and Components

This section addresses the steam generator blowdown system for pressurized water reactors 

(PWRs), which extends from the steam generator through the blowdown condenser and 

includes the containment isolation valves and small bore piping less than nominal pipe size 

(NPS) 2 in. (including instrumentation lines). 

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” the portion 

of the blowdown system extending from the steam generator up to the isolation valve outside 

the containment and including the isolation valves is governed by Group B or C Quality 

Standards. The remaining portions of the steam generator blowdown system consist of 

components governed by Group D Quality Standards. 

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are subject to replacement based on qualified life or specified time period. 

Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of the external surfaces of components and 

miscellaneous bolting are included in VIII.H. Common miscellaneous material/environment

combinations, where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation, are included in 

VIII.I. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the blowdown system include the steam generator (IV.D1 and 

IV.D2) and the open- or closed-cycle cooling water systems (VII.C1 or VII.C2).
NUREG-1801, Rev. 1 VIII F-2 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

F Steam Generator Blowdown System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.F-1

(S-25)

VIII.F.4-e Heat 

exchanger 

components

Stainless 

steel

Closed cycle 

cooling water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

VIII.F-2

(S-26)

VIII.F.4-b Heat 

exchanger 

components

Stainless 

steel

Raw water Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion, 

and fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VIII.F-3

(S-39)

VIII.F.4-a Heat 

exchanger 

components

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking/stress

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

The AMP is to be augmented by

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.F-4

(S-23)

VIII.F.4-e Heat 

exchanger 

components

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting, 

crevice, and galvanic 

corrosion

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

VIII.F-5

(S-24)

VIII.F.4-b Heat 

exchanger 

components

Steel Raw water Loss of material/ 

general, pitting, 

crevice, galvanic, 

and microbiologically 

influenced corrosion, 

and fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VIII.F-6

(SP-56)

VIII.F. Heat 

exchanger 

tubes

Copper alloy Raw water Reduction of heat 

transfer/fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No
September 2005 VIII F-3 NUREG-1801, Rev. 1

VIII STEAM AND POWER CONVERSION SYSTEM

F Steam Generator Blowdown System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.F-7

(SP-58)

VIII.F. Heat 

exchanger 

tubes

Copper alloy Treated water Reduction of heat 

transfer/fouling

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.F-8

(SP-41)

VIII.F. Heat 

exchanger 

tubes

Stainless 

steel

Closed cycle 

cooling water

Reduction of heat 

transfer/fouling

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

VIII.F-9

(S-28)

VIII.F.4-c Heat 

exchanger 

tubes

Stainless 

steel

Raw water Reduction of heat 

transfer/fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VIII.F-10

(SP-40)

VIII.F. Heat 

exchanger 

tubes

Stainless 

steel

Treated water Reduction of heat 

transfer/fouling

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.F-11

(SP-64)

VIII.F.4-e Heat 

exchanger 

tubes

Steel Closed cycle 

cooling water

Reduction of heat 

transfer/fouling

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

VIII.F-12

(SP-24)

VIII.F. Piping, piping 

components, 

and piping 

elements

Aluminum Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, "Water Chemistry"

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
NUREG-1801, Rev. 1 VIII F-4 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

F Steam Generator Blowdown System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.F-13

(SP-8)

VIII.F. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

VIII.F-14

(SP-31)

VIII.F. Piping, piping 

components, 

and piping 

elements

Copper alloy Raw water Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VIII.F-15

(SP-61)

VIII.F. Piping, piping 

components, 

and piping 

elements

Copper alloy Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, "Water Chemistry"

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.F-16

(SP-29)

VIII.F. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching 

of Materials”

No

VIII.F-17

(SP-30)

VIII.F. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Raw water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching 

of Materials”

No

VIII.F-18

(SP-55)

VIII.F. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching 

of Materials”

No

VIII.F-19

(SP-27)

VIII.F. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching 

of Materials”

No
September 2005 VIII F-5 NUREG-1801, Rev. 1

VIII STEAM AND POWER CONVERSION SYSTEM

F Steam Generator Blowdown System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.F-20

(SP-39)

VIII.F. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed cycle 

cooling water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

VIII.F-21

(SP-54)

VIII.F. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed cycle 

cooling water 

>60°C (>140°F)

Cracking/stress

corrosion cracking

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

VIII.F-22

(SP-36)

VIII.F. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Raw water Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VIII.F-23

(SP-16)

VIII.F. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.F-24

(SP-17)

VIII.F. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking/stress

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
NUREG-1801, Rev. 1 VIII F-6 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

F Steam Generator Blowdown System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.F-25

(S-10)

VIII.F.3-a 

VIII.F.1-b 

VIII.F.2-b

Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.F-26

(S-16)

VIII.F.1-a 

VIII.F.2-a

Piping, piping 

components, 

and piping 

elements

Steel Treated water Wall thinning/ flowaccelerated corrosionChapter XI.M17, “Flow-Accelerated 

Corrosion”

No

VIII.F-27

(S-22)

VIII.F.4-a 

VIII.F.4-d

PWR heat 

exchanger 

components

Stainless 

steel

Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR primary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.F-28

(S-19)

VIII.F.4-a 

VIII.F.4-d

PWR heat 

exchanger 

components

Steel Treated water Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
September 2005 VIII G-1 NUREG-1801, Rev. 1

G. AUXILIARY FEEDWATER SYSTEM (PWR)

Systems, Structures, and Components

This section addresses the auxiliary feedwater (AFW) system for pressurized water reactors 

(PWRs), which extends from the condensate storage or backup water supply system to the 

steam generator or to the main feedwater (MFW) line. They consist of AFW piping, AFW 

pumps, pump turbine oil coolers, and valves, including the containment isolation valves. 

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” portions of 

the AFW system extending from the secondary side of the steam generator up to the second 

isolation valve and including the containment isolation valves are governed by Group B Quality 

Standards. In addition, portions of the AFW system that are required for their safety functions 

and that either do not operate during any mode of normal reactor operation or cannot be tested 

adequately are also governed by Group B Quality Standards. The remainder of the structures 

and components covered in this section are governed by Group C Quality Standards. 

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration. They are subject to replacement based on qualified life or specified time period. 

Pursuant to 10 CFR 54.21(a)(1), therefore, they are not subject to an aging management 

review.

Aging management programs for the degradation of the external surfaces of components and 

miscellaneous bolting are included in VIII.H. Common miscellaneous material/environment

combinations, where aging effects are not expected to degrade the ability of the structure or 

component to perform its intended function for the extended period of operation, are included in 

VIII.I. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

The systems that interface with the AFW system include the steam generator (IV.D1 and IV.D2), 

the main steam system (VIII.B1), the PWR feedwater system (VIII.D1), the condensate system 

(VIII.E), and the open- or closed-cycle cooling water systems (VII.C1 or VII.C2).
NUREG-1801, Rev. 1 VIII G-2 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

G Auxiliary Feedwater System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.G-1

(S-01)

VIII.G.1-e 

VIII.G.4-d

Buried piping, 

piping 

components, 

piping 

elements, and 

tanks

Steel (with 

or without 

coating or 

wrapping)

Soil Loss of material/ 

general, pitting, 

crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M28, “Buried Piping and 

Tanks Surveillance,” or

Chapter XI.M34, “Buried Piping and 

Tanks Inspection”

No 

Yes, detection 

of aging 

effects and 

operating 

experience 

are to be 

further 

evaluated

VIII.G-2

(S-25)

VIII.G.5-c Heat 

exchanger 

components

Stainless 

steel

Closed cycle 

cooling water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

VIII.G-3

(S-20)

VIII.G.5-d Heat 

exchanger 

components

Stainless 

steel

Lubricating oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.G-4

(S-26)

VIII.G.5-a Heat 

exchanger 

components

Stainless 

steel

Raw water Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion, 

and fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VIII.G-5

(S-23)

VIII.G.5-c Heat 

exchanger 

components

Steel Closed cycle 

cooling water

Loss of material/ 

general, pitting,

crevice, and galvanic 

corrosion

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No
September 2005 VIII G-3 NUREG-1801, Rev. 1

VIII STEAM AND POWER CONVERSION SYSTEM

G Auxiliary Feedwater System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.G-6

(S-17)

VIII.G.5-d Heat 

exchanger 

components

Steel Lubricating oil Loss of material/ 

general, pitting, 

crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.G-7

(S-24)

VIII.G.5-a Heat 

exchanger 

components

Steel Raw water Loss of material/ 

general, pitting, 

crevice, galvanic, 

and microbiologically 

influenced corrosion, 

and fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VIII.G-8

(SP-53)

VIII.G. Heat 

exchanger 

tubes

Copper alloy Lubricating oil Reduction of heat 

transfer/fouling

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.G-9

(SP-56)

VIII.G. Heat 

exchanger 

tubes

Copper alloy Raw water Reduction of heat 

transfer/fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No
NUREG-1801, Rev. 1 VIII G-4 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

G Auxiliary Feedwater System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.G-10

(SP-58)

VIII.G. Heat 

exchanger 

tubes

Copper alloy Treated water Reduction of heat 

transfer/fouling

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.G-11

(SP-41)

VIII.G. Heat 

exchanger 

tubes

Stainless 

steel

Closed cycle 

cooling water

Reduction of heat 

transfer/fouling

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

VIII.G-12

(SP-62)

VIII.G. Heat 

exchanger 

tubes

Stainless 

steel

Lubricating oil Reduction of heat 

transfer/fouling

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.G-13

(S-28)

VIII.G.5-b Heat 

exchanger 

tubes

Stainless 

steel

Raw water Reduction of heat 

transfer/fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VIII.G-14

(SP-64)

VIII.G.5-c Heat 

exchanger 

tubes

Steel Closed cycle 

cooling water

Reduction of heat 

transfer/fouling

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No
September 2005 VIII G-5 NUREG-1801, Rev. 1

VIII STEAM AND POWER CONVERSION SYSTEM

G Auxiliary Feedwater System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.G-15

(SP-63)

VIII.G. Heat 

exchanger 

tubes

Steel Lubricating oil Reduction of heat 

transfer/fouling

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.G-16

(S-27)

VIII.G.5-b Heat 

exchanger 

tubes

Steel Raw water Reduction of heat 

transfer/fouling

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VIII.G-17

(SP-24)

VIII.G. Piping, piping 

components, 

and piping 

elements

Aluminum Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, "Water Chemistry"

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.G-18

(SP-8)

VIII.G. Piping, piping 

components, 

and piping 

elements

Copper alloy Closed cycle 

cooling water

Loss of material/ 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

VIII.G-19

(SP-32)

VIII.G. Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
NUREG-1801, Rev. 1 VIII G-6 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

G Auxiliary Feedwater System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.G-20

(SP-31)

VIII.G. Piping, piping 

components, 

and piping 

elements

Copper alloy Raw water Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VIII.G-21

(SP-29)

VIII.G. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Closed cycle 

cooling water

Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching 

of Materials”

No

VIII.G-22

(SP-30)

VIII.G. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Raw water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching 

of Materials”

No

VIII.G-23

(SP-55)

VIII.G. Piping, piping 

components, 

and piping 

elements

Copper alloy 

>15% Zn

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching 

of Materials”

No

VIII.G-24

(SP-28)

VIII.G. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Raw water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching 

of Materials”

No

VIII.G-25

(SP-26)

VIII.G. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Soil Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching 

of Materials" 

No

VIII.G-26

(SP-27)

VIII.G. Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Treated water Loss of material/ 

selective leaching

Chapter XI.M33, “Selective Leaching 

of Materials”

No
September 2005 VIII G-7 NUREG-1801, Rev. 1

VIII STEAM AND POWER CONVERSION SYSTEM

G Auxiliary Feedwater System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.G-27

(SP-39)

VIII.G. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed cycle 

cooling water

Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

VIII.G-28

(SP-54)

VIII.G. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed cycle 

cooling water 

>60°C (>140°F)

Cracking/stress

corrosion cracking

Chapter XI.M21, “Closed-Cycle 

Cooling Water System”

No

VIII.G-29

(SP-38)

VIII.G. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Lubricating oil Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.G-30

(SP-36)

VIII.G. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Raw water Loss of material/ 

pitting, crevice, and 

microbiologically 

influenced corrosion

Chapter XI.M20, “Open-Cycle Cooling 

Water System”

No

VIII.G-31

(SP-37)

VIII.G. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Soil Loss of material/ 

pitting and crevice 

corrosion

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific
NUREG-1801, Rev. 1 VIII G-8 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

G Auxiliary Feedwater System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.G-32

(SP-16)

VIII.G. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material/ 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.G-33

(SP-17)

VIII.G. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking/stress

corrosion cracking

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.G-34

(SP-60)

VIII.G. Piping, piping 

components, 

and piping 

elements

Steel Condensation 

(Internal)

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M38, "Inspection of 

Internal Surfaces in Miscellaneous 

Piping and Ducting Components"

No

VIII.G-35

(SP-25)

VIII.G. Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M39, "Lubricating Oil 

Analysis"

The AMP is to be augmented by 

verifying the effectiveness of the 

lubricating oil analysis program. See 

Chapter XI.M32, “One-Time 

Inspection,” for an acceptable 

verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
September 2005 VIII G-9 NUREG-1801, Rev. 1

VIII STEAM AND POWER CONVERSION SYSTEM

G Auxiliary Feedwater System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.G-36

(S-12)

VIII.G.1-d Piping, piping 

components, 

and piping 

elements

Steel Raw water Loss of material/ 

general, pitting, 

crevice, and 

microbiologically 

influenced corrosion, 

and fouling

A plant-specific aging management 

program is to be evaluated.

Yes, plantspecific

VIII.G-37

(S-11)

VIII.G.1-b Piping, piping 

components, 

and piping 

elements

Steel Treated water Cumulative fatigue 

damage/ fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluated for 

the period of extended operation. See 

the Standard Review Plan, Section 

4.3 “Metal Fatigue,” for acceptable 

methods for meeting the requirements 

of 10 CFR 54.21(c)(1).

Yes,

TLAA

VIII.G-38

(S-10)

VIII.G.4-a 

VIII.G.3-a 

VIII.G.1-c 

VIII.G.2-a

Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M2, “Water Chemistry,” for 

PWR secondary water

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated

VIII.G-39

(S-16)

VIII.G.1-a Piping, piping 

components, 

and piping 

elements

Steel Treated water Wall thinning/ flowaccelerated corrosionChapter XI.M17, “Flow-Accelerated 

Corrosion”

No

VIII.G-40

(S-31)

VIII.G.4-c Tanks Steel Air – outdoor 

(External)

Loss of material/ 

general, pitting, and 

crevice corrosion

Chapter XI.M29, “Aboveground Steel 

Tanks”

No
NUREG-1801, Rev. 1 VIII G-10 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

G Auxiliary Feedwater System (PWR)

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.G-41

(S-13)

VIII.G.4-a 

VIII.G.4-b

Tanks Steel, 

Stainless 

steel

Treated water Loss of material/ 

general (steel only), 

pitting and crevice 

corrosion

Chapter XI.M2, “Water Chemistry”

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, “One-Time Inspection,” for an 

acceptable verification program.

Yes, detection 

of aging 

effects is to be 

evaluated
September 2005 VIII H-1 NUREG-1801, Rev. 1

H. EXTERNAL SURFACES OF COMPONENTS AND MISCELLANEOUS BOLTING

Systems, Structures, and Components

This section includes the aging management programs for the degradation of external surfaces 

of all steel structures and components, including closure bolting in the steam and power 

conversion system in pressurized water reactors (PWRs) and boiling water reactors (BWRs). 

For the steel components in PWRs, this section addresses only boric acid corrosion of external 

surfaces as a result of dripping borated water leaking from an adjacent PWR component. 

System Interfaces

The structures and components covered in this section belong to the Steam and Power 

Conversion Systems in PWRs and BWRs (for example, see system interfaces in VIII.A to VIII.G 

for details).
NUREG-1801, Rev. 1 VIII H-2 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

H External Surfaces of Components and Miscellaneous Bolting

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.H-1

(S-32)

VIII.H. Bolting Steel Air – outdoor 

(External)

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M18, “Bolting Integrity” No

VIII.H-2

(S-40)

VIII.H. Bolting Steel Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid Corrosion” No

VIII.H-3

(S-03)

VIII.H.2-b Closure 

bolting

Highstrength 

steel

Air with steam or 

water leakage

Cracking/ cyclic 

loading, stress 

corrosion cracking

Chapter XI.M18, “Bolting Integrity” No

VIII.H-4

(S-34)

VIII.H. Closure 

bolting

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general, pitting, 

and crevice 

corrosion

Chapter XI.M18, “Bolting Integrity” No

VIII.H-5

(S-33)

VIII.H. Closure 

bolting

Steel Air – indoor 

uncontrolled 

(External)

Loss of preload/ 

thermal effects, 

gasket creep, and 

self-loosening 

Chapter XI.M18, “Bolting Integrity” No

VIII.H-6

(S-02)

VIII.H.2-a Closure 

bolting

Steel Air with steam or 

water leakage

Loss of material/ 

general corrosion

Chapter XI.M18, “Bolting Integrity” No

VIII.H-7

(S-29)

VIII.H.1-b External 

surfaces

Steel Air – indoor 

uncontrolled 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VIII.H-8

(S-41)

VIII.H.1-b External 

surfaces

Steel Air – outdoor 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No

VIII.H-9

(S-30)

VIII.H.1-a External 

surfaces

Steel Air with borated 

water leakage

Loss of material/ 

boric acid 

corrosion

Chapter XI.M10, “Boric Acid Corrosion” No
September 2005 VIII H-3 NUREG-1801, Rev. 1

VIII STEAM AND POWER CONVERSION SYSTEM

H External Surfaces of Components and Miscellaneous Bolting

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.H-10

(S-42)

VIII.H.1-b External 

surfaces

Steel Condensation 

(External)

Loss of material/ 

general corrosion

Chapter XI.M36, "External Surfaces 

Monitoring"

No
NUREG-1801, Rev. 1 VIII H-4 September 2005

This Page Intentionally Left Blank
September 2005 VIII I-1 NUREG-1801, Rev. 1

I. COMMON MISCELLANEOUS MATERIAL/ENVIRONMENT COMBINAT IONS

Systems, Structures, and Components

This section includes the aging management programs for miscellaneous material/environment 

combinations which may be found throughout the steam and power conversion system’s 

structures and components. For the material/environment combinations in this part, aging 

effects are not expected to degrade the ability of the structure or component to perform its 

intended function for the extended period of operation. Therefore, no resulting aging 

management programs for these structures and components are required.

System Interfaces

The structures and components covered in this section belong to the steam and power 

conversion system in pressurized water reactors (PWRs) and boiling water reactors (BWRs)

(For example, see system interfaces in VIII.A to VIII.D2 for details). 
NUREG-1801, Rev. 1 VIII I-2 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

I Common Miscellaneous Material/Environment Combinations

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.I-1

(SP-23)

VIII.I. Piping, piping 

components, 

and piping 

elements

Aluminum Gas None None No

VIII.I-2

(SP-6)

VIII.I. Piping, piping 

components, 

and piping 

elements

Copper alloy Air – indoor 

uncontrolled 

(External)

None None No

VIII.I-3

(SP-5)

VIII.I. Piping, piping 

components, 

and piping 

elements

Copper alloy Gas None None No

VIII.I-4

(SP-33)

VIII.I. Piping 

elements

Glass Air None None No

VIII.I-5

(SP-9)

VIII.I. Piping 

elements

Glass Air – indoor 

uncontrolled 

(External)

None None No

VIII.I-6

(SP-10)

VIII.I. Piping 

elements

Glass Lubricating oil None None No
September 2005 VIII I-3 NUREG-1801, Rev. 1

VIII STEAM AND POWER CONVERSION SYSTEM

I Common Miscellaneous Material/Environment Combinations

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.I-7

(SP-34)

VIII.I. Piping 

elements

Glass Raw water None None No

VIII.I-8

(SP-35)

VIII.I. Piping 

elements

Glass Treated water None None No

VIII.I-9

(SP-11)

VIII.I. Piping, piping 

components, 

and piping 

elements

Nickel alloy Air – indoor 

uncontrolled 

(External)

None None No

VIII.I-10

(SP-12)

VIII.I. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Air – indoor 

uncontrolled 

(External)

None None No

VIII.I-11

(SP-13)

VIII.I. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Concrete None None No

VIII.I-12

(SP-15)

VIII.I. Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Gas None None No
NUREG-1801, Rev. 1 VIII I-4 September 2005

VIII STEAM AND POWER CONVERSION SYSTEM

I Common Miscellaneous Material/Environment Combinations

Item Link

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program (AMP) Further Evaluation

VIII.I-13

(SP-1)

VIII.I. Piping, piping 

components, 

and piping 

elements

Steel Air – indoor 

controlled 

(External)

None None No

VIII.I-14

(SP-2)

VIII.I. Piping, piping 

components, 

and piping 

elements

Steel Concrete None None No

VIII.I-15

(SP-4)

VIII.I. Piping, piping 

components, 

and piping 

elements

Steel Gas None None No
September 2005 IX-i NUREG-1801, Rev. 1

CHAPTER IX

SELECTED DEFINITIONS AND USE OF TERMS

FOR 

STRUCTURES, COMPONENTS, MATERIALS, 

ENVIRONMENTS, 

AGING EFFECTS, AND AGING MECHANISMS
NUREG-1801, Rev. 1 IX-ii September 2005

This Page Intentionally Left Blank
September 2005 IX-1 NUREG-1801, Rev. 1

SELECTED DEFINITIONS and USE OF TERMS FOR DESCRIBING AND 

STANDARDIZING STRUCTURES, COMPONENTS, MATERIALS, ENVIRONMENTS, 

AGING EFFECTS, AND AGING MECHANISMS

A. Introduction

B. Structures and Components

C. Materials

D. Environments

E. Aging Effects

F. Aging Mechanisms

G. References
NUREG-1801, Rev. 1 IX-2 September 2005

A. Introduction

The format and content of the aging management review (AMR) tables presented here 

in the GALL Report, Vol. 2, (GALL’05) have been revised to enhance its applicability to 

future plant license renewal applications. Several types of changes were incorporated in 

this revision to achieve the objective. One of these was to add material, environment, 

aging effect and program (MEAP) combinations established by precedents establishing 

strong technical justification from earlier license renewal applications (LRAs) and the 

corresponding NRC safety evaluation reports (SERs). 

Associated with this was the simplification and generalization of terms used within these 

MEAP combinations to make the line items more generic and less prescriptive. As a 

simple example, the phrase " Piping, piping components, and piping elements" is used 

to replace various combinations of “piping, fittings, tubing, flow elements/indicators, 

demineralizer, nozzles, orifices, flex hoses, pump casing and bowl, safe ends, sight 

glasses, spray head, strainers, thermowells, and valve body and bonnet." 

Further associated with this simplification is the need to define, here in this new chapter 

IX, and further in NUREG-1833, Technical Bases for Revision to the License Renewal 

Guidance Documents (“Bases Document”), what these simplified terms mean and how 

and where they are used, and what parameters in GALL’01, they have replaced. The 

following tables define some of the simplified terms used in the preceding GALL AMR 

tables in Chapters II, III, IV, V, VI, VII, and VIII, of this document. An electronic version of 

this GALL’05 is available, in which each expression defined in these tables is linked to 

the specific chapters in the GALL report where they occur. A complete listing of the 

unique identifiers and their locations of usage in the revised GALL Report is found in 

Appendix A of the Bases Document, accompanying the 2005 revision of the license 

renewal guidance documents.

B. Structures and Components

The GALL Report does not address scoping of structures and components for license 

renewal. Scoping is plant-specific, and the results depend on individual plant design and 

its current licensing basis. The inclusion of a certain structure or component in the GALL 

Report does not mean that this particular structure or component is within the scope of 

license renewal for all plants. Conversely, the omission of a certain structure or 

component in the GALL Report does not mean that this particular structure or 

component is omitted from the scope of license renewal for any plant.
September 2005 IX-3 NUREG-1801, Rev. 1

IX.B Selected Definitions & Use of Terms for Describing and Standardizing

STRUCTURES AND COMPONENTS

Term Definition as used in this document

Bolting Bolting can refer to either structural bolting or closure 

bolting. Within the scope of license renewal, both 

Class 1 and non-Class 1 systems and components 

contain bolted closures that are necessary for the 

pressure boundary of the components being 

joined/closed. Closure bolting in high-pressure or 

high-temperature systems is defined as that in which

the pressure exceeds 275 psi or 200oF (93oC).

Closure bolting is used to join pressure boundaries 

or where a mechanical seal is required; bolting 

includes closure bolting and all other bolting.

Ducting and components Ducting and components include heating, ventilation,

and air-conditioning (HVAC) components. Examples 

include ductwork, ductwork fittings, access doors, 

closure bolts, equipment frames and housing, 

housing supports, including housings for valves, 

dampers (including louvers and gravity dampers), 

and ventilation fans (including exhaust fans, intake 

fans, and purge fans). In some cases, this also 

includes piping.

Encapsulation Components/

Valve Chambers

These are airtight enclosures that function as a 

secondary containment boundary to completely 

enclose containment sump lines and isolation valves. 

Encapsulation components and features (in systems 

such as emergency core cooling system, 

containment spray system, and containment isolation 

system, and refueling water storage tank) can 

include encapsulation vessels, piping, and valves. 

External surfaces In the context of structures and components, the

term “external surfaces” is used to represent the 

external surfaces of structures and components such 

as tanks that are not specifically listed elsewhere.
NUREG-1801, Rev. 1 IX-4 September 2005

IX.B Selected Definitions & Use of Terms for Describing and Standardizing

STRUCTURES AND COMPONENTS

Term Definition as used in this document

Heat exchanger components A heat exchanger is a device that transfers heat from 

one fluid to another without the fluids coming in 

contact with each other. This includes air handling 

units and other devices that cool or heat fluids. Heat 

exchanger component examples may include, but 

are not limited to, air handling unit cooling and 

heating coils, piping/tubing, shell, tubesheets, tubes, 

valves, and bolting. Although tubes are the primary 

heat transfer component, heat exchanger internals 

including tubesheets and fins contribute to heat 

transfer and may be affected by reduction of heat 

transfer due to fouling [1].The inclusion of such 

components as tubesheets is dependent on 

manufacturer specifications.

High voltage insulators An insulator is an insulating material in a form 

designed to physically support a conductor and 

separate the conductor electrically from other 

conductors or objects. The insulators that are 

evaluated for license renewal are those used to 

support and insulate high voltage electrical 

components in switchyards, switching stations and 

transmission lines.

Metal-enclosed bus “Metal-enclosed buses” (MEBs) is the term used in 

proper electrical and industry standard (IEEE and 

ANSI) for electrical buses installed on electricallyinsulated supports that are constructed with all 

phase conductors enclosed in a separate metal 

enclosure or a common metal enclosure. 

Piping, piping components, 

and piping elements 

This general category includes various features of 

the piping system that are within the scope of license 

renewal. Examples include piping, fittings, tubing, 

flow elements/indicators, demineralizer, nozzles, 

orifices, flex hoses, pump casing and bowl, safe 

ends, sight glasses, spray head, strainers, 

thermowells, and valve body and bonnet. For reactor 

coolant pressure boundary components in Chapter 

IV that are subject to cumulative fatigue damage, this

can also include flanges, nozzles and safe ends, 

penetrations, vessel head, shell, welds, stub tubes 

and miscellaneous Class 1 components, such as 

pressure housings.
September 2005 IX-5 NUREG-1801, Rev. 1

IX.B Selected Definitions & Use of Terms for Describing and Standardizing

STRUCTURES AND COMPONENTS

Term Definition as used in this document

Piping elements This general category includes components made of 

glass, such as sight glasses and level indicators. 

This “piping elements” designation is used in the 

AMR tables only when the material is defined as 

glass.

Pressure housings The term “pressure housing” only refers to pressure 

housing for the control rod drive (CRD) head 

penetration (as indicated in GALL’01, it is only of 

concern in Section A2 for PWR reactor vessels).

Reactor Coolant Pressure 

Boundary Components

Reactor coolant pressure boundary components 

include, but are not limited to: piping, piping 

components, and piping elements; flanges; nozzles 

and safe ends; pressurizer vessel shell heads and 

welds; heater sheaths and sleeves; penetrations; 

and thermal sleeves.

Seals, gaskets, and moisture 

barriers (calking, flashing, and 

other sealants)

Elastomer components used as sealant, or as 

gaskets.

Steel elements: liner; liner 

anchors; integral attachments

Steel liners used in suppression pool or spent fuel 

pool.

Switchyard bus Switchyard bus is the uninsulated, unenclosed, rigid 

electrical conductor or pipe 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.
NUREG-1801, Rev. 1 IX-6 September 2005

IX.B Selected Definitions & Use of Terms for Describing and Standardizing

STRUCTURES AND COMPONENTS

Term Definition as used in this document

Tanks Tanks, in deference to piping and piping 

components, are large reservoirs used as hold-up 

volumes for liquids or gases. Tanks may have an 

internal liquid space and/or vapor space and may 

also be situated in proximity to soils or concrete on 

the exterior surface. Tanks are treated in GALL’05 

as a separate commodity due to the potential need 

for a different aging management regime for piping.

The following is one example of aging management 

for tanks in GALL’05. Steel tanks with bottoms in a 

soil or concrete environment have general corrosion 

as the aging effect for the interface between soil or 

concrete and the bottom of the tank. Degradation of 

the tank bottoms in these aboveground steel tanks 

can be managed by the GALL AMP XI.M29 

“Aboveground Steel Tanks.”

Transmission conductors 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 and passive switchyard bus.

Vibration isolation elements Non-steel supports used for supporting components 

prone to vibration.
September 2005 IX-7 NUREG-1801, Rev. 1

C. Materials

The following table defines many generalized materials used in the preceding GALL 

AMR tables in Chapters II, III, IV, V, VI, VII, and VIII, of GALL’05. A complete listing of 

the materials, the correlation to more specific material designations, and their locations 

of usage are found in Appendix A of the Bases Document, NUREG-1833, accompanying

the 2005 revision of the license renewal guidance documents.

IX.C Selected Definitions & Use of Terms for Describing and Standardizing

MATERIALS

Term Definition as used in this document

Boraflex Boraflex is a material that is composed of 46% silica, 4% 

polydimethyl siloxane polymer and 50% boron carbide, by 

weight. It is a neutron absorbing material used as a neutron 

absorber in spent fuel storage racks; degradation of Boraflex 

panels under gamma radiation can lead to loss of the ability 

to absorb neutrons in spent fuel storage pools. The GALL 

AMP XI.M22 is used as a reference for Boraflex monitoring.

Boral, boron steel Boron steel is steel with boron content ranging from one to 

several percent. Boron steel absorbs neutrons and thus is 

often used as a control rod to help control the neutron flux. 

Boral is material consisting of boron carbide sandwiched 

between aluminum. Boral refers to patented AluminumBoron master alloys; these alloys can contain up to 10% 

boron as AlB12 intermetallics.

Cast austenitic stainless 

steel (CASS)

CASS alloys, such as CF-3, CF-8, CF-3M, and CF-8M, have 

been widely used in LWRs. These CASS alloys are similar to 

wrought grades Type 304L, Type 304, Type 316L, and Type 

316, except CASS typically contains 5 to 25% ferrite. CASS 

is susceptible to loss of fracture toughness due to thermal 

and neutron irradiation embrittlement.

Copper alloy <15% Zn The broad purpose of this material category is to collect 

those copper alloys whose critical alloying elements are less 

than certain thresholds that keep the alloy from being 

susceptible to aging effects. For example, copper, copper 

nickel, brass, bronze <15% zinc, and aluminum bronze <8% 

aluminum are resistant to stress corrosion cracking, selective 

leaching and pitting and crevice corrosion. They may be 

identified simply as copper alloy when these aging 

mechanisms are not at issue. 
NUREG-1801, Rev. 1 IX-8 September 2005

IX.C Selected Definitions & Use of Terms for Describing and Standardizing

MATERIALS

Term Definition as used in this document

Copper alloy >15% Zn The broad purpose of this material category is to collect 

those copper alloys whose critical alloying elements are 

above certain thresholds that make the alloy susceptible to 

aging effects. Copper-zinc alloys >15% zinc are susceptible 

to stress corrosion cracking, selective leaching (except for 

inhibited brass), and pitting and crevice corrosion. Additional 

copper alloys may be susceptible, such as aluminum bronze 

> 8% aluminum. The elements that are most commonly 

alloyed with copper are zinc (referred to as brass), tin 

(referred to as bronze), nickel, silicon, aluminum (referred to 

as aluminum-bronze), cadmium and beryllium. Additional 

copper alloys may be susceptible to these aging effects 

above the threshold for the critical alloying element.

Elastomers Elastomers are materials such as rubber, EPT, EPDM, 

PTFE, ETFE, viton, vitril, neoprene, and silicone elastomer. 

Hardening and loss of strength of elastomers can be induced 

by elevated temperature (over about 95°F (35°C), and 

additional aging factors such as exposure to ozone, 

oxidation, and radiation.

Galvanized steel Steel coated with zinc usually by immersion or 

electrodeposition. The zinc coating in galvanized steel 

protects the underlying steel and the corrosion rate of zinc 

(coating the steel) in dry clean air is very low.

Glass Any glass materials. Glass is a hard, amorphous, brittle 

super-cooled liquid made by fusing together one or more of 

the oxides of silicon, boron, or phosphorous, with certain 

basic oxides (e.g., Na, Mg, Ca, K), and cooling the product 

rapidly to prevent crystallization or devitrification. 

Graphitic tool steel Graphitic tool steels (such as AISI O6 which is oil-hardening 

and, AISI A10 which is air-hardening), have excellent nonseizing properties. The graphite particles provide self lubricity 

and hold applied lubricants.
September 2005 IX-9 NUREG-1801, Rev. 1

IX.C Selected Definitions & Use of Terms for Describing and Standardizing

MATERIALS

Term Definition as used in this document

Gray cast iron This form of cast iron is an iron alloy used in nuclear plants. 

Cast iron is made by adding larger amounts of carbon to 

molten iron than would be used to make steel. Most steels 

will have less than about 1.2% by weight carbon, while cast 

irons typically have between 2.5 to 4% by weight carbon. 

Gray cast iron has flat graphite flakes, which reduce its 

strength and act as crack formers, initiating mechanical 

failures. They also cause the metal to behave in a nearly 

brittle fashion, rather than experiencing the elastic, ductile 

behavior of steel. Fractures in this type of metal tend to take 

place along the flakes, which give the fracture surface a gray 

color, hence the name of the metal. 

Cast iron is susceptible to selective leaching resulting in a 

significant reduction of the material’s strength due to the loss 

of iron from the microstructure, leaving a porous matrix of 

graphite.

Insulation materials (e.g. 

bakelite, phenolic 

melamine or ceramic, 

molded polycarbonate)

Electrical fuse holders are composed of insulation materials, 

e.g. bakelite, phenolic melamine or ceramic, molded 

polycarbonate.

Low-alloy steel, yield 

strength >150 ksi

High-strength Fe-Cr-Ni-Mo low alloy steel bolting materials 

with maximum tensile strength <1172 MPa (<170 Ksi) may 

be subject to stress corrosion cracking if the actual 

measured yield strength Sy = 150 ksi. Examples of high 

strength alloy steel designations that were earlier referenced 

in GALL’01 that comprise this category include SA540-Gr. 

B23/24, SA193-Gr. B8, and Grade L43 (AISI4340).

Low-alloy steel SA 193 Gr. B7 is a ferritic low-alloy steel 

bolting material for high-temperature service. 

Low-alloy steel includes AISI steels 4140, 4142, 4145, 

4140H, 4142H, and 4145H (UNS#: G41400, G41420, 

G41450, H41400, H41420, H41450). Bolting fabricated from 

high-strength (actual measured yield strength Sy = 150 ksi) 

low-alloy steel SA 193 Gr. B7 is susceptible to stress 

corrosion cracking.

Lubrite®Lubrite® refers to a patented technology in which the bearing 

substrate (bronze is commonly used, but, in unusual 

environments, other materials, ranging from stainless steel 

and nodular-iron to tool-steel, are used) is fastened to 

lubricant. Lubrite® is often defined as bronze attached to 

ASTM B22, alloy 905, with G10 lubricant.
NUREG-1801, Rev. 1 IX-10 September 2005

IX.C Selected Definitions & Use of Terms for Describing and Standardizing

MATERIALS

Term Definition as used in this document

Even though Lubrite® bearings are characterized as 

maintenance-free, because of the differences in installation, 

fineness of the surfaces, and lubricant characteristics, they 

can be subjected to mechanical wear and fretting. 

Though experience with the use of Lubrite® bearings has not 

shown adverse conditions related to the use of Lubrite®, the 

unique environment and tight installation tolerances required 

for installing the bearings would require the bearing specific 

examinations. The general vendor’s (Lubrite® Technologies) 

literature shows basically 10 lubricant types used in the 

bearings; ranging from (G1) “General Duty,” to AE7 

(temperature and radiation tested) lubricants. Depending on 

the plant specific specification, lubricants of various 

requirements may have been used. Any deviation from the 

required tight tolerances for installation of the bearings could 

give rise to functional problems during the challenging 

loading conditions (DBA, SSE). Thus, ensuring the general 

installation conditions, and clearing out any obstruction to its 

functioning will ensure the proper functioning of these 

bearings under challenging loading conditions. The 

associated aging effects could be malfunctioning, distortion, 

dirt accumulation, and fatigue effects under vibratory and 

cyclic thermal loads. The potential aging effects could be 

managed by incorporating its periodic examination in IWF 

AMP (XI.S3) or SMP AMP (XI.S6).

Malleable iron Malleable iron usually means malleable cast iron, 

characterized by exhibiting some elongation and reduction in 

area in a tensile test. Malleable iron is one of the materials in 

the category of “Porcelain, Malleable iron, aluminum, 

galvanized steel, cement” as shown in AMR line-items LP-07 

and LP-11.

Nickel alloys Nickel-chromium-iron (molybdenum) alloys are those such 

as the Alloy 600 and 690. Examples of nickel alloy 

designations that were earlier referenced in GALL’01 that 

comprise this category include Alloy 182, Alloy 600, Alloy 

690, Gr. 688 (X-750), Inconel 182, Inconel 82, NiCrFe, SB166, SB-167, SB-168, X-750. [2]

Polymer (e.g., rubber) Polymeric materials, such as rubber.

Porcelain Hard-quality porcelain is used as an insulator for supporting 

high-voltage electrical insulators. Porcelain is a hard, finegrained ceramic that essentially consists of kaolin, quartz, 

and feldspar that is fired at high temperatures. 
September 2005 IX-11 NUREG-1801, Rev. 1

IX.C Selected Definitions & Use of Terms for Describing and Standardizing

MATERIALS

Term Definition as used in this document

Polymers used in 

electrical applications 

Polymers used in electrical applications include EPR, SR, 

EPDM, XLPE. XLPE is cross-linked polyethylene in the 

category of thermoplastic resins as polyethylene and 

polyethylene copolymers. EPR and EPDM are ethylenepropylene rubbers in the category of thermosetting 

elastomers. 

SA508-Cl 2 forgings clad 

with stainless steel using 

a high-heat-input 

welding process

Quenched and tempered vacuum-treated carbon and alloy 

steel forgings for pressure vessels. 

Stainless steel Wrought or forged austenitic, ferritic, martensitic, 

precipitation hardened (PH) martensitic, or duplex stainless 

steel (Cr content >11%) are grouped for AMRs under the 

term “stainless steel.” These materials are susceptible to a 

variety of aging effects and mechanisms, including loss of 

material due to pitting and crevice corrosion, and cracking 

due to stress corrosion cracking. In the context of license 

renewal, in some cases, when the recommended AMP is the 

same for PH stainless steel or cast austenitic stainless steel 

(CASS) as for stainless steel, PH stainless steel or CASS 

are included as a part of the stainless steel classification. 

However, CASS is quite susceptible to loss of fracture 

toughness due to thermal and neutron irradiation 

embrittlement. Therefore, when this aging effect is being 

considered, CASS is specifically designated in the AMR lineitem. 

Steel with stainless steel cladding may also be considered 

stainless steel when the aging effect is associated with the 

stainless steel surface of the material, rather than the 

composite volume of the material.

Examples of stainless steel designations that were earlier 

referenced in GALL’01 that comprise this category include 

A-286, SA193-Gr. B8, SA193-Gr. B8M, Gr. 660 (A-286), 

SA193-6, SA193-Gr. B8 or B-8M, SA453, Type 304, Type 

304NG, Type 308, Type 308L, Type 309, Type 309L, Type 

316, Type 347, Type 403, and Type 416. 

Examples of CASS designations that were earlier referenced 

include CF-3, CF-8, CF-3M, and CF-8M. [2]
NUREG-1801, Rev. 1 IX-12 September 2005

IX.C Selected Definitions & Use of Terms for Describing and Standardizing

MATERIALS

Term Definition as used in this document

Steel For a given environment, carbon steel, alloy steel, cast iron, 

gray cast iron, malleable iron, and high strength low alloy 

steel are vulnerable to general, pitting, and crevice corrosion,

even though the rates of aging may vary. Consequently, 

these metal types are generally grouped for AMRs under the 

broad term “steel.” Note that this does not include stainless 

steel. However, gray cast iron is also susceptible to selective 

leaching, and high strength low alloy steel is susceptible to 

stress corrosion cracking. Therefore, when these aging 

effects are being considered, these materials are specifically 

called out. Galvanized steel (zinc-coated carbon steel) is 

also included in this category of “steel” when exposed to 

moisture. Malleable iron is also specifically called out in the 

phrase “Porcelain, Malleable iron, aluminum, galvanized 

steel, cement” used to define the high voltage insulators in 

chapter VI.

Examples of steel designations that were earlier referenced 

in GALL’01 that comprise this category include ASTM A 36, 

ASTM A 285, ASTM A759, SA36, SA106-Gr. B, SA155-Gr. 

KCF70, SA193-Gr. B7, SA194 -Gr. 7, SA302-Gr B, SA320-

Gr. L43 (AISI 4340), SA333-Gr. 6, SA336, SA508-64, class 

2, SA508-Cl 2 or Cl 3, SA516-Gr. 70, SA533-Gr. B, SA540-

Gr. B23/24, and SA582. [4]
September 2005 IX-13 NUREG-1801, Rev. 1

D. Environments

The following table defines many of the standardized environments used in the 

preceding GALL AMR tables in Chapters II, III, IV, V, VI, VII, and VIII, of GALL’05. A 

complete listing of the environments, the correlation to the environmental designations in 

GALL’01, and their locations is found in Appendix A of the Bases Document, NUREG1833, companying the 2005 revision of the license renewal guidance documents.

Some new technical criteria, such as temperature thresholds for aging effects in 

common use by the industry, are added to clarify further applicability of the results. 

Temperature threshold of 95°F (35°C) for thermal stresses in elastomers: In general, if 

the ambient temperature is less than about 95°F (35°C), then thermal aging may be 

considered not significant for rubber, butyl rubber, neoprene, nitrile rubber, silicone 

elastomer, fluoroelastomer, EPR, and EPDM [3]. Hardening and loss of strength of 

elastomers can be induced by thermal aging, exposure to ozone, oxidation, and 

radiation. When applied to the elastomers used in electrical cable insulation, it should be 

noted that most cable insulation is manufactured as either 75oC (167oF) or 90oC (194oF) 

rated material.

Temperature threshold of 140°F (60°C) for SCC in stainless steel: Stress corrosion 

cracking (SCC) occurs very rarely in austenitic stainless steels below 140°F (60°C). 

Although SCC has been observed in stagnant, oxygenated borated water systems at 

lower temperatures than this 140°F threshold, all of these instances have identified a 

significant presence of contaminants (halogens, specifically chlorides) in the failed 

components. With a harsh enough environment (i.e., significant contamination), SCC 

can occur in austenitic stainless steel at ambient temperature. However, these 

conditions are considered event-driven, resulting from a breakdown of chemistry controls 

[5, 6]. 

Temperature threshold of 482°F (250°C) for thermal embrittlement in CASS: CASS 

subjected to sustained temperatures below 250°C (482°F) will not result in a reduction of 

room temperature Charpy impact energy below 50 ft-lb for exposure times of 

approximately 300,000 hours (for CASS with ferrite content of 40% and approximately 

2,500,000 hours for CASS with ferrite content of 14%) [Fig. 2; Ref. 7]. For a maximum 

exposure time of approximately 420,000 hours (48 EFPY), a screening temperature of 

482°F is conservatively chosen because (1) the majority of nuclear grade materials is

expected to contain a ferrite content well below 40%, and (2) the 50 ft-lb limit is very 

conservative when applied to cast austenitic materials. It is typically applied to ferritic 

materials, e.g., 10 CFR 50 Appendix G. For CASS components in the reactor coolant 

pressure boundary, this threshold is supported by the GALL’05 AMP XI.M12, "Thermal 

Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)," with the exception of 

niobium-containing steels, which require evaluation on a case-by-case basis.

Specification of External or Internal Surface: Surface conditions of systems, structures, 

and components are monitored through visual examinations and leakage inspections to 

determine the existence of external and internal corrosion or deterioration. For some 

environments listed below such as air-indoor controlled, air-indoor uncontrolled, airoutdoor, condensation, air-indoor uncontrolled > 95° the component information 

description should identify whether the surface is external. This information is important,

because it indicates the applicability of direct visual observation of the surface for aging 
NUREG-1801, Rev. 1 IX-14 September 2005

management. For the remaining environments, this distinction need not be made, since 

the environment must be internal to some barrier that precludes direct observation of the 

surface.

IX.D Selected Definitions & Use of Terms for Describing and Standardizing

ENVIRONMENTS

Term Definition as used in this document

Adverse localized 

environment 

The conductor insulation used for electrical cables in 

instrumentation circuits can be subjected to an adverse 

localized environment. This can be represented within a 

specific GALL AMR line item as being due to any of the 

following: (1) exposure to moisture and voltage (2) heat, 

radiation, or moisture, in the presence of oxygen (3) heat, 

radiation, or moisture, in the presence of oxygen or >60-

year service limiting temperature, or (4) adverse localized 

environment caused by heat, radiation, oxygen, moisture, 

or voltage.

The term “>60-year service limiting temperature” refers to 

that temperature that exceeds the temperature below 

which the material has a 60-year or greater service 

lifetime. 

Aggressive environment 

(steel in concrete)

That occurring when concrete pH <11.5 or chlorides 

concentration >500 ppm. [8]

Air-indoor Uniquely used for the new AMR line-item LP-01 in Chapter 

VI for electrical systems, air-indoor is synonymous with 

“Air-indoor uncontrolled (internal/external).” Indoor air on 

systems with temperatures higher than the dew point, i.e., 

condensation can occur but only rarely, equipment 

surfaces are normally dry. 

Air-indoor controlled The environment to which the specified internal or external 

surface of the component or structure is exposed: indoor 

air in a humidity controlled (e.g., air conditioned) 

environment.

Air-indoor uncontrolled Indoor air on systems with temperatures higher than the 

dew point, i.e., condensation can occur but only rarely, 

equipment surfaces are normally dry. 
September 2005 IX-15 NUREG-1801, Rev. 1

IX.D Selected Definitions & Use of Terms for Describing and Standardizing

ENVIRONMENTS

Term Definition as used in this document

Air-indoor uncontrolled 

>35°C (>95°F) 

(Internal/External)

The environment to which the internal or external surface 

of the component or structure is exposed. Indoor air above 

thermal stress threshold for elastomers. If ambient is 

<95°F, then any resultant thermal aging of organic 

materials can be considered to be insignificant, over the 

60-yr period of interest. [4, 5] However, elastomers are 

subject to aging effects from other factors such as 

exposure to ozone, oxidation, and radiation.

Air-outdoor The outdoor environment consists of moist, possibly saltladen atmospheric air, ambient temperatures and 

humidity, and exposure to weather, including precipitation 

and wind. The component is exposed to air and local 

weather conditions, including salt water spray, where 

applicable. A component is considered susceptible to a 

wetted environment when it is submerged, has the 

potential to pool water, or is subject to external 

condensation.

Air with borated water 

leakage

Air and untreated borated water leakage on indoor or 

outdoor systems with temperatures above or below the 

dew point. The water from leakage is considered to be 

untreated, due to the potential for water contamination at 

the surface. This is germane to PWRs.

Air with leaking 

secondary-side water 

and/or steam

Steel components in the pressure boundary and structural 

parts of the once-through steam generator may be 

exposed to an environment consisting of air with leaking 

secondary-side water and/or steam.

Air with metal 

temperature up to 288°C 

(550°F)

In the context of GALL’05, synonymous with the more 

commonly-used phrase, system temperature up to 288°C 

(550°F). 

Air with reactor coolant 

leakage

Air and reactor coolant or steam leakage on high 

temperature systems. This is germane to BWRs.

Air with steam or water 

leakage

Air and untreated steam or water leakage on indoor or 

outdoor systems with temperatures above or below the 

dew point.

Air, dry Air that has been treated to reduce the dew point well 

below the system operating temperature
NUREG-1801, Rev. 1 IX-16 September 2005

IX.D Selected Definitions & Use of Terms for Describing and Standardizing

ENVIRONMENTS

Term Definition as used in this document

Air, moist Air with enough moisture to facilitate loss of material in 

steel caused by general, pitting, and crevice corrosion. 

Moist air in the absence of condensation is also potentially 

aggressive, e.g., under conditions where hygroscopic 

surface contaminants are present.

Any Could be any environment indoors or outdoor, aging effect 

not dependent on environment.

Closed cycle cooling 

water

Treated water subject to the closed cycle cooling water 

chemistry program. Closed cycle cooling water >60°C 

(>140°F) allows the possibility of stainless steel SCC. 

Examples of environment descriptors that comprise this 

category can include, but are not limited to

• chemically treated borated water; and treated 

component cooling water

• demineralized water on one side; closed-cycle cooling 

water (treated water) on the other side

• chemically treated borated water on tube side and 

closed-cycle cooling water on shell side.

Concrete Components embedded in concrete.

Condensation 

(internal/external)

The environment to which the internal or external surface 

of the component or structure is exposed. Condensation 

on the surfaces of systems with temperatures below the 

dew point is considered raw water, due to potential for 

surface contamination. For the purposes of GALL’05, 

under certain circumstances, the GALL’01 terms “moist 

air” or “warm moist air” are enveloped by condensation to 

describe an environment where there is enough moisture 

for corrosion to occur.

Containment 

environment (inert) 

The drywell is made inert with hydrogen to render the 

primary containment atmosphere non-flammable by 

maintaining the oxygen content below 4% by volume 

during normal operation.

Diesel Exhaust Gases, fluids, and particulates present in diesel engine 

exhaust.

Fuel oil Diesel oil, No. 2 oil, or other liquid hydrocarbons used to 

fuel diesel engines. Fuel oil is used for combustion 

engines with possible water contamination. 
September 2005 IX-17 NUREG-1801, Rev. 1

IX.D Selected Definitions & Use of Terms for Describing and Standardizing

ENVIRONMENTS

Term Definition as used in this document

Gas Internal gas environments from dry air, inert or nonreactive gases. As used in GALL’05 AMR line-items, this 

generic term, standing on its own, is used only in 

“Common Miscellaneous Material/Environment” sections 

where aging effects are not expected to degrade the ability 

of the structure of component to perform its intended 

function for the extended period of operation. In such 

“none-none” AMR line-items, no AMPs are required. 

In the context of GALL’05, this term “gas” subsequently is 

not meant to envelope gases in the fire suppression 

system. The GALL AMP XI.M26 “Fire Protection” is used 

for the periodic inspection and test of the halon/carbon 

dioxide fire suppression system.

Groundwater/soil Groundwater is the water beneath the surface that can be 

collected with wells, tunnels, or drainage galleries, or that 

flows naturally to the earth's surface via seeps or springs. 

Soil is a mixture of inorganic materials produced by the 

weathering of rocks and clays, and organic material 

produced by the decomposition of vegetation. Voids 

containing air and moisture occupy ~50% of the soil 

volume. Concrete subjected to a groundwater/soil 

environment can be vulnerable to Increase in porosity and 

permeability, cracking, loss of material (spalling, scaling)/ 

aggressive chemical attack.

Lubricating oil Lubricating oils are low-to-medium viscosity 

hydrocarbons, with the possibility of containing 

contaminants and/or moisture, used for bearing, gear, 

and engine lubrication. The GALL AMP XI.M39 

“Lubricating Oil Monitoring” addresses this environment. 

Piping, piping components, and piping elements, whether 

copper, stainless steel, or steel, when exposed to 

lubricating oil that does not have water pooling, will have 

limited susceptibility to aging degradation, due to general 

or localized corrosion.
NUREG-1801, Rev. 1 IX-18 September 2005

IX.D Selected Definitions & Use of Terms for Describing and Standardizing

ENVIRONMENTS

Term Definition as used in this document

Raw water Raw, untreated fresh, salt, or ground water. Floor drains 

and reactor buildings and auxiliary building sumps may be 

exposed to a variety of untreated water that is thus 

classified as raw water, for the determination of aging 

effects.

Raw water may contain contaminants, including oil and 

boric acid, depending on the location, as well as originally 

treated water that is not monitored by a chemistry 

program. 

Reactor coolant Water in the reactor coolant system and connected 

systems at or near full operating temperature; includes 

steam for BWRs. 

Reactor coolant >250°C 

(>482°F)

Treated water above thermal embrittlement threshold for 

CASS. 

Reactor coolant >250°C 

(>482°F) and neutron 

flux

Water in the reactor coolant system and connected 

systems above thermal embrittlement threshold for CASS. 

Reactor coolant and high 

fluence (>1 x 1021 n/cm2

E >0.1 MeV)

Reactor coolant environment with a high fluence (>1 x 1021

n/cm2 E >0.1 MeV). 

Reactor coolant and 

neutron flux

Reactor core environment that will result in a neutron 

fluence exceeding 1017 n/cm2 (E >1 MeV) at the end of the 

license renewal term. 

Reactor coolant and 

secondary 

feedwater/steam

Water in the reactor coolant system and connected 

systems at or near full operating temperature and the 

PWR feedwater or steam at or near full operating 

temperature, subject to the secondary water chemistry 

program. 

Secondary feedwater Within the context of the recirculating steam generator, 

components such as steam generator feedwater

impingement plate and support may be subjected to loss 

of material due to erosion in a secondary feedwater 

environment. More generally, the environment of concern 

is a secondary feedwater/steam combination.

Secondary 

feedwater/steam

PWR feedwater or steam at or near full operating 

temperature, subject to the secondary water chemistry 

program. 

Sodium pentaborate 

solution

Treated water that contains a mixture of borax and boric 

acid.
September 2005 IX-19 NUREG-1801, Rev. 1

IX.D Selected Definitions & Use of Terms for Describing and Standardizing

ENVIRONMENTS

Term Definition as used in this document

Soil Mixture of inorganic materials produced by the weathering 

of rocks and clays, and organic material produced by the 

decomposition of vegetation. Voids containing air and 

moisture occupy ~50% of the soil volume. Properties of 

soil that can affect degradation kinetics include water 

content, pH, ion exchange capacity, density, and 

permeability. External environment for components 

exposed to soil (including the air/soil interface) or buried 

in the soil, including groundwater in the soil. 

Steam Steam, subject to BWR water chemistry program or PWR 

secondary plant water chemistry program. Defining 

temperature of steam is not considered necessary for 

analysis.

System temperature up 

to 288°C (550°F)

Metal temperature of BWR components <288°C (550°F).

System temperature up 

to 340°C (644°F)

Maximum metal temperature <340°C (644°F).

Treated borated water Borated (PWR) water is a controlled water system. 

Referred to elsewhere as borated (PWR) water

Treated borated water 

>250°C (>482°F)

Treated water with boric acid above thermal embrittlement 

threshold for cast austenitic stainless steel of 250°C 

(>482°F). 

Treated borated water 

>60°C (>140°F)

Treated water with boric acid in PWR systems above the 

SCC threshold for stainless steel of 60°C (>140°F).

Treated water Treated water is demineralized water, which is the base 

water for all clean systems. Depending on the system, this 

demineralized water may require additional processing. 

Treated water could be deaerated and include corrosion 

inhibitors, biocides, or some combination of these 

treatments. Unlike the PWR reactor coolant environment 

(treated borated water), the BWR reactor coolant 

environment (i.e., treated water) does not contain boron, a 

recognized corrosion inhibitor. 

Treated water >60°C 

(>140°F)

Treated water above 60°C stress corrosion cracking

threshold for stainless steel.

Water-flowing Water that is refreshed, thus having larger impact on 

leaching; this can be rainwater, raw water, groundwater, or 

flowing water under a foundation.
NUREG-1801, Rev. 1 IX-20 September 2005

IX.D Selected Definitions & Use of Terms for Describing and Standardizing

ENVIRONMENTS

Term Definition as used in this document

Water-standing Water that is stagnant and unrefreshed, thus possibly 

resulting in an increased ionic strength of solution up to 

saturation.
September 2005 IX-21 NUREG-1801, Rev. 1

E. Aging Effects

The following table defines many of the standardized aging effects descriptors used in 

the preceding GALL AMR tables in Chapters II, III, IV, V, VI, VII, and VIII of GALL’05. A 

complete listing of the aging effects, the correlation to the designations in GALL’01, and 

their locations is found in Appendix A of the Technical Bases for Revision to the License 

Renewal Guidance Documents (Bases Document, NUREG-1833) accompanying the 

2005 revision of the license renewal guidance documents.

IX.E Selected Definitions & Use of Terms for Describing and Standardizing

AGING EFFECTS

Term Definition as used in this document

Changes in dimensions Changes in dimension can result from void swelling.

Concrete cracking and 

spalling

Concrete cracking and spalling can result from freezethaw, aggressive chemical attack, and reaction with 

aggregates.

Corrosion of connector 

contact surfaces

Corrosion of exposed connector contact surfaces can be 

caused by borated water intrusion.

Crack growth Increase in crack size, attributable to cyclic loading. 

Cracking This term is used in this document to be synonymous 

with the phrase “crack initiation and growth” in metallic 

substrates. 

Cracking in concrete can be caused by restraint 

shrinkage, creep, and aggressive environment.

Cracking, loss of bond, 

and loss of material 

(spalling, scaling)

Cracking, loss of bond, and loss of material (spalling, 

scaling) can be caused by corrosion of embedded steel 

in concrete.

Cracks; distortion; 

increase in component 

stress level

Within concrete structures, cracks, distortion, and 

increase in component stress level can be caused by 

settlement. Although settlement can be occur in a soil 

environment, the symptoms can be manifested in either 

an air-indoor uncontrolled or air-outdoor environment.

Cumulative fatigue 

damage

Cumulative fatigue damage is due to fatigue, as defined 

by ASME Boiler and Pressure Vessel Code.
NUREG-1801, Rev. 1 IX-22 September 2005

IX.E Selected Definitions & Use of Terms for Describing and Standardizing

AGING EFFECTS

Term Definition as used in this document

Degradation of insulator

quality

The decrease in insulating capacity can result from the 

presence of salt deposits or surface contamination. 

Although this derives from an aging mechanism 

(presence of salt deposits or surface contamination as 

noted in LP-07) that may be due to temporary, transient 

environmental conditions, the net result may be longlasting and cumulative.

Denting Denting in steam generators can result from corrosion of 

carbon steel tube support plates.

Embrittlement, cracking, 

melting, discoloration, 

swelling, or loss of 

dielectric strength 

leading to reduced 

insulation resistance; 

electrical failure

Embrittlement, cracking, melting, discoloration, swelling, 

or loss of dielectric strength leading to reduced insulation 

resistance, electrical failure can result from mechanisms 

such as thermal or thermoxidative degradation of 

organics; radiation-induced oxidation, radiolysis and 

photolysis (UV sensitive materials only) of organics; 

moisture intrusion; and ohmic heating.

Expansion and cracking Within concrete structures, expansion and cracking can 

result from reaction with aggregates. 

Fatigue Fatigue in copper fuse holder clamps can result from 

ohmic heating, thermal cycling, electrical transients, 

frequent manipulation, vibration, chemical 

contamination, corrosion, oxidation. [9]

Fretting or lockup Fretting is an aging effect due to accelerated 

deterioration at the interface between contacting 

surfaces as the result of corrosion and slight oscillatory 

movement between the two surfaces. In essence, both 

fretting and lockup are due to mechanical wear.

Hardening and loss of 

strength 

Hardening and loss of strength can result from elastomer 

degradation of seals and other elastomeric components. 

Elastomers can experience increased hardness, 

shrinkage, and loss of strength, due to weathering.

Increase in porosity and 

permeability, cracking, 

loss of material (spalling, 

scaling), loss of strength

Concrete can increase in porosity and permeability, 

cracking, loss of material (spalling, scaling) due to 

aggressive chemical attack. In concrete, loss of material

(spalling, scaling) and cracking can result from freezethaw processes. Loss of strength can result from 

leaching of calcium hydroxide in the concrete.

Increased resistance of 

connection

Increased resistance of connection in electrical 

transmission conductors and connections can be caused 

by oxidation or loss of preload. 
September 2005 IX-23 NUREG-1801, Rev. 1

IX.E Selected Definitions & Use of Terms for Describing and Standardizing

AGING EFFECTS

Term Definition as used in this document

Ligament cracking Steel tube support plates can experience ligament 

cracking due to corrosion.

Localized damage and 

breakdown of insulation 

leading to electrical 

failure 

Localized damage in polymeric electrical conductor 

insulation leading to electrical failure can be due to a 

number of aging mechanisms including moisture 

intrusion, and the formation of water trees. Based on 

operating experience, localized damage and breakdown 

of insulation may be exacerbated by manufacturing 

defects in the insulation of older electrical conductors, 

external damage, or damage due to poor installation 

practices.

Loosening of bolted 

connections

The loosening of bolted bus duct connections due to 

thermal cycling can result from ohmic heating. [10, 11]

Loss of fracture 

toughness

Loss of fracture toughness can result from various aging 

mechanisms including thermal aging, thermal aging 

embrittlement, and neutron irradiation embrittlement. 

Loss of leak tightness Steel airlocks can experience loss of leak tightness in 

closed position resulting from mechanical wear of locks, 

hinges, and closure mechanisms.

Loss of material Loss of material may be due to general corrosion, boric 

acid corrosion, pitting corrosion, galvanic corrosion, 

crevice corrosion, erosion, fretting, flow-accelerated 

corrosion, MIC, fouling, selective leaching, wastage, 

wear, and aggressive chemical attack. In concrete 

structures, loss of material can also be caused by 

abrasion or cavitation or corrosion of embedded steel. 

For high voltage insulators, loss of material can be 

attributed to mechanical wear or wind-induced abrasion 

and fatigue due to wind blowing on transmission 

conductors. [10]

Loss of material, loss of 

form

In earthen water-control structures, the loss of material 

and loss of form can result from erosion, settlement, 

sedimentation, frost action, waves, currents, surface 

runoff, and seepage.
NUREG-1801, Rev. 1 IX-24 September 2005

IX.E Selected Definitions & Use of Terms for Describing and Standardizing

AGING EFFECTS

Term Definition as used in this document

Loss of mechanical 

function

Loss of mechanical function in Class 1 piping and 

components (such as constant and variable load spring 

hangers, guides, stops, sliding surfaces, and vibration 

isolators) fabricated from steel or other materials, such 

as Lubrite® can occur through the combined influence of 

a number of aging mechanisms. Such aging 

mechanisms can include corrosion, distortion, dirt, 

overload, fatigue due to vibratory and cyclic thermal 

loads, or elastomer hardening. Clearances being less 

than the design requirements can also contribute to loss 

of mechanical function.

Loss of preload Loss of preload due to gasket creep, thermal effects 

(including differential expansion and creep or stress 

relaxation), and self-loosening (which includes vibration, 

joint flexing, cyclic shear loads, thermal cycles) is an 

aging effect/mechanism accepted by industry as being 

within the scope of license renewal. [11,12]

Loss of prestress Loss of prestress in structural steel anchorage 

components can result from relaxation, shrinkage, creep, 

or elevated temperatures.

Loss of sealing; leakage 

through containment

Loss of sealing and leakage through containment in 

such materials as seals, elastomers, rubber, and other 

similar materials can result from deterioration of seals, 

gaskets, and moisture barriers (caulking, flashing, and 

other sealants). Loss of seal in elastomeric phase bus 

enclosure assemblies can result from moisture intrusion.

None Certain materials may, in certain environments, be 

subject to no significant aging mechanisms and thus 

there are also no relevant aging effects that require 

management.

Reduction in concrete 

anchor capacity due to 

local concrete 

degradation

Reduction in concrete anchor capacity due to local 

concrete degradation can result from a service-induced 

cracking or other concrete aging mechanisms.

Reduction in foundation 

strength, cracking, 

differential settlement

Reduction in foundation strength, cracking, and 

differential settlement can result from erosion of porous 

concrete subfoundation.
September 2005 IX-25 NUREG-1801, Rev. 1

IX.E Selected Definitions & Use of Terms for Describing and Standardizing

AGING EFFECTS

Term Definition as used in this document

Reduction of heat 

transfer

Reduction of heat transfer from fouling by the buildup,

from whatever source, on the heat transfer surface. 

Although in heat exchangers, the tubes are the primary 

heat transfer component, heat exchanger internals 

including tubesheets and fins contribute to heat transfer 

and may be affected by the reduction of heat transfer 

due to fouling. Although GALL’05 does not include 

reduction of heat transfer for any heat exchanger 

surfaces other than tubes, reduction in heat transfer is of 

concern for other heat exchanger surfaces.

Reduction of neutronabsorbing capacityReduction of neutron-absorbing capacity can result from 

Boraflex degradation.

Reduction of strength 

and modulus

In concrete, reduction of strength and modulus can be 

attributed to elevated temperatures (>150°F general; 

>200°F local).

Reduction or loss of 

isolation function 

Reduction or loss of isolation function in polymeric 

vibration isolation elements can result from elastomers 

exposed to radiation hardening, temperature, humidity, 

sustained vibratory loading.

Wall thinning This is the term used to describe the specific type of loss 

of material due to flow-accelerated corrosion. 
NUREG-1801, Rev. 1 IX-26 September 2005

F. Significant Aging Mechanisms

An aging mechanism is considered to be significant when it may result in aging effects 

that produce a loss of functionality of a component or structure during the current or 

license renewal period, if allowed to continue without mitigation. 

The following table defines many of the standardized aging mechanism descriptors used

in the preceding GALL AMR tables in Chapters II, III, IV, V, VI, VII, and VIII, of GALL’05. 

A complete listing of the aging mechanisms, the correlation to the designations in 

GALL’01, and their locations is found in Appendix A of the Bases Document, NUREG1833, accompanying the 2005 revision of the license renewal guidance documents.

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Abrasion As water migrates over a concrete surface, it may 

transport material that can abrade the concrete. The 

passage of water may also create a negative pressure at 

the water/air to concrete interface that can result in 

abrasion and cavitation degradation of the concrete. This 

may result in pitting or aggregate exposure due to loss of 

cement paste. [13]

Aggressive chemical 

attack

Concrete, being highly alkaline (pH >12.5) is degraded by 

strong acids. Chlorides and sulfates of potassium, sodium, 

and magnesium may attack concrete, depending 

concentration in soil/ground water. Exposed surfaces of 

Class 1 structures may be subject to sulfur-based acid-rain 

degradation. Minimum degradation thresholds are 500 

ppm chlorides and 1500 ppm sulfates. [13]

Boraflex Degradation Boraflex degradation may involve gamma radiationinduced shrinkage of Boraflex and the potential to develop 

tears or gaps in the material. A more significant potential 

degradation is the gradual release of silica and the 

depletion of boron carbide from Boraflex, following gamma 

irradiation and long-term exposure to the wet pool 

environment. The loss of boron carbide from Boraflex is 

characterized by slow dissolution of the Boraflex matrix 

from the surface of the Boraflex and a gradual thinning of 

the material.

The boron carbide loss can result in a significant increase 

in the reactivity within the storage racks. An additional 

consideration is the potential for silica transfer through the 

fuel transfer canal into the reactor core during refueling 

operations and its effect on the fuel clad heat transfer 

capability. [14]
September 2005 IX-27 NUREG-1801, Rev. 1

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Borated Water Intrusion Influx of borated water.

Boric acid corrosion Corrosion by boric acid, which can occur where there is 

borated water leakage in an environment described as air 

with borated water leakage. See also Corrosion.

Cavitation Formation and instantaneous collapse of innumerable tiny 

voids or cavities within a liquid subjected to rapid and 

intense pressure changes. Cavitation caused by severe 

turbulent flow can potentially lead to cavitation damage.

Chemical contamination Degradation due to presence of chemical constituents.

Cladding breach This refers to the aging mechanisms comprising breach of 

the stainless steel cladding via any applicable process. 

Unique problems with stainless cladding have been 

identified for HHSI pumps as discussed in NRC 

Information Notice 94-63, “Boric Acid Corrosion of 

Charging Pump Casings Caused by Cladding Cracks.”

In GALL’05, it is only used in new AMR line-items in the 

Engineered Safety Features (EP-49) and Auxiliary 

System (VII AP-85) to describe the loss of material in 

PWR emergency core cooling system pump casing 

constructed of steel with stainless steel cladding (EP-49) 

and the PWR chemical & volume control system pump 

casing constructed of steel with stainless steel cladding 

(AP-85).

Cladding degradation This refers to the degradation of the stainless via any 

applicable degradation process. 

In GALL’05, it is only used in VII A-40 to describe the loss 

of material due to pitting and crevice corrosion (only for 

steel after lining/cladding degradation) of piping, piping 

components, and piping elements fabricated from steel,

with elastomer lining or stainless steel cladding.

Corrosion Chemical or electrochemical reaction between a material, 

usually a metal, and its environment that produces a 

deterioration of the material and its properties.

Corrosion of carbon steel 

tube support plate

Corrosion (as defined above) of the carbon steel tube 

support plates, which are plate-type components providing 

tube to tube mechanical support for the tubes in the tube 

bundle of the steam generator (recirculating) system of a 

PWR. The tubes pass through drilled holes in the plate. 

The secondary coolant flows through the tube supports via 

flow holes between the tubes. [15, 16]
NUREG-1801, Rev. 1 IX-28 September 2005

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Corrosion of embedded 

steel

If pH of the concrete in which steel is embedded is 

reduced (pH < 11.5) by intrusion of aggressive ions (e.g., 

chlorides > 500 ppm) in the presence of oxygen, 

embedded steel corrosion may occur. A reduction in pH 

may be caused by the leaching of alkaline products 

through cracks, entry of acidic materials, or carbonation. 

Chlorides may also be present in the constituents of the 

original concrete mix. The severity of the corrosion is 

affected by the properties and types of cement, 

aggregates, and moisture content. [17]

Creep Creep, for a metallic material, refers to a time-dependent 

continuous deformation process under constant stress. It 

is an elevated temperature process and is not a concern 

for low alloy steel below 700°F, for austenitic alloys below 

1000°F, and for Ni-based alloys below 1800°F. [18, 19]

Creep, in concrete, is related to the loss of absorbed water 

from the hydrated cement paste. It is a function of modulus 

of elasticity of the aggregate. It may result in loss of 

prestress in the tendons used in prestressed concrete 

containment. [15]

Crevice Corrosion Localized corrosion of a metal surface at, or immediately 

adjacent to, an area that is shielded from full exposure to 

the environment, because of close proximity between the 

metal and the surface of another material. Crevice 

corrosion occurs in a wetted or buried environment when a 

crevice or area of stagnant or low flow exists that allows a 

corrosive environment to develop in a component. It 

occurs most frequently in joints and connections, or points 

of contact between metals and non-metals, such as gasket 

surfaces, lap joints, and under bolt heads. Carbon steel, 

cast iron, low alloy steels, stainless steel, copper, and 

nickel base alloys are all susceptible to crevice corrosion. 

Steel can be subject to crevice corrosion in some cases 

after lining/cladding degradation.

Cyclic loading One source of cyclic loading is due to periodic application 

of pressure loads and forces due to thermal movement of 

piping transmitted through penetrations and structures to 

which penetrations are connected. The typical result of 

cyclic loads on metal components is fatigue cracking and 

failure; however, the cyclic loads may also cause 

deformation that results in functional failure.
September 2005 IX-29 NUREG-1801, Rev. 1

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Deterioration of seals, 

gaskets, and moisture 

barriers (caulking, 

flashing, and other 

sealants)

Seals, gaskets, and moisture barriers (caulking, flashing, 

and other sealants) are subject to loss of sealing and 

leakage through containment caused by aging 

degradation of these components. 

Distortion The aging mechanism of distortion can be caused by timedependent strain, or gradual elastic and plastic 

deformation of metal that is under constant stress at a 

value lower than its normal yield strength.

Elastomer degradation Elastomer materials are substances whose elastic 

properties are similar to that of natural rubber. The term 

elastomer is sometimes used to technically distinguish 

synthetic rubbers and rubber-like plastics from natural 

rubber. Degradation may include cracking, crazing, fatigue 

breakdown, abrasion, chemical attacks, and weathering. 

[20, 21] Elastomer hardening refers to the degradation in 

elastic properties of the elastomer.

Electrical transients An electrical transient is a stressor caused by a voltage 

spike that can contribute to aging degradation. Certain 

types of high-energy electrical transients can contribute to 

electromechanical forces ultimately resulting in fatigue or 

loosening of bolted connections. Transient voltage surges 

are a major contributor to the early failure of sensitive 

electrical components

Elevated temperature In concrete, reduction of strength and modulus can be 

attributed to elevated temperatures (>150°F general; 

>200°F local).

Erosion Progressive loss of material from a solid surface due to 

mechanical interaction between that surface and a fluid, a 

multicomponent fluid, or solid particles carried with the 

fluid.

Erosion settlement Erosion (as defined above). Settlement of containment 

structure may occur during the design life due to changes 

in the site conditions, e.g., due to erosion or changes in 

the water table. The amount of settlement depends on the 

foundation material, and is generally determined by 

survey. [17] Another term is erosion of the porous concrete 

subfoundation.

Erosion, settlement, 

sedimentation, frost 

action, waves, currents, 

surface runoff, seepage

In earthen water-control structures, the loss of material 

and loss of form can result from erosion, settlement, 

sedimentation, frost action, waves, currents, surface 

runoff, and seepage.
NUREG-1801, Rev. 1 IX-30 September 2005

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Fatigue A phenomenon leading to fracture under repeated or 

fluctuating stresses having a maximum value less than the 

tensile strength of the material. Fatigue fractures are 

progressive, and grow under the action of the fluctuating 

stress. Fatigue due to vibratory and cyclic thermal loads is 

defined as the structural degradation that can occur as a 

result of repeated stress/strain cycles caused by 

fluctuating loads, e.g., from vibratory loads, and 

temperatures, giving rise to thermal loads. After repeated 

cyclic loading of sufficient magnitude, microstructural 

damage may accumulate, leading to macroscopic crack 

initiation at the most vulnerable regions. Subsequent 

mechanical or thermal cyclic loading may lead to growth of 

the initiated crack. Vibration may result in component 

cyclic fatigue, as well as in cutting, wear, and abrasion, if 

left unabated. Vibration is generally induced by external 

equipment operation. It may also result from flow 

resonance or movement of pumps or valves in fluid 

systems.

Crack initiation and growth resistance is governed by 

factors including stress range, mean stress, loading 

frequency, surface condition, and the presence of 

deleterious chemical species. [23]

Flow-accelerated 

corrosion (FAC)

Also termed erosion-corrosion. A co-joint activity involving 

corrosion and erosion in the presence of a moving 

corrosive fluid, leading to the accelerated loss of material. 

Susceptibility may be determined using the review process 

outlined in Section 4.2 of NSAC-202L-R2

recommendations for an effective FAC program. [22]
September 2005 IX-31 NUREG-1801, Rev. 1

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Fouling An accumulation of deposits. This term includes 

accumulation and growth of aquatic organisms on a 

submerged metal surface and also includes the 

accumulation of deposits, usually inorganic, on heat 

exchanger tubing. Biofouling, as a subset of fouling, can 

be caused by either macro-organisms (such as barnacles, 

Asian clams, zebra mussels, and others found in fresh and 

salt water) or micro-organisms, e.g., algae. 

Fouling can also be categorized as particulate fouling 

(sediment, silt, dust, and corrosion products), marine 

biofouling, or macrofouling, e.g., peeled coatings, debris, 

etc. Fouling in a raw water system can occur on the piping, 

valves, and heat exchangers. Fouling can result in a 

reduction of heat transfer, loss of material, or a reduction 

in the system flow rate (this last aging effect is considered 

active and thus is not in the purview of license renewal).

Freeze-Thaw, frost 

action

Repeated freezing and thawing is known to be capable of 

causing severe degradation to the concrete characterized 

by scaling, cracking, and spalling. The cause of this 

phenomenon is water freezing within the pores of the 

concrete, creating hydraulic pressure that, if unrelieved, 

will lead to freeze-thaw degradation.

Factors that enhance the resistance of concrete to freezethaw degradation are a) adequate air content (e.g., within 

ranges specified in ACI 301-84), b) low permeability, c) 

protection until adequate strength has developed, and d)

surface coating applied to frequently wet-dry surfaces. [17,

24]

Fretting Aging effect due to accelerated deterioration at the 

interface between contacting surfaces as the result of 

corrosion, and slight oscillatory movement between the 

two surfaces.

Galvanic corrosion Accelerated corrosion of a metal because of an electrical 

contact with a more noble metal or nonmetallic conductor 

in a corrosive electrolyte. Also called bimetallic corrosion, 

contact corrosion, dissimilar metal corrosion, or two-metal 

corrosion. Galvanic corrosion is an applicable aging 

mechanism for steel materials coupled to more noble 

metals in heat exchangers; galvanic corrosion of copper is 

of concern when coupled with the nobler stainless steel.
NUREG-1801, Rev. 1 IX-32 September 2005

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

General corrosion Also known as uniform corrosion, corrosion proceeds at 

approximately the same rate over a metal surface. Loss of 

material due to general corrosion is an aging effect 

requiring management for low alloy steel, carbon steel, 

and cast iron in outdoor environments. 

Some potential for pitting and crevice corrosion may exist 

even when pitting and crevice is not explicitly listed in the 

aging effects/aging mechanism column in GALL’05 AMR 

line-items and when the descriptor may only be loss of 

material due to general corrosion. For example, the new 

AMP XI.M36 “External Surfaces Monitoring” inspects for 

general corrosion of steel and manages aging effects 

through visual inspection of external surfaces for evidence 

of material loss and leakage. It acts as a de facto 

screening for pitting and crevice corrosion, since the 

symptoms of general corrosion will be first noticed. 

Wastage is thinning of component walls due to general 

corrosion.

Intergranular attack (IGA) In austenitic stainless steels, the precipitation of chromium

carbides, usually at grain boundaries, on exposure to 

temperatures of about 550-850°C, leaving the grain 

boundaries depleted of Cr and therefore susceptible to 

preferential attack (intergranular attack) by a corroding 

(oxidizing) medium.

Intergranular stress 

corrosion cracking 

(IGSCC)

SCC in which the cracking occurs along grain boundaries.

Irradiation-assisted 

stress corrosion cracking 

(IASCC)

Failure by intergranular cracking in aqueous environments 

of stressed materials exposed to ionizing radiation has 

been termed irradiation-assisted stress corrosion cracking 

(IASCC). Irradiation by high-energy neutrons can promote 

SCC by affecting material microchemistry (e.g., radiationinduced segregation of elements such as P, S, Si, and Ni 

to the grain boundaries), material composition and 

microstructure (e.g., radiation hardening), as well as water 

chemistry (e.g., radiolysis of the reactor water to make it 

more aggressive).
September 2005 IX-33 NUREG-1801, Rev. 1

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Leaching of calcium 

hydroxide

Water passing through cracks, inadequately prepared 

construction joints, or areas that are not sufficiently 

consolidated during placing may dissolve some calciumcontaining products, of which calcium hydroxide is the 

most-readily soluble, in concrete. Once the calcium 

hydroxide has been leached away, other cementatious 

constituents become vulnerable to chemical 

decomposition, finally leaving only the silica and alumina 

gels behind with little strength. The water's 

aggressiveness in the leaching of calcium hydroxide 

depends on its salt content and temperature. This leaching 

action is effective only if the water passes through the 

concrete. [17]

Mechanical loading Applied loads of mechanical origins rather than from other 

sources, such as thermal. 

Mechanical wear See “wear”

Microbiologicallyinfluenced corrosion 

(MIC)

Any of the various forms of corrosion influenced by the 

presence and activities of such microorganisms as 

bacteria, fungi, and algae, and/or the products produced in 

their metabolism. Degradation of material that is 

accelerated due to conditions under a biofilm or 

microfouling tubercle, for example, anaerobic bacteria that 

can set up an electrochemical galvanic reaction or 

inactivate a passive protective film, or acid-producing 

bacterial that might produce corrosive metabolites.

Moisture intrusion Influx of moisture through any viable process.

Neutron irradiation 

embrittlement

Irradiation by neutrons results in embrittlement of carbon 

and low alloy steels. It may produce changes in 

mechanical properties by increasing tensile and yield 

strengths with a corresponding decrease in fracture 

toughness and ductility. The extent of embrittlement 

depends on neutron fluence, temperature, and trace 

material chemistry. [19]

Ohmic heating Ohmic heating is induced by current flow through a 

conductor and can be calculated using first principles of 

electricity and heat transfer. Ohmic heating is a thermal 

stressor and can be induced in situations, such as 

conductors passing through electrical penetrations. Ohmic 

heating is especially significant for power circuit 

penetrations. [10]
NUREG-1801, Rev. 1 IX-34 September 2005

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Outer diameter stress 

corrosion cracking 

(ODSCC)

SCC initiating in the outer diameter (secondary side) 

surface of steam generator tubes. This differs from 

PWSCC, which describes inner diameter (primary side) 

initiated cracking. [16]

Overload Overload is one of the aging mechanisms that can cause 

loss of mechanical function in Class 1 piping and 

components, such as constant and variable load spring 

hangers, guides, stops, sliding surfaces, design 

clearances, vibration isolators, fabricated from steel or 

other materials, such as Lubrite®.

Oxidation Two types of reactions a) reaction in which there is an 

increase in valence resulting from a loss of electrons, or b) 

a corrosion reaction in which the corroded metal forms an 

oxide. [20]

Photolysis Chemical reactions induced or assisted by light.

Pitting corrosion Localized corrosion of a metal surface, confined to a point 

or small area, which takes the form of cavities called pits.

Plastic deformation Time-dependent strain, or gradual elastic and plastic 

deformation, of metal that is under constant stress at a 

value lower than its normal yield strength.

Presence of any salt 

deposits

The surface contamination resulting from the aggressive 

environment associated with the presence of any salt 

deposits can be an aging mechanism causing the aging 

effect of degradation of insulator quality. Although this 

aging mechanism may be due to temporary, transient 

environmental conditions, the net result may be longlasting and cumulative for plants located in the vicinity of 

saltwater bodies.

Primary water stress 

corrosion cracking 

(PWSCC)

PWSCC is an intergranular cracking mechanism that

requires the presence of high applied and/or residual 

stress, susceptible tubing microstructures (few 

intergranular carbides), and high temperature. For 

conditions of concern in context of license renewal, this 

aging mechanism is most likely for nickel alloys in PWR 

environment. [15]

Radiation hardening, 

temperature, humidity, 

sustained vibratory 

loading.

Reduction or loss of isolation function in polymeric 

vibration isolation elements can result from a combination 

of radiation hardening, temperature, humidity, and

sustained vibratory loading.
September 2005 IX-35 NUREG-1801, Rev. 1

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Radiation-induced 

oxidation

Two types of reactions that are affected by radiation a) 

reaction in which there is an increase in valence resulting 

from a loss of electrons, or b) a corrosion reaction in which 

the corroded metal forms an oxide. This is a very limited 

form of oxidation and is referenced in LP-05 for MEB 

insulation. [20]

Radiolysis Chemical reactions induced or assisted by radiation. 

Radiolysis and photolysis aging mechanisms can occur in 

UV-sensitive organic materials.

Reaction with aggregate The presence of reactive alkalis in concrete, can lead to 

subsequent reactions with aggregates that may be 

present. These alkalis are introduced mainly by cement, 

but also may come from admixtures, salt-contamination, 

seawater penetration, or solutions of deicing salts. These 

reactions include alkali-silica reactions, cement-aggregate 

reactions, and aggregate-carbonate reactions. These 

reactions may lead to expansion and cracking. [13]

Restraint shrinkage Restraint shrinkage can cause cracking in concrete 

transverse to the longitudinal construction joint.

Selective leaching Also known as dealloying, e.g., dezincification or graphitic 

corrosion. Selective corrosion of one or more components 

of a solid solution alloy.

Service-induced cracking 

or other concrete aging 

mechanisms

Cracking of concrete under load over time of service, e.g., 

from shrinkage or creep, or other concrete aging 

mechanisms which may include freeze-thaw, leaching, 

aggressive chemicals, reaction with aggregates, corrosion 

of embedded steels, elevated temperatures, irradiation, 

abrasion and cavitations. [13]

Settlement Settlement of containment structure may occur during the 

design life due to changes in the site conditions, e.g., the 

water table. The amount of settlement depends on the 

foundation material and is generally determined by survey. 

[16]

Stress corrosion cracking 

(SCC)

Cracking of a metal produced by the combined action of 

corrosion and tensile stress (applied or residual).
NUREG-1801, Rev. 1 IX-36 September 2005

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Stress relaxation Many of the bolts in reactor internals are stressed to a cold 

initial preload. When subject to high operating 

temperatures, over time, these bolts may loosen and the 

preload may be lost. Radiation can also cause stress 

relaxation, in highly stressed members such as bolts. [15]

Relaxation in structural steel anchorage components can 

be an aging mechanism contributing to the aging effect of 

loss of prestress.

Surface contamination Contamination of the surfaces by corrosive constituents.

Sustained vibratory 

loading

Vibratory loading over time.

Thermal aging 

embrittlement

Also termed thermal aging or thermal embrittlement. At 

operating temperatures of 500 to 650°F, cast austenitic 

stainless steels (CASS) exhibit a spinoidal decomposition 

of the ferrite phase into ferrite-rich and chromium-rich 

phases. This may give rise to significant embrittlement, 

i.e., reduction in fracture toughness, depending on the 

amount, morphology, and distribution of the ferrite phase 

and the composition of the steel.

Thermal aging of materials other than CASS is a time- and 

temperature-dependent degradation mechanism that 

decreases material toughness. It includes temper 

embrittlement and strain aging embrittlement. Ferritic and 

low alloy steels are subject to both of these embrittlement, 

but wrought stainless steel is not affected by either of the 

processes. [19]

Thermal effects, gasket 

creep, and self-loosening

Loss of preload due to gasket creep, thermal effects 

(including differential expansion and creep or stress 

relaxation), and self-loosening (which includes vibration, 

joint flexing, cyclic shear loads, thermal cycles) is within 

the scope of license renewal. [11,12]

Thermal and mechanical 

loading

Loads (stress) due to mechanical or thermal (temperature) 

sources.
September 2005 IX-37 NUREG-1801, Rev. 1

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Thermal degradation of 

organic materials

This category includes both short-term thermal 

degradation and long-term thermal degradation. Thermal 

energy absorbed by polymers can result in crosslinking 

and chain scission. Crosslinking will generally result in 

such aging effects as increased tensile strength and 

hardening of material, with some loss of flexibility and 

eventual decrease in elongation-at-break and increased 

compression set. Scission generally reduces tensile 

strength. Other reactions that may occur include 

crystallization and chain depolymerization. 

Thermal fatigue Thermal (temperature) fatigue can result from phenomena 

such as thermal loading, thermal cycling, where there is 

cycling of the thermal loads and thermal stratification and 

turbulent penetration. Thermal stratification is a thermohydraulic condition with definitive hot and cold water 

boundary inducing thermal fatigue of the piping. Turbulent 

penetration is a thermo-hydraulic condition where hot and 

cold water mix as a result of turbulent flow conditions,

leading to thermal fatigue of the piping. The GALL AMP

XI.M32 "One-Time Inspection" inspects for cracking 

induced by thermal stratification, and for turbulent 

penetration via volumetric (RT or UT) techniques.

Thermoxidative 

degradation of 

organics/thermoplastics

Degradation of organics/thermoplastics via oxidation 

reactions (loss of electrons by a constituent of a chemical 

reaction) and thermal means. See Thermal degradation of 

organic materials. [18]

Void swelling Vacancies created in reactor (metallic) materials as a 

result of irradiation may accumulate into voids that may, in 

turn lead to dimensional changes (swelling) of the 

material. Void swelling may occur after an extended 

incubation period.

Water trees Water trees occur when the insulating materials are 

exposed to long-term, continuous electrical stress and 

moisture; these trees eventually result in breakdown of the 

dielectric and ultimate failure. The growth and propagation 

of water trees is somewhat unpredictable. Water treeing is 

a degradation and long-term failure phenomenon. 
NUREG-1801, Rev. 1 IX-38 September 2005

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Wear Wear is defined as the removal of surface layers due to 

relative motion between two surfaces or under the 

influence of hard abrasive particles. Wear occurs in parts 

that experience intermittent relative motion, frequent 

manipulation, or in clamped joints where relative motion is 

not intended but may occur due to a loss of the clamping 

force. [19] 

Weathering Degradation of external surfaces of materials when 

exposed to outside environment.

Wind-induced abrasion See abrasion. The carrier of abrading particles is wind 

rather than water/liquids.
September 2005 IX-39 NUREG-1801, Rev. 1

G. References:

1. SAND 93-7070, “Aging Management Guideline for Commercial Nuclear Power 

Plants-Heat Exchangers,” Sandia National Laboratories, June 1994.

2. ASME Boiler & Pressure Vessel Code, Section II: Part B, Nonferrous Material 

Specifications

3. ASME Boiler & Pressure Vessel Code, Section II: Part A, Ferrous Material 

Specification

4. Gillen and Clough, Rad. Phys. Chem Vol. 18, p. 679, 1981

5. D. Peckner and I. M. Bernstein, Eds., Handbook of Stainless Steels, McGraw-Hill, 

New York, 1977, p. 16-85.

6. Metals Handbook, Ninth Edition, Volume 13, Corrosion, American Society of Metals, 

1987, p. 326

7. O. K. Chopra and A. Sather, “Initial Assessment of the Mechanisms and Significance 

of Low-Temperature Embrittlement of Cast Stainless Steels in LWR Systems,” 

NUREG/CR-5385 (ANL-89/17) Argonne National Laboratory, Argonne, IL (August 

1990).

8. NUREG-1557, “Summary of Technical Information and Agreements from Nuclear 

Management and Resources Council Industry Reports Addressing License 

Renewal,” October 1996.

9. NUREG-1760, “Aging Assessment of Safety-Related Fuses Used in Low- and 

Medium-Voltage Applications in Nuclear Power Plants,” May 2002.

10. SAND96-0344, “Aging Management Guideline for Commercial Nuclear Power 

Plants-Electrical Cable and Terminations,” September 1996.

11. EPRI TR-104213, “Bolted Joint Maintenance & Application Guide,” Electric Power 

Research Institute, Palo Alto, CA, December 1995.

12. EPRI NP-5067, "Good Bolting Practices, A Reference Manual for Nuclear Power 

Plant Maintenance Personnel," volume 1: "Large Bolt Manual," 1987 and volume 2: 

"Small Bolts and Threaded Fasteners," 1990. 

13. NUMARC Report 90-06, Revision 1, December 1991, "Class 1 Structures License 

Renewal Industry Report,” NUMARC, Washington D.C.

14. NRC GL 96-04: “Boraflex Degradation in Spent Fuel Pool Storage Racks,” NRC, 

Rockville, MD, 1996.

15. V. N. Shah and D. E. Macdonald, Eds., "Aging and Life Extension of Major Light 

Water Reactor Components,” Elsevier, Amsterdam, 1993.

16. M. Gavrilas, P. Hejzlar, N.E. Todreas, and Y. Shatilla, "Safety Features of Operating 

Light Water Reactors of Western Designs," CANES, MIT, Cambridge, MA, 2000.

17. NUMARC Report 90-01, Revision 1, Sept 1991, "Pressurized Water Reactors 

Containment Structures License Renewal Industry Report,” NUMARC, Washington 

D.C.
NUREG-1801, Rev. 1 IX-40 September 2005

18. 1976 Annual Book of ASTM Standards, Part 10, ASTM, Philadelphia, PA, 1976.

19. NUMARC Report 90-07, May 1992, "PWR Reactor Coolant System License 

Renewal Industry Report,” NUMARC, Washington D.C.

20. J. R. Davis (Editor) "Corrosion," ASM International, Materials Park, OH, 2000.

21. 2004 Annual Book of ASTM Standards, Volume 09.01, ASTM International, 2004.

22. NUMARC Report 90-05, Revision 1, December 1992, "PWR Reactor Pressure 

Vessel Internals License Renewal Industry Report,” Washington D.C.

23. NSAC-202L-R2, “Recommendations for an Effective Flow Accelerated Corrosion 

Program,” Electric Power Research Institute, Palo Alto, CA, April 8, 1999.

24.ACI 301-84 “Specification for Structural Concrete for Buildings,” (Field Reference 

Manual) American Concrete Institute, Detroit, MI, Revised 1988.

25.ACI 201.2R 77 “Guide to Durable Concrete,” American Concrete Institute, Detroit, 

MI, Reapproved 1982.
September 2005 X-i NUREG-1801, Rev. 1

CHAPTER X

TIME-LIMITED AGING ANALYSES

EVALUATION OF AGING MANAGEMENT PROGRAMS

UNDER 10 CFR 54.21(c)(1)(iii)
NUREG-1801, Rev. 1 X-ii September 2005

This Page Intentionally Left Blank
September 2005 X-iii NUREG-1801, Rev. 1

TIME-LIMITED AGING ANALYSES: EVALUATION OF AGING MANAGEMENT PROGRAMS 

UNDER 10 CFR 54.21(c)(1)(iii)

X.M1 Metal Fatigue of Reactor Coolant Pressure Boundary 

X.S1 Concrete Containment Tendon Prestress 

X.E1 Environmental Qualification (EQ) of Electrical Components 
NUREG-1801, Rev. 1 X-iv September 2005

This Page Intentionally Left Blank
September 2005 X M-1 NUREG-1801, Rev. 1

X.M1 METAL FATIGUE OF REACTOR COOLANT PRESSURE BOUNDARY

Program Description

In order not to exceed the design limit on fatigue usage, the aging management program (AMP) 

monitors and tracks the number of critical thermal and pressure transients for the selected 

reactor coolant system components.

The AMP addresses the effects of the coolant environment on component fatigue life by 

assessing the impact of the reactor coolant environment on a sample of critical components for 

the plant. Examples of critical components are identified in NUREG/CR-6260. The sample of 

critical components can be evaluated by applying environmental life correction factors to the 

existing ASME Code fatigue analyses. Formulae for calculating the environmental life correction 

factors are contained in NUREG/CR-6583 for carbon and low-alloy steels and in NUREG/CR5704 for austenitic stainless steels.

As evaluated below, this is an acceptable option for managing metal fatigue for the reactor 

coolant pressure boundary, considering environmental effects. Thus, no further evaluation is 

recommended for license renewal if the applicant selects this option under 10 CFR 

54.21(c)(1)(iii) to evaluate metal fatigue for the reactor coolant pressure boundary.

Evaluation and Technical Basis

1. Scope of Program: The program includes preventive measures to mitigate fatigue cracking 

of metal components of the reactor coolant pressure boundary caused by anticipated cyclic 

strains in the material.

2. Preventive Actions: Maintaining the fatigue usage factor below the design code limit and 

considering the effect of the reactor water environment, as described under the program 

description, will provide adequate margin against fatigue cracking of reactor coolant system 

components due to anticipated cyclic strains.

3. Parameters Monitored/Inspected: The program monitors all plant transients that cause 

cyclic strains, which are significant contributors to the fatigue usage factor. The number of 

plant transients that cause significant fatigue usage for each critical reactor coolant pressure 

boundary component is to be monitored. Alternatively, more detailed local monitoring of the 

plant transient may be used to compute the actual fatigue usage for each transient.

4. Detection of Aging Effects: The program provides for periodic update of the fatigue usage 

calculations.

5. Monitoring and Trending: The program monitors a sample of high fatigue usage locations. 

This sample is to include the locations identified in NUREG/CR-6260, as minimum, or 

propose alternatives based on plant configuration.

6. Acceptance Criteria: The acceptance criteria involves maintaining the fatigue usage below 

the design code limit considering environmental fatigue effects as described under the 

program description.

7. Corrective Actions: The program provides for corrective actions to prevent the usage 

factor from exceeding the design code limit during the period of extended operation. 
NUREG-1801, Rev. 1 X M-2 September 2005

Acceptable corrective actions include repair of the component, replacement of the 

component, and a more rigorous analysis of the component to demonstrate that the design 

code limit will not be exceeded during the extended period of operation. For programs that 

monitor a sample of high fatigue usage locations, corrective actions include a review of 

additional affected reactor coolant pressure boundary locations. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address the corrective actions.

8. Confirmation Process: Site quality assurance procedures, review and approval processes,

and administrative controls are implemented in accordance with the requirements of 

Appendix B to 10 CFR Part 50. As discussed in the appendix to this report, the staff finds 

the requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: The program reviews industry experience regarding fatigue 

cracking. Applicable experience with fatigue cracking is to be considered in selecting the 

monitored locations.

References

NUREG/CR-5704, Effects of LWR Coolant Environments on Fatigue Design Curves of 

Austenitic Stainless Steels, U.S. Nuclear Regulatory Commission, April 1999.

NUREG/CR-6260, Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear 

Power Plant Components, U.S. Nuclear Regulatory Commission, March 1995.

NUREG/CR-6583, Effects of LWR Coolant Environments on Fatigue Design Curves of Carbon 

and Low-Alloy Steels, U.S. Nuclear Regulatory Commission, March 1998.
NUREG-1801, Rev. 1 X S-2 September 2005

6. Acceptance Criteria: The prestressing force trend lines indicate that existing prestressing 

forces in the containment tendon would not be below the MRVs prior to the next scheduled 

inspection, as required by 10 CFR 50.55a(b)(2)(ix)(B) or 10 CFR 50.55a(b)(2)(viii)(B).

7. Corrective Actions: If acceptance criteria are not met, then either systematic retensioning 

of tendons or a reanalysis of the containment is warranted to ensure the design adequacy of 

the containment. As discussed in the appendix to this report, the staff finds the requirements 

of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions.

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process.

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: The program incorporates the relevant operating experience that 

has occurred at the applicant's plant as well as at other plants. The applicable portions of 

the experience with prestressing systems described in NRC Information Notice 99-10 could 

be useful for the purpose. However, tendon operating experience could be different at plants 

with prestressed concrete containments. The difference could be due to the prestressing 

system design (e.g., button-headed, wedge, or swaged anchorages), environment, and type 

of reactor (i.e., PWR and BWR). Thus, the applicant's plant-specific operating experience 

should be further evaluated for license renewal.

References

ASME Section XI, Rules for In-Service Inspection of Nuclear Power Plant Components, 

Subsection IWL, Requirements for Class CC Concrete Components of Light-Water Cooled 

Plants, 1992 Edition with 1992 Addenda, The ASME Boiler and Pressure Vessel Code, The 

American Society of Mechanical Engineers, New York, NY. 

ASME Section XI, Rules for In-Service Inspection of Nuclear Power Plant Components, 

Subsection IWL, Requirements for Class CC Concrete Components of Light-Water Cooled 

Plants, 1995 Edition with 1996 Addenda, The ASME Boiler and Pressure Vessel Code, The 

American Society of Mechanical Engineers, New York, NY. 

NRC Information Notice 99-10, Degradation of Prestressing Tendon Systems in Prestressed 

Concrete Containments, U. S. Nuclear Regulatory Commission, April 1999.

NRC Regulatory Guide 1.35.1, Determining Prestressing Forces for Inspection of Prestressed 

Concrete Containments, U. S. Nuclear Regulatory Commission, July 1990.
September 2005 X S-1 NUREG-1801, Rev. 1

X.S1 CONCRETE CONTAINMENT TENDON PRESTRESS

Program Description 

In order to ensure the adequacy of prestressing forces in prestressed concrete containment

tendons during the extended period of operation, an applicant shall develop an aging 

management program (AMP) under 10 CFR 54.21(c)(1)(iii).

The AMP consists of an assessment of the results of inspections performed in accordance with 

the requirements of Subsection IWL of the ASME Section XI Code, as supplemented by the 

requirements of 10 CFR 50.55a(b)(2)(ix) or (viii) in the later amendment of the regulation. The 

assessment related to the adequacy of the prestressing force will consist of the establishment of 

(1) acceptance criteria and (2) trend lines. The acceptance criteria will normally consist of

predicted lower limit (PLL) and the minimum required prestressing force, also called minimum 

required value (MRV). NRC Regulatory Guide 1.35.1 provides guidance for calculating PLL and 

MRV. The trend line represents the trend of prestressing forces based on the actual measured 

forces. NRC Information Notice IN 99-10 provides guidance for constructing the trend line. The 

goal is to keep the trend line above the PLL because, as a result of any inspection performed in 

accordance with ASME Section XI, Subsection IWL, if the trend line crosses the PLL, the 

existing prestress in the containment tendon could go below the MRV soon after the inspection 

and would not meet the requirements of 10 CFR 50.55a(b)(2)(ix)(B) or 10 CFR 

50.55a(b)(2)(viii)(B).

As evaluated below, this time limited aging analysis (TLAA) is an acceptable option to manage 

containment tendon prestress force, except for the program element/attribute regarding 

operating experience. Thus, it is recommended that the staff should further evaluate an 

applicant's operating experience related to the containment tendon prestress force.

The AMP related to the adequacy of prestressing force for containments with grouted tendons 

will be reviewed on a case-by-case basis.

Evaluation and Technical Basis

1. Scope of Program: The program addresses the assessment of containment tendon 

prestressing force when an applicant chooses to perform the containment prestress force 

TLAA using 10 CFR 54.21(c)(1)(iii).

2. Preventive Actions: Maintaining the prestress above the MRV, as described under 

program description above, will ensure that the structural and functional adequacy of the 

containment are maintained.

3. Parameters Monitored: The parameters to be monitored are the containment tendon 

prestressing forces in accordance with requirements specified in Subsection IWL of Section 

XI of the ASME Code, as incorporated by reference in 10 CFR 50.55a.

4. Detection of Aging Effects: The loss of containment tendon prestressing forces is detected 

by the program.

5. Monitoring and Trending: The estimated and measured prestressing forces are plotted 

against time and the PLL, MRV, and trending lines developed for the period of extended 

operation.
September 2005 X E-1 NUREG-1801, Rev. 1

X.E1 ENVIRONMENTAL QUALIFICATION (EQ) OF ELECTRIC COMPONENTS

Program Description

The Nuclear Regulatory Commission (NRC) has established nuclear station environmental 

qualification (EQ) requirements in 10 CFR Part 50, Appendix A, Criterion 4, and 10 CFR 50.49. 

10 CFR 50.49 specifically requires that an EQ program 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 environment) are qualified to perform 

their safety function in those harsh environments after the effects of inservice aging. 

10 CFR 50.49 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. 10 CFR 50.49 defines the scope of components to be included, 

requires the preparation and maintenance of a list of in-scope components, and requires the 

preparation and maintenance of a qualification file that includes component performance 

specifications, electrical characteristics, 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) 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. 10 CFR 50.49(f) establishes four 

methods of demonstrating qualification for aging and accident conditions. 10 CFR 50.49(k) and 

(l) permit different qualification criteria to apply based on plant and component vintage. 

Supplemental EQ regulatory guidance for compliance with these different qualification criteria is 

provided in the 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 Regulatory Guide 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.

EQ 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 time-limited aging analyses (TLAAs) for license renewal.

Under 10 CFR 54.21(c)(1)(iii), plant EQ programs, which implement the requirements of 

10 CFR 50.49 (as further defined and clarified by the DOR Guidelines, NUREG-0588, and 

Regulatory Guide 1.89, Rev. 1), are viewed as aging management programs (AMPs) for license 

renewal. Reanalysis 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 reanalysis of an aging evaluation 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 in the "EQ Component 

Reanalysis Attributes" section.
NUREG-1801, Rev. 1 X E-2 September 2005

This reanalysis program can be applied to EQ components now qualified for the current 

operating term (i.e., those components now qualified for 40 years or more). As evaluated below, 

this is an acceptable AMP. Thus, no further evaluation is recommended for license renewal if an 

applicant elects this option under 10 CFR 54.21(c)(1)(iii) to evaluate the TLAA of EQ of electric 

equipment.

EQ Component Reanalysis Attributes

The reanalysis of an aging evaluation is normally performed to extend the qualification by 

reducing excess conservatism incorporated in the prior evaluation. Reanalysis of an aging 

evaluation to extend the qualification of a component is performed on a routine basis 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 reanalysis 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 reanalysis 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 models used in the reanalysis of an aging evaluation are the 

same as those previously applied during the prior evaluation. The Arrhenius methodology is an 

acceptable thermal model for performing a thermal aging evaluation. The analytical method 

used for a radiation aging evaluation is to demonstrate qualification for the total integrated dose

(that is, normal radiation dose for the projected installed life plus accident radiation dose). For 

license renewal, one acceptable method of establishing the 60-year normal radiation dose is to 

multiply the 40-year normal radiation dose by 1.5 (that is, 60 years/40 years). The result is 

added to the accident radiation dose to obtain the total integrated dose for the component. For 

cyclical aging, a similar approach may be used. Other models may be justified on a case-bycase basis.

Data Collection and Reduction Methods: Reducing excess conservatism in the component 

service conditions (for example, temperature, radiation, cycles) used in the prior aging 

evaluation is the chief method used for a reanalysis. Temperature data used in an aging 

evaluation is to be conservative and based on plant design temperatures or on actual plant 

temperature data. When used, plant temperature data can be obtained in several ways, 

including monitors used for technical specification compliance, other installed monitors, 

measurements made by plant operators during rounds, and temperature sensors on large 

motors (while the motor is not running). A representative number of temperature measurements 

are conservatively evaluated to establish the temperatures used in an aging evaluation. Plant 

temperature data may be used in an aging evaluation in different ways, such as (a) directly 

applying the plant temperature data in the evaluation, or (b) using the plant temperature data to 

demonstrate conservatism when using plant design temperatures for an evaluation. Any 

changes to material activation energy values as part of a reanalysis are 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.
September 2005 X E-3 NUREG-1801, Rev. 1

Underlying Assumptions: EQ component aging evaluations contain sufficient conservatism to 

account for most environmental changes occurring due to plant modifications and events. When 

unexpected adverse conditions are identified during operational or maintenance activities that 

affect the normal operating environment of a qualified component, the affected EQ component 

is evaluated and appropriate corrective actions are taken, which may include changes to the 

qualification bases and conclusions.

Acceptance Criteria and Corrective Actions: The reanalysis of an aging evaluation could extend 

the qualification of the component. If the qualification cannot be extended by reanalysis, the 

component is to be refurbished, replaced, or requalified prior to exceeding the period for which 

the current qualification remains valid. A reanalysis is to be performed in a timely manner (that 

is, sufficient time is available to refurbish, replace, or requalify the component if the reanalysis is 

unsuccessful).

Evaluation and Technical Basis

1. Scope of Program: 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 and Regulatory Guide 1.89, Rev.1.

2. 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.

3. Parameters Monitored/Inspected: EQ component qualified life is not based on condition 

or performance monitoring. However, pursuant to Regulatory Guide 1.89, Rev. 1, such 

monitoring programs are an acceptable basis to modify a qualified life through reanalysis. 

Monitoring or inspection of certain environmental conditions or component parameters may 

be used to ensure that the component is within the bounds of its qualification basis, or as a 

means to modify the qualified life.

4. Detection of Aging Effects: 10 CFR 50.49 does not require the detection of aging effects 

for in-service 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.

5. Monitoring and Trending: 10 CFR 50.49 does not require monitoring and trending of 

component condition or performance parameters of in-service components to manage the 

effects of aging. 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.

6. 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 
NUREG-1801, Rev. 1 X E-4 September 2005

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.

7. Corrective Actions: 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. Confirmatory actions, as 

needed, are implemented as part of the station's corrective action program, pursuant to 

10 CFR 50, Appendix B. As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions.

8. Confirmation Process: Confirmatory actions, as needed, are implemented as part of the 

station's corrective action program, pursuant to 10 CFR 50, Appendix B. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address the confirmation process.

9. 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. As discussed in the appendix to this report, the staff finds the requirements of 

10 CFR Part 50, Appendix B, acceptable to address the administrative controls.

10. Operating Experience: EQ programs include consideration of operating experience to 

modify qualification bases and conclusions, including qualified life. 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.

References

10 CFR 50.49, Environmental Qualification of Electric Equipment Important to Safety for 

Nuclear Power Plants, Office of the Federal Register, National Archives and Records 

Administration, 2005.

DOR Guidelines, Guidelines for Evaluating Environmental Qualification of Class 1E Electrical 

Equipment in Operating Reactors, November 1979.

NRC Regulatory Guide 1.89, Rev. 1, Environmental Qualification of Certain Electric Equipment 

Important to Safety for Nuclear Power Plants, U. S. Nuclear Regulatory Commission, 

June 1984.
September 2005 X E-5 NUREG-1801, Rev. 1

NUREG-0588, Interim Staff Position on Environmental Qualification of Safety-Related Electrical 

Equipment, U. S. Nuclear Regulatory Commission, July 1981.

NRC Regulatory Issue Summary 2003-09, “Environmental Qualification of Low-Voltage 

Instrumentation and Control Cables” dated May 2, 2003.
NUREG-1801, Rev. 1 X E-6 September 2005

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September 2005 XI M-i NUREG-1801, Rev. 1

CHAPTER XI

AGING MANAGEMENT PROGRAMS

(AMPs) 
NUREG-1801, Rev. 1 XI M-ii September 2005

This Page Intentionally Left Blank
September 2005 XI M-iii NUREG-1801, Rev. 1

AGING MANAGEMENT PROGRAMS (AMPs)

XI.M1 ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD

XI.M2 Water Chemistry

XI.M3 Reactor Head Closure Studs

XI.M4 BWR Vessel ID Attachment Welds

XI.M5 BWR Feedwater Nozzle

XI.M6 BWR Control Rod Drive Return Line Nozzle

XI.M7 BWR Stress Corrosion Cracking

XI.M8 BWR Penetrations

XI.M9 BWR Vessel Internals

XI.M10 Boric Acid Corrosion

XI.M11 Nickel-Alloy Nozzles and Penetrations

XI.M11A Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure 

Heads of Pressurized Water Reactors 

XI.M12 Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)

XI.M13 Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless 

Steel (CASS)

XI.M14 Loose Part Monitoring

XI.M15 Neutron Noise Monitoring

XI.M16 PWR Vessel Internals

XI.M17 Flow-Accelerated Corrosion

XI.M18 Bolting Integrity

XI.M19 Steam Generator Tube Integrity

XI.M20 Open-Cycle Cooling Water System

XI.M21 Closed-Cycle Cooling Water System

XI.M22 Boraflex Monitoring

XI.M23 Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems

XI.M24 Compressed Air Monitoring

XI.M25 BWR Reactor Water Cleanup System

XI.M26 Fire Protection

XI.M27 Fire Water System

XI.M28 Buried Piping and Tanks Surveillance 

XI.M29 Aboveground Steel Tanks

XI.M30 Fuel Oil Chemistry

XI.M31 Reactor Vessel Surveillance

XI.M32 One-Time Inspection

XI.M33 Selective Leaching of Materials

XI.M34 Buried Piping and Tanks Inspection

XI.M35 One-time Inspection of ASME Code Class 1 Small Bore-Piping

XI.M36 External Surfaces Monitoring 

XI.M37 Flux Thimble Tube Inspection 

XI.M38 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

XI.M39 Lubricating Oil Analysis
NUREG-1801, Rev. 1 XI M-iv September 2005

AGING MANAGEMENT PROGRAMS (AMPs) (Continued)

XI.S1 ASME Section XI, Subsection IWE

XI.S2 ASME Section XI, Subsection IWL

XI.S3 ASME Section XI, Subsection IWF

XI.S4 10 CFR Part 50, Appendix J

XI.S5 Masonry Wall Program

XI.S6 Structures Monitoring Program 

XI.S7 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants

XI.S8 Protective Coating Monitoring and Maintenance Program

XI.E1 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements

XI.E2 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Used in Instrumentation Circuits

XI.E3 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements

XI.E4 Metal-Enclosed Bus

XI.E5 Fuse Holders

XI.E6 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirement
September 2005 XI M-1 NUREG-1801, Rev. 1

XI.M1 ASME SECTION XI INSERVICE INSPECTION, SUBSECTIONS IWB, IWC, AND IWD

Program Description

Title 10 of the Code of Federal Regulations, 10 CFR 50.55a, imposes the inservice inspection 

(ISI) requirements of the American Society of Mechanical Engineers (ASME) Boiler and 

Pressure Vessel (B&PV) Code, Section XI, for Class 1, 2, and 3 pressure-retaining components 

and their integral attachments in light-water cooled power plants. Inspection, repair, and 

replacement of these components are covered in Subsections IWB, IWC, and IWD, 

respectively, in the 2001 edition1 including the 2002 and 2003 Addenda. The program generally 

includes periodic visual, surface, and/or volumetric examination and leakage test of all Class 1, 

2, and 3 pressure-retaining components and their integral attachments. 

The ASME Section XI inservice inspection program in accordance with Subsections IWB, IWC, 

or IWD has been shown to be generally effective in managing aging effects in Class 1, 2, or 3 

components and their integral attachments in light-water cooled power plants. However, in 

certain cases, the ASME inservice inspection program is to be augmented to manage effects of 

aging for license renewal and is so identified in the GALL Report. 

Evaluation and Technical Basis

1. Scope of Program: The ASME Section XI program provides the requirements for ISI, 

repair, and replacement. The components within the scope of the program are specified in 

Subsections IWB-1100, IWC-1100, and IWD-1100 for Class 1, 2, and 3 components, 

respectively, and include all pressure-retaining components and their integral attachments 

in light-water cooled power plants. The components described in Subsections IWB-1220, 

IWC-1220, and IWD-1220 are exempt from the examination requirements of Subsections 

IWB-2500, IWC-2500, and IWD-2500.

2. Preventive Actions: Operation within the limits prescribed in the Technical 

Specifications.

3. Parameters Monitored/Inspected: The ASME Section XI ISI program detects 

degradation of components by using the examination and inspection requirements 

specified in ASME Section XI Tables IWB-2500-1, IWC-2500-1, or IWD-2500-1, 

respectively, for Class 1, 2, or 3 components. 

4. Detection of Aging Effects: The extent and schedule of the inspection and test 

techniques prescribed by the program are designed to maintain structural integrity and 

ensure that aging effects will be discovered and repaired before the loss of intended 

function of the component. Inspection can reveal cracking, loss of material due to 

corrosion, leakage of coolant and indications of degradation due to wear or stress 

relaxation, such as verification of clearances, settings, physical displacements, loose or 

missing parts, debris, wear, erosion, or loss of integrity at bolted or welded connections.

Components are examined and tested as specified in Tables IWB-2500-1, IWC-2500-1, 

and IWD-2500-1, respectively, for Class 1, 2, and 3 components. The tables specify the 

 

1

An applicant may rely on a different version of the ASME Code, but should justify such use. An 

applicant may wish to refer to the SOC for an update of 10 CFR § 50.55a to justify use of a more recent 

edition of the Code.
NUREG-1801, Rev. 1 XI M-2 September 2005

extent and schedule of the inspection and examination methods for the components of the 

pressure-retaining boundaries. Alternative approved methods that meet the requirements

of IWA-2240 are also specified in these tables. 

The program uses three types of examination — visual, surface, and volumetric — in 

accordance with the general requirements of Subsection IWA-2000. Visual VT-1 

examination detects discontinuities and imperfections, such as cracks, corrosion, wear, or 

erosion, on the surface of components. Visual VT-2 examination detects evidence of 

leakage from pressure-retaining components, as required during the system pressure test. 

Visual VT-3 examination (a) determines the general mechanical and structural condition of 

components and their supports by verifying parameters such as clearances, settings, and 

physical displacements; (b) detects discontinuities and imperfections such as loss of 

integrity at bolted or welded connections, loose or missing parts, debris, corrosion, wear, 

or erosion; and (c) observes conditions that could affect operability or functional adequacy 

of constant-load and spring-type components and supports.

Surface examination uses magnetic particle, liquid penetrant, or eddy current 

examinations to indicate the presence of surface discontinuities and flaws.

Volumetric examination uses radiographic, ultrasonic, or eddy current examinations to 

indicate the presence of discontinuities or flaws throughout the volume of material 

included in the inspection program.

For BWRs, the nondestructive examination (NDE) techniques appropriate for inspection of 

vessel internals, including the uncertainties inherent in delivering and executing an NDE 

technique in a boiling water reactor (BWR), are included in the approved boiling water 

reactor vessel and internals project (BWRVIP)-03. Also, an applicant may use the 

guidelines of the approved BWRVIP-62 for inspection relief for vessel internal components 

with hydrogen water chemistry provided such relief is submitted under the provisions of 

10 CFR 50.55a and approved by the staff.

The ASME Section XI examination categories used in this report are given below. 

Class 1 Components, Table IWB-2500-1

Examination category B-B for pressure-retaining welds in vessels other than reactor 

vessels: This category specifies volumetric examination of circumferential and longitudinal 

shell-to-head welds and circumferential and meridional head welds in pressurizers, and 

circumferential and meridional head welds and tubesheet-to-head welds in steam 

generators (primary side). The welds selected during the first inspection interval are 

reexamined during successive inspection intervals.

Examination category B-D for full penetration welds of nozzles in reactor vessels, 

pressurizers, steam generators (primary side), and heat exchangers (primary side): This 

category specifies volumetric examination of all nozzle-to-vessel welds and the nozzle 

inside surface.

Examination category B-E for pressure-retaining partial penetration welds in vessels: This 

category specifies visual VT-2 examination of partial penetration welds in nozzles and 

penetrations in reactor vessels and pressurizers during the hydrostatic test. In the 1995 

edition of the ASME Code, examination category B-E is covered under examination 

category B-P.
September 2005 XI M-3 NUREG-1801, Rev. 1

Examination category B-F for pressure-retaining dissimilar metal welds in reactor vessels, 

pressurizers, steam generators, heat exchangers, and piping: This category specifies 

volumetric examination of the inside diameter (ID) region and surface examination of the 

outside diameter (OD) surface for all nozzle-to-safe end butt welds of nominal pipe size 

(NPS) 4 inch (in.) or larger. Only surface examination is conducted for all butt welds less 

than NPS 4 in. and for all nozzle-to-safe end socket welds. Examinations are required for 

each safe end weld in each loop and connecting branch of the reactor coolant system. In 

the 1995 edition of the ASME Code, examination category B-F for piping is covered under 

examination category B-J for all pressure-retaining welds in piping.

Examination category B-G-1 for pressure-retaining bolting greater than 2 in. in diameter, 

and category B-G-2 for pressure-retaining bolting less than 2 in. in diameter in reactor 

vessels, pressurizers, steam generators, heat exchangers, piping, pumps, and valves: 

Category B-G-1 specifies volumetric examination of studs in place, from the top of the nut 

to the bottom of the flange hole; surface and volumetric examination of studs when 

removed; volumetric examination of flange threads; and visual VT-1 examination of the 

surfaces of nuts, washers, and bushings. Category B-G-2 specifies visual VT-1 

examination of the surfaces of nuts, washers, and bushings. For heat exchangers, piping, 

pumps, and valves, examinations are limited to components selected for examination 

under examination categories B-B, B-J, B-L-2, and B-M-2.

Examination category B-K for integral attachments for vessels: This category specifies 

volumetric or surface examination of essentially 100% of the length of the attachment 

weld at each attachment subject to examination.

Examination category B-J for pressure-retaining welds in piping: This category specifies 

volumetric examination of the ID region and surface examination of the OD for 

circumferential and longitudinal welds in each pipe or branch run NPS 4 in. or larger. 

Surface examination is conducted for circumferential and longitudinal welds in each pipe 

or branch run less than NPS 4 in. and for all socket welds. The pipe welds selected during 

the first inspection interval are reexamined during each successive inspection interval.

Examination category B-L-1 for pressure-retaining welds in pump casing, and 

category B-L-2 for pump casing: Category B-L-1 specifies volumetric examination of all 

welds, and category B-L-2 specifies visual VT-3 examination of internal surfaces of the 

pump casing. All welds from at least one pump in each group of pumps performing similar 

functions in the system (such as recirculating coolant pumps) are inspected during each 

inspection interval. Visual examination is required only when the pump is disassembled 

for maintenance, repair, or volumetric examination, but one pump in a particular group of 

pumps is visually examined at least once during the inspection interval.

Examination category B-M-1 for pressure-retaining welds in valve bodies and 

category B-M-2 for valve bodies: Category B-M-1 specifies volumetric examination for all 

welds in valve bodies NPS 4 in. or larger, and surface examination of OD surfaces for all 

welds in valve bodies less than NPS 4 in. Category B-M-2 specifies visual VT-3 

examination of internal surfaces of valve bodies. All welds from at least one valve in each 

group of valves that are of the same size, construction design (such as globe, gate, or 

check valves), and manufacturing method, and that perform similar functions in the 

system (such as the containment isolation valve) are inspected during each inspection 

interval. Visual examination is required only when the valve is disassembled for 
NUREG-1801, Rev. 1 XI M-4 September 2005

maintenance, repair, or volumetric examination, but one valve in a particular group of 

valves is visually examined at least once during the inspection interval.

Examination category B-N-1 for the interior of reactor vessels: Category B-N-1 specifies 

visual VT-3 examination of interior surfaces that are made accessible for examination by 

removal of components during normal refueling outages. 

Examination category B-N-2 for integrally welded core support structures and interior 

attachments to reactor vessels: Category B-N-2 specifies visual VT-1 examination of all 

accessible welds in interior attachments within the beltline region; visual VT-3 examination 

of all accessible welds in interior attachments beyond the beltline region; and, for BWRs, 

visual VT-3 examination of all accessible surfaces in the core support structure. 

Examination category B-N-3, which is applicable to pressurized water reactors (PWRs), 

for removable core support structures: Category B-N-3 specifies visual VT-3 examination 

of all accessible surfaces of reactor core support structures that can be removed from the 

reactor vessel.

Examination category B-O for pressure-retaining welds in control rod housing: This 

category specifies volumetric or surface examination of the control rod drive (CRD) 

housing welds, including the weld buttering.

Examination category B-P for all pressure-retaining components: This category specifies 

visual VT-2 examination of all pressure-retaining boundary components during the system 

leakage test and hydrostatic test (IWA-5000 and IWB-5000). The pressure-retaining 

boundary during the system leakage test corresponds to the reactor coolant system 

boundary, with all valves in the normal position, which is required for normal reactor 

operation startup. However, VT-2 visual examination extends to and includes the second 

closed valve at the boundary extremity. The 1995 edition of the ASME Code eliminated

the hydrostatic test because equivalent results are obtained from the leakage test. The 

pressure-retaining boundary for the hydrostatic test (1989 edition) and system leakage 

test (1995 edition) conducted at or near the end of each inspection interval extends to all 

Class 1 pressure-retaining components within the system boundary.

Class 2 Components, Table IWC-2500-1

Examination category C-A for pressure-retaining welds in pressure vessels: This category 

specifies volumetric examination of circumferential welds at gross structural 

discontinuities, such as junctions between shells of different thickness or cylindrical shellto-conical shell junctions, and head-to-shell, shell (or head)-to-flange, and tubesheet-toshell welds.

Examination category C-F-1 for pressure-retaining welds in austenitic stainless steel or 

high-alloy piping: This category specifies, for circumferential and longitudinal welds in 

each pipe or branch run NPS 4 in. or larger, volumetric and surface examination of the ID 

region, and surface examination of the OD surface for piping welds ≥3/8 in. wall thickness 

for piping >NPS 4 in. or for piping welds >1/5 in. wall thickness for piping ≥NPS 2 in. and 

≤NPS 4 in. Surface examination is conducted for circumferential and longitudinal welds in 

pipe branch connections of branch piping ≥NPS 2 in. and for socket welds.
September 2005 XI M-5 NUREG-1801, Rev. 1

Examination category C-G for all pressure-retaining welds in pumps and valves: This 

category specifies surface examination of either the inside or outside surface of all welds 

in the pump casing and valve body. In a group of multiple pumps or valves of similar 

design, size, function, and service in a system, examination of only one pump or one 

valve among each group of multiple pumps or valves is required to detect the loss of 

intended function of the pump or valve.

Examination category C-H for all pressure-retaining components: This category specifies 

visual VT-2 examination during system pressure tests (IWA-5000 and IWC-5000) of all 

pressure-retaining boundary components. The pressure-retaining boundary includes only 

those portions of the system required to operate or support the safety function, up to and 

including the first normally closed valve (including a safety or relief valve) or valve capable 

of automatic closure when the safety function is required. The 1995 edition of the ASME 

Code eliminated the hydrostatic test because equivalent results are obtained from the 

leakage test.

Class 3 Components, Table IWD-2500-1

Examination category D-A (1989 edition) for systems in support of reactor shutdown 

function, and category D-B (1989 edition) for systems in support of emergency core 

cooling, containment heat removal, atmosphere cleanup, and reactor residual heat 

removal: Categories D-A and D-B specify visual VT-2 examination during system pressure 

tests (IWA-5000 and IWD-5000) of all pressure-retaining boundary components. The 

pressure-retaining boundary extends up to and includes the first normally closed valve or 

valve capable of automatic closure as required to perform the safety-related system 

function. Examination categories D-A and D-B, from the 1989 edition of the ASME Code, 

have been combined into examination category D-B for all pressure-retaining components 

in the 1995 edition of the ASME Code.

5. Monitoring and Trending: For Class 1, 2, or 3 components, the inspection schedule of 

IWB-2400, IWC-2400, or IWD-2400, respectively, and the extent and frequency of IWB2500-1, IWC-2500-1, or IWD-2500-1, respectively, provides for timely detection of 

degradation. The sequence of component examinations established during the first 

inspection interval is repeated during each successive inspection interval, to the extent 

practical. If flaw conditions or relevant conditions of degradation are evaluated in 

accordance with IWB-3100, IWC-3100, or IWD-3100, and the component is qualified as 

acceptable for continued service, the areas containing such flaw indications and relevant 

conditions are reexamined during the next three inspection periods of IWB-2110 for Class 

1 components, IWC-2410 for Class 2 components, and IWD-2410 for Class 3 

components. Examinations that reveal indications that exceed the acceptance standards 

described below are extended to include additional examinations in accordance with IWB2430, IWC-2430, or IWD-2430 (1995 edition) for Class 1, 2, or, 3 components, 

respectively.

6. Acceptance Criteria: Any indication or relevant conditions of degradation detected are 

evaluated in accordance with IWB-3000, IWC-3000, or IWD-3000, for Class 1, 2, or 3 

components, respectively. Examination results are evaluated in accordance with IWB3100, IWC-3100, or IWD-3100 by comparing the results with the acceptance standards of 

IWB-3400 and IWB3500, or IWC-3400 and IWC-3500, or IWD3400 and IWD3500, 

respectively for Class 1 or Class 2 and 3 components. Flaws that exceed the size of 

allowable flaws, as defined in IWB-3500, IWC-3500, or IWD3500, are evaluated by using 
NUREG-1801, Rev. 1 XI M-6 September 2005

the analytical procedures of IWB-3600, IWC-3600, or IWD-3600, respectively, for Class 1 

or Class 2, and 3 components. Flaws that exceed the size of allowable flaws, as defined 

in IWB-3500 or IWC-3500, are evaluated by using the analytical procedures of IWB-3600 

or IWC-3600, respectively, for Class 1 or Class 2 and 3 components. Approved BWRVIP14, BWRVIP-59, and BWRVIP-60 documents provide guidelines for evaluation of crack 

growth in stainless steels, nickel alloys, and low-alloy steels, respectively. 

7. Corrective Actions: For Class 1, 2, and 3, respectively, repair is performed in 

conformance with IWB-4000, IWC-4000, and IWD-4000, and replacement according to 

IWB-7000, IWC-7000, and IWD-7000. Approved BWRVIP-44 and BWRVIP-45 

documents, respectively, provide guidelines for weld repair of nickel alloys and for 

weldability of irradiated structural components. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the

corrective actions.

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: Because the ASME Code is a consensus document that has 

been widely used over a long period, it has been shown to be generally effective in 

managing aging effects in Class 1, 2, and 3 components and their integral attachments in 

light-water cooled power plants (see Chapter I of the GALL Report, Vol. 2).

Some specific examples of operating experience of component degradation are as 

follows:

BWR: Cracking due to intergranular stress corrosion cracking (IGSCC) has occurred in 

small- and large-diameter BWR piping made of austenitic stainless steels and nickel 

alloys. The IGSCC has also occurred in a number of vessel internal components, such as 

core shrouds, access hole covers, top guides, and core spray spargers (NRC 

Bulletin 80-13, NRC Information Notice [IN] 95-17, NRC Generic Letter [GL] 94-03, and 

NUREG-1544). Cracking due to thermal and mechanical loading have occurred in highpressure coolant injection (HPCI) piping (NRC IN 89-80) and instrument lines (NRC 

Licensee Event Report [LER] 50-249/99-003-1). Jet pump BWRs are designed with 

access holes in the shroud support plate at the bottom of the annulus between the core 

shroud and the reactor vessel wall. These holes are used for access during construction 

and are subsequently closed by welding a plate over the hole. Both circumferential (NRC 

IN 88-03) and radial cracking (NRC IN 92-57) have been observed in access hole covers. 

Failure of the isolation condenser tube bundles due to thermal fatigue and transgranular 

stress corrosion cracking (TGSCC) caused by leaky valves has also occurred 

(NRC LER 50-219/98-014).

PWR Primary System: Although the primary pressure boundary piping of PWRs has 

generally not been found to be affected by SCC because of low dissolved oxygen levels 

and control of primary water chemistry, SCC has occurred in safety injection lines (NRC 

IN 97-19 and 84-18), charging pump casing cladding (NRC IN 80-38 and 94-63), 
September 2005 XI M-7 NUREG-1801, Rev. 1

instrument nozzles in safety injection tanks (NRC IN 91-05), CRD seal housing (NRC 

Inspection Report 50-255/99012), and safety-related stainless steel (SS) piping systems 

that contain oxygenated, stagnant, or essentially stagnant borated coolant (NRC IN 

97-19). Cracking has occurred in SS baffle former bolts in a number of foreign plants 

(NRC IN 98-11) and has been observed in plants in the United States. Cracking due to 

thermal and mechanical loading has occurred in high-pressure injection and safety 

injection piping (NRC IN 97-46 and NRC Bulletin 88-08). 

PWR Secondary System: Steam generator tubes have experienced outside diameter

stress corrosion cracking (ODSCC), intergranular attack (IGA), wastage, and pitting (NRC 

IN 97-88). Carbon steel support plates in steam generators have experienced general 

corrosion. Steam generator shells have experienced pitting and stress corrosion cracking 

(NRC INs 82-37, 85-65, and 90-04).

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2005.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 2001 edition including the 2002 and 2003 Addenda,

American Society of Mechanical Engineers, New York, NY.

BWRVIP-03, BWR Vessel and Internals Project, Reactor Pressure Vessel and Internals 

Examination Guidelines (EPRI TR-105696 R1, March 30, 1999), Final Safety Evaluation 

Report by the Office of Nuclear Reactor Regulation for BWRVIP-03, July 15, 1999.

BWRVIP-14, Evaluation of Crack Growth in BWR Stainless Steel RPV Internals 

(EPRI TR-105873, July 11, 2000), Final Safety Evaluation Report by the Office of Nuclear 

Reactor Regulation for BWRVIP-14, December 3, 1999.

BWRVIP-44, Underwater Weld Repair of Nickel Alloy Reactor Vessel Internals 

(EPRI TR-108708, April 3, 2000), Final Safety Evaluation Report by the Office of Nuclear 

Reactor Regulation for BWRVIP-44, June 9, 1999.

BWRVIP-45, Weldability of Irradiated LWR Structural Components, (EPRI TR-108707),

BWRVIP and Electric Power Research Institute, Palo Alto, CA, June 14, 2000.

BWRVIP-59, Evaluation of Crack Growth in BWR Nickel-Base Austenitic Alloys in RPV 

Internals, (EPRI TR-108710), BWRVIP and Electric Power Research Institute, Palo Alto, CA, 

March 24, 2000.

BWRVIP-60, BWR Vessel and Internals Project, Evaluation of Crack Growth in BWR Low Alloy 

Steel RPV Internals, (EPRI TR-108709, April 14, 2000), Final Safety Evaluation Report by 

the Office of Nuclear Reactor Regulation for BWRVIP-60, July 8, 1999.
NUREG-1801, Rev. 1 XI M-8 September 2005

BWRVIP-62, BWR Vessel and Internals Project, Technical Basis for Inspection Relief for BWR 

Internal Components with Hydrogen Injection, (EPRI TR-108705), BWRVIP and Electric 

Power Research Institute, Palo Alto, CA, March 7, 2000.

NRC Bulletin 88-08, Thermal Stresses in Piping Connected to Reactor Coolant System, U.S. 

Nuclear Regulatory Commission, June 22, 1988; Supplement 1, June 24, 1988; Supplement 

2, September 4, 1988; Supplement 3, April 4, 1989.

NRC Generic Letter 94-03, Intergranular Stress Corrosion Cracking of Core Shrouds in Boiling 

Water Reactors, U.S. Nuclear Regulatory Commission, July 25, 1994.

NRC Bulletin 80-13, Cracking in Core Spray Spargers, U.S. Nuclear Regulatory Commission, 

May 12, 1980.

NRC Information Notice 80-38, Cracking in Charging Pump Casing Cladding, U.S. Nuclear 

Regulatory Commission, October 31, 1980.

NRC Information Notice 82-37, Cracking in the Upper Shell to Transition Cone Girth Weld of a 

Steam Generator at an Operating PWR, U.S. Nuclear Regulatory Commission, 

September 16, 1982.

NRC Information Notice 84-18, Stress Corrosion Cracking in PWR Systems, U.S. Nuclear 

Regulatory Commission, March 7, 1984.

NRC Information Notice 85-65, Crack Growth in Steam Generator Girth Welds, U.S. Nuclear 

Regulatory Commission, July 31, 1985.

NRC Information Notice 88-03, Cracks in Shroud Support Access Hole Cover Welds, 

U.S. Nuclear Regulatory Commission, February 2, 1988.

NRC Information Notice 89-80, Potential for Water Hammer, Thermal Stratification, and Steam 

Binding in High-Pressure Coolant Injection Piping, U.S. Nuclear Regulatory Commission, 

December 1, 1989.

NRC Information Notice 90-04, Cracking of the Upper Shell-to-Transition Cone Girth Welds in 

Steam Generators, U.S. Nuclear Regulatory Commission, January 26, 1990.

NRC Information Notice 91-05, Intergranular Stress Corrosion Cracking in Pressurized Water 

Reactor Safety Injection Accumulator Nozzles, U.S. Nuclear Regulatory Commission, 

January 30, 1991.

NRC Information Notice 92-57, Radial Cracking of Shroud Support Access Hole Cover Welds, 

U.S. Nuclear Regulatory Commission, August 11, 1992.

NRC Information Notice 94-63, Boric Acid Corrosion of Charging Pump Casing Caused by 

Cladding Cracks, U.S. Nuclear Regulatory Commission, August 30, 1994.

NRC Information Notice 95-17, Reactor Vessel Top Guide and Core Plate Cracking, 

U.S. Nuclear Regulatory Commission, March 10, 1995.
September 2005 XI M-9 NUREG-1801, Rev. 1

NRC Information Notice 97-19, Safety Injection System Weld Flaw at Sequoyah Nuclear Power 

Plant, Unit 2, U.S. Nuclear Regulatory Commission, April 18, 1997.

NRC Information Notice 97-46, Unisolable Crack in High-Pressure Injection Piping, U.S. Nuclear

Regulatory Commission, July 9, 1997.

NRC Information Notice 97-88, Experiences During Recent Steam Generator Inspections, 

U.S. Nuclear Regulatory Commission, December 16, 1997.

NRC Information Notice 98-11, Cracking of Reactor Vessel Internal Baffle Former Bolts in 

Foreign Plants, U.S. Nuclear Regulatory Commission, March 25, 1998.

NRC Inspection Report 50-255/99012, Palisades Inspection Report, Item E8.2, Licensee Event 

Report 50-255/99-004, Control Rod Drive Seal Housing Leaks and Crack Indications, 

U.S. Nuclear Regulatory Commission, January 12, 2000. 

NRC Licensee Event Report LER 50-219/98-014-00, Failure of the Isolation Condenser Tube 

Bundles due to Thermal Stresses/Transgranular Stress Corrosion Cracking Caused by 

Leaky Valve, U.S. Nuclear Regulatory Commission, October 29, 1998. 

NRC Licensee Event Report LER 50-249/ 99-003-01, Supplement to Reactor Recirculation B 

Loop, High Pressure Flow Element Venturi Instrument Line Steam Leakage Results in 

Unit 3 Shutdown Due to Fatigue Failure of Socket Welded Pipe Joint, U.S. Nuclear 

Regulatory Commission, August 30, 1999.
NUREG-1801, Rev. 1 XI M-10 September 2005

XI.M2 WATER CHEMISTRY

Program Description

The main objective of this program is to mitigate damage caused by corrosion and stress 

corrosion cracking (SCC). The water chemistry program for boiling water reactors (BWRs) relies 

on monitoring and control of reactor water chemistry based on industry guidelines such as the 

boiling water reactor vessel and internals project (BWRVIP)-29 (Electric Power Research 

Institute [EPRI] TR-103515) or later revisions. The BWRVIP-29 has three sets of guidelines: one 

for primary water, one for condensate and feedwater, and one for control rod drive (CRD) 

mechanism cooling water. The water chemistry program for pressurized water reactors (PWRs) 

relies on monitoring and control of reactor water chemistry based on industry guidelines for 

primary water and secondary water chemistry such as EPRI TR-105714, Rev. 3 and TR102134, Rev. 3 or later revisions. 

The water chemistry programs are generally effective in removing impurities from intermediate 

and high flow areas. The Generic Aging Lessons Learned (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’s intended function will be 

maintained during the extended period of operation. As discussed in the GALL Report for these 

specific cases, an acceptable verification program is a one-time inspection of selected 

components at susceptible locations in the system.

Evaluation and Technical Basis

1. Scope of Program: The program includes periodic monitoring and control of known 

detrimental contaminants such as chlorides, fluorides (PWRs only), dissolved oxygen, and 

sulfate concentrations below the levels known to result in loss of material or cracking. 

Water chemistry control is in accordance with industry guidelines such as BWRVIP-29 

(EPRI TR-103515) for water chemistry in BWRs, EPRI TR-105714 for primary water 

chemistry in PWRs, and EPRI TR-102134 for secondary water chemistry in PWRs. 

2. Preventive Actions: The program includes specifications for chemical species, sampling 

and analysis frequencies, and corrective actions for control of reactor water chemistry. 

System water chemistry is controlled to minimize contaminant concentration and mitigate 

loss of material due to general, crevice and pitting corrosion and cracking caused by SCC. 

For BWRs, maintaining high water purity reduces susceptibility to SCC.

3. Parameters Monitored/Inspected: The concentration of corrosive impurities listed in the 

EPRI guidelines discussed above, which include chlorides, fluorides (PWRs only), 

sulfates, dissolved oxygen, and hydrogen peroxide, are monitored to mitigate degradation 

of structural materials. Water quality (pH and conductivity) is also maintained in 

accordance with the guidance. Chemical species and water quality are monitored by inprocess methods or through sampling. The chemical integrity of the samples is 

maintained and verified to ensure that the method of sampling and storage will not cause 

a change in the concentration of the chemical species in the samples.
September 2005 XI M-11 NUREG-1801, Rev. 1

BWR Water Chemistry: The guidelines in BWRVIP-29 (EPRI TR-103515) for BWR reactor 

water recommend that the concentration of chlorides, sulfates, and dissolved oxygen are 

monitored and kept below the recommended levels to mitigate corrosion. The two 

impurities, chlorides and sulfates, determine the coolant conductivity; dissolved oxygen, 

hydrogen peroxide, and hydrogen determine electrochemical potential (ECP). The EPRI 

guidelines recommend that the coolant conductivity and ECP are also monitored and kept 

below the recommended levels to mitigate SCC and corrosion in BWR plants. The EPRI 

guidelines in BWRVIP-29 (TR-103515) for BWR feedwater, condensate, and control rod 

drive water recommend that conductivity, dissolved oxygen level, and concentrations of 

iron and copper (feedwater only) are monitored and kept below the recommended levels 

to mitigate SCC. The EPRI guidelines in BWRVIP-29 (TR-103515) also include 

recommendations for controlling water chemistry in auxiliary systems: torus/pressure 

suppression chamber, condensate storage tank, and spent fuel pool. 

PWR Primary Water Chemistry: The EPRI guidelines (EPRI TR-105714), for PWR 

primary water chemistry recommend that the concentration of chlorides, fluorides, 

sulfates, lithium, and dissolved oxygen and hydrogen are monitored and kept below the 

recommended levels to mitigate SCC of austenitic stainless steel, Alloy 600, and Alloy 

690 components. TR-105714 provides guidelines for chemistry control in PWR auxiliary 

systems such as the boric acid storage tank, refueling water storage tank, spent fuel pool, 

letdown purification systems, and volume control tank. 

PWR Secondary Water Chemistry: The EPRI guidelines (EPRI TR-102134), for PWR 

secondary water chemistry recommend monitoring and control of chemistry parameters 

(e.g., pH level, cation conductivity, sodium, chloride, sulfate, lead, dissolved oxygen, iron, 

copper, and hydrazine) to mitigate steam generator tube degradation caused by denting, 

intergranular attack (IGA), outer diameter stress corrosion cracking (ODSCC), or crevice 

and pitting corrosion. The monitoring and control of these parameters, especially the pH 

level, also mitigates general (for steel components), crevice, and pitting corrosion of the 

steam generator shell and the balance of plant materials of construction (e.g., steel, 

stainless steel, and copper).

4. Detection of Aging Effects: This is a mitigation program and does not provide for 

detection of any aging effects.

In certain cases as identified in the GALL Report, inspection of select components is to be 

undertaken to verify the effectiveness of the chemistry control program and to ensure that 

significant degradation is not occurring and the component intended function will be 

maintained during the extended period of operation. 

5. Monitoring and Trending: The frequency of sampling water chemistry varies (e.g., 

continuous, daily, weekly, or as needed) based on plant operating conditions and the 

EPRI water chemistry guidelines. Whenever corrective actions are taken to address an 

abnormal chemistry condition, increased sampling is utilized to verify the effectiveness of 

these actions. 

6. Acceptance Criteria: Maximum levels for various contaminants are maintained below the 

system specific limits as indicated by the limits specified in the corresponding EPRI water 

chemistry guidelines. Any evidence of aging effects or unacceptable water chemistry 

results is evaluated, the root cause identified, and the condition corrected.
NUREG-1801, Rev. 1 XI M-12 September 2005

7. Corrective Actions: When measured water chemistry parameters are outside the 

specified range, corrective actions are taken to bring the parameter back within the 

acceptable range and within the time period specified in the EPRI water chemistry 

guidelines. As discussed in the appendix to this report, the staff finds the requirements of 

10 CFR Part 50, Appendix B, acceptable to address the corrective actions.

8. Confirmation Process: Following corrective actions, additional samples are taken and 

analyzed to verify that the corrective actions were effective in returning the concentrations 

of contaminants such as chlorides, fluorides, sulfates, dissolved oxygen, and hydrogen 

peroxide to within the acceptable ranges. As discussed in the appendix to this report, the 

staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process.

9. Administrative Controls: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address 

administrative controls.

10. Operating Experience: The EPRI guideline documents have been developed based on 

plant experience and have been shown to be effective over time with their widespread 

use. The specific examples of operating experience are as follows:

BWR: Intergranular stress corrosion cracking (IGSCC) has occurred in small- and largediameter BWR piping made of austenitic stainless steels and nickel-base alloys. 

Significant cracking has occurred in recirculation, core spray, residual heat removal (RHR) 

systems, and reactor water cleanup (RWCU) system piping welds. IGSCC has also 

occurred in a number of vessel internal components, including core shroud, access hole 

cover, top guide, and core spray spargers (Nuclear Regulatory Commission [NRC] 

Bulletin 80-13, NRC Information Notice [IN] 95-17, NRC Generic Letter [GL] 94-03, and 

NUREG-1544). No occurrence of SCC in piping and other components in standby liquid 

control systems exposed to sodium pentaborate solution has ever been reported 

(NUREG/CR-6001).

PWR Primary System: The primary pressure boundary piping of PWRs has generally not 

been found to be affected by SCC because of low dissolved oxygen levels and control of 

primary water chemistry. However, the potential for SCC exists due to inadvertent 

introduction of contaminants into the primary coolant system from unacceptable levels of

contaminants in the boric acid, introduction through the free surface of the spent fuel pool 

(which can be a natural collector of airborne contaminants), or introduction of oxygen 

during cooldown (NRC IN 84–18). Ingress of demineralizer resins into the primary system 

has caused IGSCC of Alloy 600 vessel head penetrations (NRC IN 96-11, NRC 

GL 97-01). Inadvertent introduction of sodium thiosulfate into the primary system has 

caused IGSCC of steam generator tubes. The SCC has occurred in safety injection lines 

(NRC INs 97-19 and 84-18), charging pump casing cladding (NRC INs 80-38 and 94-63), 

instrument nozzles in safety injection tanks (NRC IN 91-05), and safety-related SS piping 

systems that contain oxygenated, stagnant, or essentially stagnant borated coolant (NRC 

IN 97-19). Steam generator tubes and plugs and Alloy 600 penetrations have experienced 

primary water stress corrosion cracking (PWSCC) (NRC INs 89-33, 94-87, 97-88, 90-10, 

and 96-11; NRC Bulletin 89-01 and its two supplements).
September 2005 XI M-13 NUREG-1801, Rev. 1

PWR Secondary System: Steam generator tubes have experienced ODSCC, IGA, 

wastage, and pitting (NRC IN 97-88, NRC GL 95-05). Carbon steel support plates in 

steam generators have experienced general corrosion. The steam generator shell has 

experienced pitting and stress corrosion cracking (NRC INs 82-37, 85-65, and 90-04).

Such operating experience has provided feedback to revisions of the EPRI water 

chemistry guideline documents. 

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

BWRVIP-29 (EPRI TR-103515), BWR Water Chemistry Guidelines-1993 Revision, Normal and 

Hydrogen Water Chemistry, Electric Power Research Institute, Palo Alto, CA, February 

1994.

BWRVIP-79, BWR Water Chemistry Guidelines, Electric Power Research Institute, Palo Alto, 

CA, March 2000.

BWRVIP-130, BWR Water Chemistry Guidelines, Electric Power Research Institute, Palo Alto, 

CA, October 2000.

EPRI TR-102134, PWR Secondary Water Chemistry Guideline-Revision 3, Electric Power 

Research Institute, Palo Alto, CA, May 1993.

EPRI TR-105714, PWR Primary Water Chemistry Guidelines–Revision 3, Electric Power 

Research Institute, Palo Alto, CA, Nov. 1995.

EPRI TR-1002884, PWR Primary Water Chemistry Guidelines, Electric Power Research 

Institute, Palo Alto, CA, October 2003.

NRC Bulletin 80-13, Cracking in Core Spray Piping, U.S. Nuclear Regulatory Commission, May 

12, 1980.

NRC Bulletin 89-01, Failure of Westinghouse Steam Generator Tube Mechanical Plugs, 

U.S. Nuclear Regulatory Commission, May 15, 1989.

NRC Bulletin 89-01, Supplement 1, Failure of Westinghouse Steam Generator Tube Mechanical 

Plugs, U.S. Nuclear Regulatory Commission, November 14, 1989.

NRC Bulletin 89-01, Supplement 2, Failure of Westinghouse Steam Generator Tube Mechanical 

Plugs, U.S. Nuclear Regulatory Commission, June 28, 1991.

NRC Generic Letter 94-03, Intergranular Stress Corrosion Cracking of Core Shrouds in Boiling 

Water Reactors, U.S. Nuclear Regulatory Commission, July 25, 1994.

NRC Generic Letter 95-05, Voltage-Based Repair Criteria for Westinghouse Steam Generator 

Tubes Affected by Outside Diameter Stress Corrosion Cracking, U.S. Nuclear Regulatory 

Commission, August 3, 1995.
NUREG-1801, Rev. 1 XI M-14 September 2005

NRC Generic Letter 97-01, Degradation of Control Rod Drive Mechanism Nozzle and Other 

Vessel Closure Head Penetrations, U.S. Nuclear Regulatory Commission, April 1,1997.

NRC Information Notice 80-38, Cracking In Charging Pump Casing Cladding, U.S. Nuclear 

Regulatory Commission, October 31, 1980.

NRC Information Notice 82-37, Cracking in the Upper Shell to Transition Cone Girth Weld of a 

Steam Generator at an Operating PWR, U.S. Nuclear Regulatory Commission, 

September 16,1982.

NRC Information Notice 84-18, Stress Corrosion Cracking in Pressurized Water Reactor 

Systems, U.S. Nuclear Regulatory Commission, March 7, 1984.

NRC Information Notice 85-65, Crack Growth in Steam Generator Girth Welds, U.S. Nuclear 

Regulatory Commission, July 31, 1985.

NRC Information Notice 89-33, Potential Failure of Westinghouse Steam Generator Tube 

Mechanical Plugs, U.S. Nuclear Regulatory Commission, March 23, 1989.

NRC Information Notice 90-04, Cracking of the Upper Shell-to-Transition Cone Girth Welds in 

Steam Generators, U.S. Nuclear Regulatory Commission, January 26, 1990.

NRC Information Notice 90-10, Primary Water Stress Corrosion Cracking (PWSCC) of 

Inconel 600, U.S. Nuclear Regulatory Commission, February 23, 1990.

NRC Information Notice 91-05, Intergranular Stress Corrosion Cracking In Pressurized Water 

Reactor Safety Injection Accumulator Nozzles, U.S. Nuclear Regulatory Commission, 

January 30, 1991.

NRC Information Notice 94-63, Boric Acid Corrosion of Charging Pump Casing Caused by 

Cladding Cracks, U.S. Nuclear Regulatory Commission, August 30, 1994.

NRC Information Notice 94-87, Unanticipated Crack in a Particular Heat of Alloy 600 Used for 

Westinghouse Mechanical Plugs for Steam Generator Tubes, U.S. Nuclear Regulatory 

Commission, December 22, 1994.

NRC Information Notice 95-17, Reactor Vessel Top Guide and Core Plate Cracking, 

U.S. Nuclear Regulatory Commission, March 10, 1995.

NRC Information Notice 96-11, Ingress of Demineralizer Resins Increase Potential for Stress 

Corrosion Cracking of Control Rod Drive Mechanism Penetrations, U.S. Nuclear Regulatory 

Commission, February 14, 1996.

NRC Information Notice 97-19, Safety Injection System Weld Flaw at Sequoyah Nuclear Power 

Plant, Unit 2, U.S. Nuclear Regulatory Commission, April 18, 1997.

NRC Information Notice 97-88, Experiences During Recent Steam Generator Inspections, 

U.S. Nuclear Regulatory Commission, December 16, 1997.

NUREG-1544, Status Report: Intergranular Stress Corrosion Cracking of BWR Core Shrouds 

and Other Internal Components, U.S. Nuclear Regulatory Commission, March 1996.
September 2005 XI M-15 NUREG-1801, Rev. 1

NUREG/CR-6001, Aging Assessment of BWR Standby Liquid Control Systems, G. D. Buckley, 

R. D. Orton, A. B. Johnson Jr., and L. L. Larson, 1992.
NUREG-1801, Rev. 1 XI M-16 September 2005

XI.M3 Reactor Head Closure Studs

Program Description

This program includes (a) inservice inspection (ISI) in conformance with the requirements of the 

American Society of Mechanical Engineers (ASME), Code, Section XI, Subsection IWB (2001 

edition2 including the 2002 and 2003 Addenda), Table IWB 2500-1, and (b) preventive 

measures to mitigate cracking. 

Evaluation and Technical Basis

1. Scope of Program: The program includes (a) ISI to detect cracking due to stress 

corrosion cracking (SCC) or intergranular stress corrosion cracking (IGSCC), loss of 

material due to wear, and coolant leakage from reactor vessel closure stud bolting for both 

boiling water reactors (BWRs) and pressurized water reactors (PWRs); and (b) preventive 

measures of NRC Regulatory Guide 1.65 to mitigate cracking. The program is applicable 

to closure studs and nuts constructed from materials with a maximum tensile strength 

limited to less than 1,172 MPa (170 ksi) (Nuclear Regulatory Commission [NRC] 

Regulatory Guide [RG] 1.65).

2. Preventive Actions: Preventive measures include avoiding the use of metal-plated stud 

bolting to prevent degradation due to corrosion or hydrogen embrittlement, and to use 

manganese phosphate or other acceptable surface treatments and stable lubricants 

(RG 1.65). Implementation of these mitigation measures is can reduce SCC or IGSCC,

thus making this program effective.

3. Parameters Monitored/Inspected: The ASME Section XI ISI program detects and sizes 

cracks, detects loss of material, and detects coolant leakage by following the examination 

and inspection requirements specified in Table IWB-2500-1. 

4. Detection of Aging Effects: The extent and schedule of the inspection and test 

techniques prescribed by the program are designed to maintain structural integrity and 

ensure that aging effects will be discovered and repaired before the loss of intended 

function of the component. Inspection can reveal cracking, loss of material due to 

corrosion or wear, and leakage of coolant.

The program uses visual, surface, and volumetric examinations in accordance with the 

general requirements of Subsection IWA-2000. Surface examination uses magnetic 

particle, liquid penetration, or eddy current examinations to indicate the presence of 

surface discontinuities and flaws. Volumetric examination uses radiographic or ultrasonic 

examinations to indicate the presence of discontinuities or flaws throughout the volume of 

material. Visual VT-2 examination detects evidence of leakage from pressure-retaining 

components, as required during the system pressure test.

Components are examined and tested as specified in Table IWB-2500-1. Examination 

category B-G-1 for pressure-retaining bolting greater than 2 in. diameter in reactor vessels 

specifies volumetric examination of studs in place, from the top of the nut to the bottom of 

 

2

An applicant may rely on a different version of the ASME Code, but should justify such use. An 

applicant may wish to refer to the SOC for an update of 10 CFR § 50.55a to justify use of a more recent 

edition of the Code.
September 2005 XI M-17 NUREG-1801, Rev. 1

the flange hole, and surface and volumetric examination of studs when removed. Also 

specified are volumetric examination of flange threads and visual VT-1 examination of 

surfaces of nuts, washers, and bushings. Examination category B-P for all pressureretaining components specifies visual VT-2 examination of all pressure-retaining boundary 

components during the system leakage test and the system hydrostatic test.

5. Monitoring and Trending: The Inspection schedule of IWB-2400, and the extent and 

frequency of IWB-2500-1 provide timely detection of cracks, loss of material, and leakage.

6. Acceptance Criteria: Any indication or relevant condition of degradation in closure stud 

bolting is evaluated in accordance with IWB-3100 by comparing ISI results with the 

acceptance standards of IWB-3400 and IWB-3500.

7. Corrective Actions: Repair and replacement are performed in conformance with the 

requirements of IWB-400 and IWB-7000, respectively, and the material and inspection 

guidance of RG 1.65. As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective 

actions.

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: The SCC has occurred in BWR pressure vessel head studs 

(Stoller 1991). The aging management program (AMP) has provisions regarding 

inspection techniques and evaluation, material specifications, corrosion prevention, and 

other aspects of reactor pressure vessel head stud cracking. Implementation of the 

program provides reasonable assurance that the effects of cracking due to SCC or IGSCC 

and loss of material due to wear will be adequately managed so that the intended 

functions of the reactor head closure studs and bolts will be maintained consistent with the 

current licensing basis (CLB) for the period of extended operation.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2005.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 2001 edition including the 2002 and 2003 Addenda, 

American Society of Mechanical Engineers, New York, NY.

NRC Regulatory Guide 1.65, Material and Inspection for Reactor Vessel Closure Studs, 

U.S. Nuclear Regulatory Commission, October 1973.
NUREG-1801, Rev. 1 XI M-18 September 2005

Stoller, S. M., Reactor Head Closure Stud Cracking, Material Toughness Outside FSAR - SCC 

in Thread Roots, Nuclear Power Experience, BWR-2, Ill, 58, 1991, p. 30.
September 2005 XI M-19 NUREG-1801, Rev. 1

XI.M4 BWR VESSEL ID ATTACHMENT WELDS

Program Description

The program includes (a) inspection and flaw evaluation in accordance with the guidelines of 

staff-approved boiling water reactor vessel and internals project (BWRVIP)-48, and 

(b) monitoring and control of reactor coolant water chemistry in accordance with the guidelines 

of BWRVIP-29 (Electric Power Research Institute [EPRI] TR-103515) to ensure the long-term 

integrity and safe operation of boiling water reactor (BWR) vessel inside diameter (ID) 

attachment welds.

Evaluation and Technical Basis

1. Scope of Program: The program is focused on managing the effects of cracking due to 

stress corrosion cracking (SCC), including intergranular stress corrosion cracking 

(IGSCC). The program contains preventive measures to mitigate SCC inservice 

inspection (ISI) to detect cracking and monitor the effects of cracking on the intended 

function of the components, and repair and/or replacement, as needed, to maintain the 

ability to perform the intended function.

The guidelines of BWRVIP-48 include inspection recommendations and evaluation 

methodologies for the attachment welds between the vessel wall and vessel ID brackets 

that attach safety-related components to the vessel (e.g., jet pump riser braces and corespray piping brackets). In some cases, the attachment is a simple weld; in others, it 

includes a weld build-up pad on the vessel. The BWRVIP-48 guidelines include 

information on the geometry of the vessel ID attachments, evaluate susceptible locations 

and safety consequence of failure, provide recommendations regarding the method, 

extent, and frequency of inspection, and discuss acceptable methods for evaluating the 

structural integrity significance of flaws detected during these examinations.

2. Preventive Actions: The BWRVIP-48 provides guidance on detection, but does not 

provide guidance on methods to mitigate cracking. Maintaining high water purity reduces 

susceptibility to SCC or IGSCC. Reactor coolant water chemistry is monitored and 

maintained in accordance with the guidelines in BWRVIP-29 (EPRI TR-103515). The 

program description and evaluation and technical basis of monitoring and maintaining 

reactor water chemistry are presented in Section XI.M2, “Water Chemistry.”

3. Parameters Monitored/Inspected: The program monitors the effects of SCC and IGSCC 

on the intended function of vessel attachment welds by detection and sizing of cracks by 

ISI in accordance with the guidelines of approved BWRVIP-48 and the requirements of 

the American Society of Mechanical Engineers (ASME) Code, Section XI, Table IWB 

2500-1 (2001 edition3 including the 2002 and 2003 Addenda). An applicant may use the 

guidelines of BWRVIP-62 for inspection relief for vessel internal components with 

hydrogen water chemistry provided that such relief is submitted under the provisions of 10

CFR 50.55a and approved by the staff. 

 

3

An applicant may rely on a different version of the ASME Code, but should justify such use. An 

applicant may wish to refer to the SOC for an update of 10 CFR § 50.55a to justify use of a more recent 

edition of the Code.
NUREG-1801, Rev. 1 XI M-20 September 2005

4. Detection of Aging Effects: The extent and schedule of the inspection and test 

techniques prescribed by BWRVIP-48 guidelines are designed to maintain structural 

integrity and ensure that aging effects will be discovered and repaired before the loss of 

intended function. Inspection can reveal cracking. Vessel ID attachment welds are 

inspected in accordance with the requirements of ASME Section XI, Subsection IWB, 

examination category B-N-2. The Section XI inspection specifies visual VT-1 examination 

to detect discontinuities and imperfections on the surfaces of components and visual VT-3 

examination to determine the general mechanical and structural condition of the 

component supports. The inspection and evaluation guidelines of BWRVIP-48 

recommend more stringent inspections for certain attachments. The guidelines 

recommend enhanced visual VT-1 examination of all safety-related attachments and 

those nonsafety-related attachments identified as being susceptible to IGSCC. Visual 

VT-1 examination is capable of achieving 1/32 in. resolution; the enhanced visual VT-1 

examination method is capable of achieving a 1-mil wire resolution. The nondestructive 

examination (NDE) techniques appropriate for inspection of BWR vessel internals 

including the uncertainties inherent in delivering and executing NDE techniques in a BWR, 

are included in BWRVIP-03.

5. Monitoring and Trending: Inspections scheduled in accordance with IWB-2400 and 

approved BWRVIP-48 guidelines provide timely detection of cracks. If flaws are detected, 

the scope of examination is expanded.

6. Acceptance Criteria: Any indication detected is evaluated in accordance with ASME 

Section XI or the staff-approved BWRVIP-48 guidelines. Applicable and approved 

BWRVIP-14, BWRVIP-59, and BWRVIP-60 documents provide guidelines for evaluation 

of crack growth in stainless steels (SSs), nickel alloys, and low-alloy steels, respectively.

7. Corrective Actions: Repair and replacement procedures are equivalent to those 

requirements in the ASME Section XI. Repair is performed in conformance with IWB-4000 

and replacement occurs according to IWB-7000. As discussed in the appendix to this 

report, the staff finds that licensee implementation of the guidelines in BWRVIP-48, as 

modified, will provide an acceptable level of quality for inspection and flaw evaluation of 

the safety-related components addressed in accordance with 10 CFR Part 50, 

Appendix B, corrective actions.

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds that licensee implementation of the guidelines in BWRVIP-48, as modified, 

will provide an acceptable level of quality for inspection and flaw evaluation of the safetyrelated components addressed in accordance with the 10 CFR Part 50, Appendix B, 

confirmation process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: Cracking due to SCC, including IGSCC, has occurred in BWR 

components. The program guidelines are based on an evaluation of available information, 

including BWR inspection data and information on the elements that cause IGSCC, to 

determine which attachment welds may be susceptible to cracking. Implementation of the 

program provides reasonable assurance that cracking will be adequately managed and 
September 2005 XI M-21 NUREG-1801, Rev. 1

the intended functions of the vessel ID attachments will be maintained consistent with the 

current licensing basis (CLB) for the period of extended operation.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2005.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 2001 edition including the 2002 and 2003 Addenda, 

American Society of Mechanical Engineers, New York, NY.

BWRVIP-03, BWR Vessel and Internals Project, Reactor Pressure Vessel and Internals 

Examination Guidelines (EPRI TR-105696 R1, March 30, 1999), Final Safety Evaluation 

Report by the Office of Nuclear Reactor Regulation for BWRVIP-03, July 15, 1999.

BWRVIP-14, Evaluation of Crack Growth in BWR Stainless Steel RPV Internals 

(EPRI TR-105873, July 11, 2000), Final Safety Evaluation Report by the Office of Nuclear 

Reactor Regulation for BWRVIP-14, December 3, 1999.

BWRVIP-29, BWR Vessel and Internals Project, BWR Water Chemistry Guidelines-1993 

Revision, Normal and Hydrogen Water Chemistry (EPRI TR-103515), February 1994.

BWRVIP-48, BWR Vessel and Internals Project, Vessel ID Attachment Weld Inspection and 

Flaw Evaluation Guidelines (EPRI TR-108724, February 1998), Final License Renewal 

Safety Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-48 for 

Compliance with the License Renewal Rule (10 CFR Part 54), January 17, 2001.

BWRVIP-59, Evaluation of Crack Growth in BWR Nickel-Base Austenitic Alloys in RPV Internals 

(EPRI TR-108710), March 24, 2000.

BWRVIP-60, BWR Vessel and Internals Project, Evaluation of Crack Growth in BWR Low Alloy 

Steel RPV Internals (EPRI TR-108709, April 14, 2000), Final Safety Evaluation Report by 

the Office of Nuclear Reactor Regulation for BWRVIP-60, July 8, 1999.

BWRVIP-62, BWR Vessel and Internals Project, Technical Basis for Inspection Relief for BWR 

Internal Components with Hydrogen Injection (EPRI TR-108705), March 7, 2000.
NUREG-1801, Rev. 1 XI M-22 September 2005

XI.M5 BWR FEEDWATER NOZZLE

Program Description

This program includes (a) enhanced inservice inspection (ISI) in accordance with the 

requirements of the American Society of Mechanical Engineers (ASME) Code, Section XI, 

Subsection IWB, Table IWB 2500-1 (2001 edition4 including the 2002 and 2003 Addenda) and 

the recommendation of General Electric (GE) NE-523-A71-0594, and (b) system modifications 

to mitigate cracking. The program specifies periodic ultrasonic inspection of critical regions of 

the boiling water reactor (BWR) feedwater nozzle. 

Evaluation and Technical Basis

1. Scope of Program: The program includes enhanced ISI to monitor the effects of cracking

on the intended function of the component, and systems modifications to mitigate 

cracking.

2. Preventive Actions: Mitigation occurs by systems modifications, such as removal of 

stainless steel cladding and installation of improved spargers. Mitigation is also 

accomplished by changes to plant-operating procedures, such as improved feedwater 

control and rerouting of the reactor water cleanup system, to decrease the magnitude and 

frequency of temperature fluctuations.

3. Parameters Monitored/Inspected: The aging management program (AMP) monitors the 

effects of cracking on the intended function of the component by detection and sizing of 

cracks by ISI in accordance with ASME Section XI, Subsection IWB and the 

recommendation of GE NE-523-A71-0594.

4. Detection of Aging Effects: The extent and schedule of the inspection prescribed by the 

program are designed to ensure that aging effects will be discovered and repaired before 

the loss of intended function of the component. Inspection can reveal cracking. 

GE NE-523-A71-0594 specifies ultrasonic testing (UT) of specific regions of the blend 

radius and bore. The UT examination techniques and personnel qualifications are in 

accordance with the guidelines of GE NE-523-A71-0594. Based on the inspection method 

and techniques and plant-specific fracture mechanics assessments, the inspection 

schedule is in accordance with Table 6-1 of GE NE-523-A71-0594. Leakage monitoring 

may be used to modify the inspection interval.

5. Monitoring and Trending: Inspections scheduled in accordance with GE NE-523-A71-

0594 provide timely detection of cracks.

6. Acceptance Criteria: Any cracking is evaluated in accordance with IWB-3100 by 

comparing inspection results with the acceptance standards of IWB-3400 and IWB-3500.

7. Corrective Actions: Repair is performed in conformance with IWB-4000 and replacement 

in accordance with IWB-7000. As discussed in the appendix to this report, the staff finds 

 

4

An applicant may rely on a different version of the ASME Code, but should justify such use. An 

applicant may wish to refer to the SOC for an update of 10 CFR § 50.55a to justify use of a more recent 

edition of the Code.
September 2005 XI M-23 NUREG-1801, Rev. 1

the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective 

actions.

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: Cracking has occurred in several BWR plants (NUREG-0619, 

NRC Generic Letter 81-11). This AMP has been implemented for nearly 25 years and has 

been found to be effective in managing the effect of cracking on the intended function of 

feedwater nozzles.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 2001 edition including the 2002 and 2003 Addenda, 

American Society of Mechanical Engineers, New York, NY.

GE-NE-523-A71-0594, Rev. 1, Alternate BWR Feedwater Nozzle Inspection Requirements, 

BWR Owner’s Group, August 1999.

NRC Generic Letter 81-11, BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle 

Cracking (NUREG-0619), U.S. Nuclear Regulatory Commission, February 29, 1981.

NUREG-0619, BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking, 

U.S. Nuclear Regulatory Commission, November 1980.
NUREG-1801, Rev. 1 XI M-24 September 2005

XI.M6 BWR CONTROL ROD DRIVE RETURN LINE NOZZLE

Program Description

This program includes (a) enhanced inservice inspection (ISI) in conformance with the American 

Society of Mechanical Engineers (ASME) Code, Section XI, Subsection IWB, Table IWB 2500-1 

(2001 edition5 including the 2002 and 2003 Addenda) and the recommendations of NUREG0619, and (b) system modifications and maintenance programs to mitigate cracking. The 

program specifies periodic liquid penetrant and ultrasonic inspection of critical regions of the 

boiling water reactor (BWR) control rod drive return line (CRDRL) nozzle. 

Evaluation and Technical Basis

1. Scope of Program: The program includes systems modifications, enhanced ISI, and 

maintenance programs to monitor the effects of cracking on the intended function of 

CRDRL nozzles.

2. Preventive Actions: Mitigation occurs by system modifications, such as rerouting the 

CRDRL to a system that connects to the reactor vessel. For some classes of BWRs, or 

those that can prove satisfactory system operation, mitigation is also accomplished by 

confirmation of proper return flow capability, two-pump operation, and cutting and capping 

the CRDRL nozzle without rerouting.

3. Parameters Monitored/ Inspected: The aging management program (AMP) monitors the 

effects of cracking on the intended function of the CRDRL nozzles by detecting and sizing 

cracks by ISI in accordance with Table IWB 2500-1 and NUREG-0619.

4. Detection of Aging Effects: The extent and schedule of inspection, as delineated in 

NUREG-0619, assures detection of cracks before the loss of intended function of the 

CRDRL nozzles. Inspection recommendations include liquid penetrant testing (PT) of 

CRDRL nozzle blend radius and bore regions and the reactor vessel wall area beneath 

the nozzle, return-flow-capacity demonstration, CRD-system-performance testing, and 

ultrasonic inspection of welded connections in the rerouted line. The inspection is to 

include base metal to a distance of one-pipe-wall thickness or 0.5 in., whichever is 

greater, on both sides of the weld.

5. Monitoring and Trending: The inspection schedule of NUREG-0619 provides timely 

detection of cracks.

6. Acceptance Criteria: Any cracking is evaluated in accordance with IWB-3100 by 

comparing inspection results with the acceptance standards of IWB-3400 and IWB-3500. 

All cracks found in the CRDRL nozzles are to be removed by grinding.

7. Corrective Actions: Repair is performed in conformance with IWB-4000 and replacement 

in accordance with IWB-7000. As discussed in the appendix to this report, the staff finds 

the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective 

actions.

 

5

An applicant may rely on a different version of the ASME Code, but should justify such use. An 

applicant may wish to refer to the SOC for an update of 10 CFR § 50.55a to justify use of a more recent 

edition of the Code.
September 2005 XI M-25 NUREG-1801, Rev. 1

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: Cracking has occurred in several BWR plants (NUREG-0619 and 

Information Notice 2004-08). The present AMP has been implemented for nearly 25 years 

and has been found to be effective in managing the effect of cracking on the intended 

function of CRDRL nozzles.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2005.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 2001 edition including the 2002 and 2003 Addenda, 

American Society of Mechanical Engineers, New York, NY.

NUREG-0619, BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking, 

U.S. Nuclear Regulatory Commission, November 1980.

NRC Information Notice 2004-08, Reactor Coolant Pressure Boundary Leakage Attributable To 

Propagation of Cracking In Reactor Vessel Nozzle Welds, , U.S. Nuclear Regulatory 

Commission, April 22, 2004.
NUREG-1801, Rev. 1 XI M-26 September 2005

XI.M7 BWR STRESS CORROSION CRACKING

Program Description

The program to manage intergranular stress corrosion cracking (IGSCC) in boiling water reactor 

(BWR) coolant pressure boundary piping made of stainless steel (SS) and nickel based alloy 

components is delineated in NUREG-0313, Rev. 2, and Nuclear Regulatory Commission (NRC) 

Generic Letter (GL) 88-01 and its Supplement 1. The material includes base metal and welds. 

The program includes (a) preventive measures to mitigate IGSCC, and (b) inspection and flaw 

evaluation to monitor IGSCC and its effects. The staff-approved boiling water reactor vessel and 

internals project (BWRVIP-75) report allows for modifications to the inspection scope in the GL 

88-01 program.

Evaluation and Technical Basis

1. Scope of Program: The program focuses on (a) managing and implementing 

countermeasures to mitigate IGSCC and (b) performing inservice inspection (ISI) to 

monitor IGSCC and its effects on the intended function of BWR components. The program 

is applicable to all BWR piping and piping welds made of austenitic SS and nickel alloy

that is 4 in. or larger in nominal diameter and contains reactor coolant at a temperature 

above 93°C (200°F) during power operation, regardless of code classification. The 

program also applies to pump casings, valve bodies and reactor vessel attachments and 

appurtenances, such as head spray and vent components. NUREG-0313 and NRC GL

88-01, respectively, describe the technical basis and staff guidance regarding mitigation of 

IGSCC in BWRs. Attachment A of NRC GL 88-01 delineates the staff-approved positions 

regarding materials, processes, water chemistry, weld overlay reinforcement, partial 

replacement, stress improvement of cracked welds, clamping devices, crack 

characterization and repair criteria, inspection methods and personnel, inspection 

schedules, sample expansion, leakage detection, and reporting requirements.

2. Preventive Actions: The comprehensive program outlined in NUREG-0313 and NRC 

GL 88-01 addresses improvements in all three elements that, in combination, cause 

IGSCC. These elements consist of a susceptible (sensitized) material, a significant tensile 

stress, and an aggressive environment. Sensitization of nonstabilized austenitic SSs 

containing greater than 0.03 wt.% carbon involves precipitation of chromium carbides at 

the grain boundaries during certain fabrication or welding processes. The formation of 

carbides creates an envelope of chromium depleted region that, in certain environments, 

is susceptible to stress corrosion cracking (SCC). Residual tensile stresses are introduced 

from fabrication processes, such as welding, surface grinding, or forming. High levels of 

dissolved oxygen or aggressive contaminants, such as sulfates or chlorides, accelerate 

the SCC processes.

The program delineated in NUREG-0313, NRC GL 88-01, and in the staff-approved 

BWRVIP-75 report includes recommendations regarding selection of materials that are 

resistant to sensitization, use of special processes that reduce residual tensile stresses, 

and monitoring and maintenance of coolant chemistry. The resistant materials are used 

for new and replacement components and include low-carbon grades of austenitic SS and 

weld metal, with a maximum carbon of 0.035 wt.% and a minimum ferrite of 7.5% in weld 

metal and cast austenitic stainless steel (CASS). Inconel 82 is the only commonly used 

nickel-base weld metal considered to be resistant to SCC; other nickel-alloys, such as 

Alloy 600 are evaluated on an individual basis. Special processes are used for existing, 
September 2005 XI M-27 NUREG-1801, Rev. 1

new, and replacement components. These processes include solution heat treatment, 

heat sink welding, induction heating, and mechanical stress improvement.

The program delineated in NUREG-0313 and NRC GL 88-01 does not provide specific 

guidelines for controlling reactor water chemistry to mitigate IGSCC. Maintaining high 

water purity reduces susceptibility to SCC or IGSCC. The program description, and 

evaluation and technical basis of monitoring and maintaining reactor water chemistry are

addressed through implementation of Section XI.M2, “Water Chemistry.”

3. Parameters Monitored/Inspected: The program detects and sizes cracks and detects 

leakage by using the examination and inspection guidelines delineated in NUREG-0313, 

Rev. 2, and NRC GL 88-01 or the referenced BWRVIP-75 guideline as approved by the 

NRC staff. 

4. Detection of Aging Effects: The extent, method, and schedule of the inspection and test 

techniques delineated in NRC GL 88-01 or BWRVIP-75 are designed to maintain 

structural integrity and ensure that aging effects will be discovered and repaired before the 

loss of intended function of the component. The inspection guidance in approved 

BWRVIP-75 replaces the extent and schedule of inspection in NRC GL 88-01. The 

program uses volumetric examinations to detect IGSCC. 

NRC GL 88-01 recommends that the detailed inspection procedure, components, and 

examination personnel be qualified by a formal program approved by the NRC. These 

inspection guidelines, updated in the approved BWRVIP-75 document, provide the 

technical basis for revisions to NRC GL 88-01 inspection schedules. Inspection can reveal 

cracking and leakage of coolant. The extent and frequency of inspection recommended by 

the program are based on the condition of each weld (e.g., whether the weldments were 

made from IGSCC-resistant material, whether a stress improvement process was applied 

to a weldment to reduce residual stresses, and how the weld was repaired if it had been 

cracked). 

5. Monitoring and Trending: The extent and schedule for inspection, in accordance with 

the recommendations of NRC GL 88-01 or approved BWRVIP-75 guidelines, provide 

timely detection of cracks and leakage of coolant. Based on inspection results, NRC 

GL 88-01 or approved BWRVIP-75 guidelines provide guidelines for additional samples of 

welds to be inspected when one or more cracked welds are found in a weld category.

6. Acceptance Criteria: As recommended in NRC GL 88-01, any indication detected is 

evaluated in accordance with ASME Section XI, IWB-3600 of Section XI of the 1986 

Edition of the ASME Boiler and Pressure Vessel Code and the guidelines of NUREG0313. 

Applicable and approved BWRVIP-14, BWRVIP-59, BWRVIP-60, and BWRVIP-62 

documents provide guidelines for evaluation of crack growth in SSs, nickel alloys, and 

low-alloy steels. An applicant may use BWRVIP-61 guidelines for BWR vessel and 

internals induction heating stress improvement effectiveness on crack growth in operating 

plants.

7. Corrective Actions: The guidance for weld overlay repair and stress improvement or 

replacement is provided in NRC GL 88-01; ASME Section XI, Subsections IWB-4000 and 

IWB-7000, IWC-4000 and IWC-7000, or IWD-4000 and IWD-7000, respectively for 

Class 1, 2, or 3 components; and ASME Code Case N-504-1. As discussed in the 
NUREG-1801, Rev. 1 XI M-28 September 2005

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address the corrective actions.

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: Intergranular stress corrosion cracking has occurred in smalland large-diameter BWR piping made of austenitic stainless steel and nickel-base alloys. 

Cracking has occurred in recirculation, core spray, residual heat removal (RHR), control 

rod drive (CRD) return line penetrations, and reactor water cleanup (RWCU) system 

piping welds (NRC GL 88-01, NRC Information Notices [INs] 82-39, 84-41, and 04-08). 

The comprehensive program outlined in NRC GL 88-01, NUREG-0313, and in the staffapproved BWRVIP-75 report addresses mitigating measures for SCC or IGSCC (e.g., 

susceptible material, significant tensile stress, and an aggressive environment). The GL 

88-01 program has been effective in managing IGSCC in BWR reactor coolant pressureretaining components and the revision to the GL 88-01 program, according to the staffapproved BWRVIP-75 report, will adequately manage IGSCC degradation.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2005.

ASME Code Case N-504-1, Alternative Rules for Repair of Class 1, 2, and 3 Austenitic 

Stainless Steel Piping, Section XI, Division 1, 1995 edition, ASME Boiler and Pressure 

Vessel Code – Code Cases – Nuclear Components, American Society of Mechanical 

Engineers, New York, NY.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 2001 edition including the 2002 and 2003 Addenda, 

American Society of Mechanical Engineers, New York, NY.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 1986 edition, American Society of Mechanical Engineers, 

New York, NY.

BWRVIP-14, Evaluation of Crack Growth in BWR Stainless Steel RPV Internals, 

(EPRI TR-105873, July 11, 2000), Final Safety Evaluation Report by the Office of Nuclear 

Reactor Regulation for BWRVIP-14, December 3, 1999.

BWRVIP-59, Evaluation of Crack Growth in BWR Nickel-Base Austenitic Alloys in RPV 

Internals, (EPRI TR-108710), March 24, 2000.
September 2005 XI M-29 NUREG-1801, Rev. 1

BWRVIP-60, BWR Vessel and Internals Project, Evaluation of Crack Growth in BWR Low Alloy 

Steel RPV Internals, (EPRI TR-108709, April 14, 2000), Final Safety Evaluation Report by 

the Office of Nuclear Reactor Regulation for BWRVIP-60, July 8, 1999.

BWRVIP-61, BWR Vessel and Internals Induction Heating Stress Improvement Effectiveness on 

Crack Growth in Operating Reactors, (EPRI TR-112076), January 29, 1999.

BWRVIP-62, BWR Vessel and Internals Project, Technical Basis for Inspection Relief for BWR 

Internal Components with Hydrogen Injection, (EPRI TR-108705), March 7, 2000.

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

(NUREG-0313), (EPRI TR-113932, Feb. 29, 2000), Initial Safety Evaluation Report by the 

Office of Nuclear Reactor Regulation for BWRVIP-75, September 15, 2000.

NRC Generic Letter 88-01, NRC Position on IGSCC in BWR Austenitic Stainless Steel Piping, 

U.S. Nuclear Regulatory Commission, January 25, 1988; Supplement 1, February 4, 1992.

NRC Information Notice 82-39, Service Degradation of Thick Wall Stainless Steel Recirculation 

System Piping at a BWR Plant, U.S. Nuclear Regulatory Commission, September 21, 1982.

NRC Information Notice 84-41, IGSCC in BWR Plants, U.S. Nuclear Regulatory Commission, 

June 1, 1984.

NRC Information Notice 04-08, Reactor Coolant Pressure Boundary Leakage Attributable to 

Propagation of Cracking in Reactor Vessel Nozzle Welds, U.S. Nuclear Regulatory 

Commission, April 22, 2004.

NUREG-0313, Rev. 2, Technical Report on Material Selection and Processing Guidelines for 

BWR Coolant Pressure Boundary Piping, W. S. Hazelton and W. H. Koo, U.S. Nuclear 

Regulatory Commission, 1988.
NUREG-1801, Rev. 1 XI M-30 September 2005

XI.M8 BWR PENETRATIONS

Program Description

The program includes (a) inspection and flaw evaluation in conformance with the guidelines of 

staff-approved boiling water reactor vessel and internals project BWRVIP-49 and BWRVIP27 documents, and (b) monitoring and control of reactor coolant water chemistry in accordance 

with the guidelines of BWRVIP-29 (Electric Power Research Institute [EPRI] TR-103515) to 

ensure the long-term integrity and safe operation of boiling water reactor (BWR) vessel internal 

components. BWRVIP-49 provides guidelines for instrument penetrations, and BWRVIP-27 

addresses the standby liquid control (SLC) system nozzle or housing.

Evaluation and Technical Basis

1. Scope of Program: The program is focused on managing the effects of cracking due to 

stress corrosion cracking (SCC) or intergranular stress corrosion cracking (IGSCC). The 

program contains preventive measures to mitigate SCC or IGSCC, inservice inspection 

(ISI) to monitor the effects of cracking on the intended function of the components, and 

repair and/or replacement as needed to maintain the ability to perform the intended 

function.

The inspection and evaluation guidelines of BWRVIP-49 and BWRVIP-27 contain generic 

guidelines intended to present appropriate inspection recommendations to assure safety 

function integrity. The guidelines of BWRVIP-49 provide information on the type of 

instrument penetration, evaluate their susceptibility and consequences of failure, and 

define the inspection strategy to assure safe operation. The guidelines of BWRVIP-27 are 

applicable to plants in which the SLC system injects sodium pentaborate into the bottom 

head region of the vessel (in most plants, as a pipe within a pipe of the core plate 

ΔP monitoring system). The BWRVIP-27 guidelines address the region where the ΔP and 

SLC nozzle or housing penetrates the vessel bottom head and include the safe ends 

welded to the nozzle or housing. Guidelines for repair design criteria are provided in 

BWRVIP-57 for instrumentation penetrations, and BWRVIP-53 for SLC line.

2. Preventive Actions: Maintaining high water purity reduces susceptibility to SCC or 

IGSCC. Reactor coolant water chemistry is monitored and maintained in accordance with 

the guidelines in BWRVIP-29 (EPRI TR-103515). The program description and the 

evaluation and technical basis of monitoring and maintaining reactor water chemistry are 

presented in Chapter XI.M2, “Water Chemistry.”

3. Parameters Monitored/Inspected: The program monitors the effects of SCC/IGSCC on 

the intended function of the component by detection and sizing of cracks by ISI in 

accordance with the guidelines of approved BWRVIP-49 or BWRVIP-27 and the 

requirements of the American Society of Mechanical Engineers (ASME) Code, Section XI, 

Table IWB 2500-1 (2001 edition6 including the 2002 and 2003 Addenda). An applicant 

may use the guidelines of BWRVIP-62 for inspection relief for vessel internal components 

with hydrogen water chemistry, provided that such relief is submitted under the provisions 

of 10 CFR 50.55a and approved by the staff.

 

6

An applicant may rely on a different version of the ASME Code, but should justify such use. An 

applicant may wish to refer to the SOC for an update of 10 CFR § 50.55a to justify use of a more recent 

edition of the Code.
September 2005 XI M-31 NUREG-1801, Rev. 1

4. Detection of Aging Effects: The evaluation guidelines of BWRVIP-49 and BWRVIP-27 

recommend that the inspection requirements currently in ASME Section XI continue to be 

followed. The extent and schedule of the inspection and test techniques prescribed by the 

ASME Section XI program are designed to maintain structural integrity and ensure that 

aging effects will be discovered and repaired before the loss of intended function of the 

component. Inspection can reveal cracking and leakage of coolant. The nondestructive 

examination (NDE) techniques appropriate for inspection of BWR vessel internals 

including the uncertainties inherent in delivering and executing NDE techniques in a BWR, 

are included in BWRVIP-03.

Instrument penetrations and SLC system nozzles or housings are inspected in 

accordance with the requirements of ASME Section XI, Subsection IWB. Components are 

examined and tested as specified in Table IWB-2500-1, examination categories B-E for 

pressure-retaining partial penetration welds in vessel penetrations, B-D for full penetration 

nozzle-to-vessel welds, B-F for pressure-retaining dissimilar metal nozzle-to-safe end 

welds, or B-J for similar metal nozzle-to-safe end welds. In addition, these components 

are part of examination category B-P for pressure-retaining boundary. Further details for 

examination are described in Chapter XI.M1, “ASME Section XI, Inservice Inspection, 

Subsections IWB, IWC, and IWD,” of this report.

5. Monitoring and Trending: Inspections scheduled in accordance with IWB-2400 and 

approved BWRVIP-48 or BWRVIP-27 provide timely detection of cracks. The scope of 

examination and reinspection must be expanded beyond the baseline inspection if flaws 

are detected.

6. Acceptance Criteria: Any indication detected is evaluated in accordance with ASME 

Section XI or other acceptable flaw evaluation criteria, such as the staff-approved 

BWRVIP-49 or BWRVIP-27 guidelines. Applicable and approved BWRVIP-14, BWRVIP59, and BWRVIP-60 documents provide guidelines for evaluation of crack growth in 

stainless steels (SSs), nickel alloys, and low-alloy steels, respectively.

7. Corrective Actions: Repair and replacement procedures in staff-approved BWRVIP-57 

and BWRVIP-53 are equivalent to those required in the ASME Section XI. Guidelines for 

repair design criteria are provided in BWRVIP-57 for instrumentation penetrations and 

BWRVIP-53 for standby liquid control line. As discussed in the appendix to this report, the 

staff finds that licensee implementation of the guidelines in BWRVIP-48, as modified, will 

provide an acceptable level of quality for inspection and flaw evaluation of the safetyrelated components addressed in accordance with 10 CFR Part 50, Appendix B, 

corrective actions.

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds that licensee implementation of the guidelines in BWRVIP-48, as modified, 

will provide an acceptable level of quality for inspection and flaw evaluation of the safetyrelated components addressed in accordance with the 10 CFR Part 50, Appendix B, 

confirmation process and administrative controls.

9. Administrative Controls: See Item 8, above.
NUREG-1801, Rev. 1 XI M-32 September 2005

10. Operating Experience: Cracking due to SCC or IGSCC has occurred in BWR 

components made of austenitic stainless steels and nickel alloys. The program guidelines 

are based on an evaluation of available information, including BWR inspection data and 

information about the elements that cause IGSCC, to determine which locations may be 

susceptible to cracking. Implementation of the program provides reasonable assurance 

that cracking will be adequately managed so the intended functions of the instrument 

penetrations and SLC system nozzles or housings will be maintained consistent with the 

current licensing basis CLB) for the period of extended operation.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2005.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 2001 edition including the 2002 and 2003 Addenda, 

American Society of Mechanical Engineers, New York, NY.

BWRVIP-03, BWR Vessel and Internals Project, Reactor Pressure Vessel and Internals 

Examination Guidelines (EPRI TR-105696 R1, March 30, 1999), Final Safety Evaluation 

Report by the Office of Nuclear Reactor Regulation for BWRVIP-03, July 15, 1999.

BWRVIP-14, Evaluation of Crack Growth in BWR Stainless Steel RPV Internals 

(EPRI TR-105873, July 11, 2000), Final Safety Evaluation Report by the Office of Nuclear 

Reactor Regulation for BWRVIP-14, December 3, 1999.

BWRVIP-27, BWR Vessel and Internals Project, BWR Standby Liquid Control System/Core 

Plate ?P Inspection and Flaw Evaluation Guidelines (EPRI TR-107286, April 1997), Final 

License Renewal Safety Evaluation Report by the Office of Nuclear Reactor Regulation for 

BWRVIP-27 for Compliance with the License Renewal Rule (10 CFR Part 54), 

December 20, 1999.

BWRVIP-29, BWR Vessel and Internals Project, BWR Water Chemistry Guidelines–1993 

Revision, Normal and Hydrogen Water Chemistry (EPRI TR-103515), Electric Power 

Research Institute, Palo Alto, CA, February 1994.

BWRVIP-48, BWR Vessel and Internals Project, Vessel ID Attachment Weld Inspection and 

Flaw Evaluation Guidelines (EPRI TR-108724, February 1998), Final License Renewal 

Safety Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-48 for 

Compliance with the License Renewal Rule (10 CFR Part 54), January 17, 2001.

BWRVIP-49, BWR Vessel and Internals Project, Instrument Penetration Inspection and Flaw 

Evaluation Guidelines (EPRI TR-108695, March 1998), Final License Renewal Safety 

Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-49 for 

Compliance with the License Renewal Rule (10 CFR Part 54), September 1, 1999.
September 2005 XI M-33 NUREG-1801, Rev. 1

BWRVIP-53, BWR Vessel and Internals Project, Standby Liquid Control Line Repair Design 

Criteria (EPRI TR-108716, March 24, 2000), Initial Safety Evaluation Report by the Office of 

Nuclear Reactor Regulation for BWRVIP-53, October 26, 2000.

BWRVIP-57, BWR Vessel and Internals Project, Instrument Penetration Repair Design Criteria 

(EPRI TR-108721), March 24, 2000.

BWRVIP-59, Evaluation of Crack Growth in BWR Nickel-Base Austenitic Alloys in RPV Internals 

(EPRI TR-108710), March 24, 2000.

BWRVIP-60, BWR Vessel and Internals Project, Evaluation of Crack Growth in BWR Low Alloy 

Steel RPV Internals (EPRI TR-108709, April 14, 2000), Final Safety Evaluation Report by 

the Office of Nuclear Reactor Regulation for BWRVIP-60, July 8, 1999.

BWRVIP-62, BWR Vessel and Internals Project, Technical Basis for Inspection Relief for BWR 

Internal Components with Hydrogen Injection (EPRI TR-108705), March 7, 2000.
NUREG-1801, Rev. 1 XI M-34 September 2005

XI.M9 BWR VESSEL INTERNALS

Program Description

The program includes (a) inspection and flaw evaluation in conformance with the guidelines of 

applicable and staff-approved boiling water reactor vessel and internals project (BWRVIP) 

documents, and (b) monitoring and control of reactor coolant water chemistry in accordance 

with the guidelines of BWRVIP-29 (Electric Power Research Institute [EPRI] TR-103515) to 

ensure the long-term integrity and safe operation of boiling water reactor (BWR) vessel internal 

components.

Evaluation and Technical Basis

1. Scope of Program: The program is focused on managing the effects of cracking due to 

stress corrosion cracking (SCC), intergranular stress corrosion cracking (IGSCC), or 

irradiation assisted stress corrosion cracking (IASCC). The program contains preventive 

measures to mitigate SCC, IGSCC, or IASCC, inservice inspection (ISI) to monitor the 

effects of cracking on the intended function of the components, and repair and/or 

replacement as needed to maintain the ability to perform the intended function of BWR 

vessel internals.

The BWRVIP documents provide generic guidelines intended to present the applicable 

inspection recommendations to assure safety function integrity of the subject safetyrelated reactor pressure vessel internal components. The guidelines include information 

on component description and function; evaluate susceptible locations and safety 

consequences of failure; provide recommendations for methods, extent, and frequency of 

inspection; discuss acceptable methods for evaluating the structural integrity significance 

of flaws detected during these examinations; and recommend repair and replacement 

procedures. 

The various applicable BWRVIP guidelines are as follows:

Core shroud: BWRVIPs-07, -63, and -76 provide guidelines for inspection and evaluation; 

BWRVIP-02, Rev. 2, provides guidelines for repair design criteria.

Core plate: BWRVIP-25 provides guidelines for inspection and evaluation; BWRVIP-50 

provides guidelines for repair design criteria.

Shroud support: BWRVIP-38 provides guidelines for inspection and evaluation; 

BWRVIP-52 provides guidelines for repair design criteria.

Low-pressure coolant injection (LPCI) coupling: BWRVIP-42 provides guidelines for 

inspection and evaluation; BWRVIP-56 provides guidelines for repair design criteria.

Top guide: BWRVIP-26 provides guidelines for inspection and evaluation; BWRVIP-50 

provides guidelines for repair design criteria. Additionally, for top guides with neutron 

fluence exceeding the IASCC threshold (5E20, E>lMeV) prior to the period of extended 

operation, inspect five percent (5%) of the top guide locations using enhanced visual 

inspection technique, EVT-1 within six years after entering the period of extended 

operation. An additional 5% of the top guide locations will be inspected within twelve years 

after entering the period of extended operation. 
September 2005 XI M-35 NUREG-1801, Rev. 1

Alternatively, if the neutron fluence for the limiting top guide location is projected to exceed 

the threshold for IASCC after entering the period of extended operation, inspect 5% of the 

top guide locations (EVT-1) within six years after the date projected for exceeding the 

threshold. An additional 5% of the top guide locations will be inspected within twelve years 

after the date projected for exceeding the threshold.

The top guide inspection locations are those that have high neutron fluences exceeding 

the IASCC threshold. The extent of the examination and its frequency will be based on a 

ten percent sample of the total population, which includes all grid beam and beam-tobeam crevice slots.

Core spray: BWRVIP-18 provides guidelines for inspection and evaluation; BWRVIP-16 

and 19 provides guidelines for replacement and repair design criteria, respectively.

Jet pump assembly: BWRVIP-41 provides guidelines for inspection and evaluation; 

BWRVIP-51 provides guidelines for repair design criteria.

Control rod drive (CRD) housing: BWRVIP-47 provides guidelines for inspection and 

evaluation; BWRVIP-58 provides guidelines for repair design criteria.

Lower plenum: BWRVIP-47 provides guidelines for inspection and evaluation; 

BWRVIP-57 provides guidelines for repair design criteria for instrument penetrations.

In addition, BWRVIP-44 provides guidelines for weld repair of nickel alloys; BWRVIP-45 

provides guidelines for weldability of irradiated structural components.

2. Preventive Actions: Maintaining high water purity reduces susceptibility to cracking due 

to SCC or IGSCC. Reactor coolant water chemistry is monitored and maintained in 

accordance with the guidelines in BWRVIP-29 (EPRI TR-103515). The program 

description and the evaluation and technical basis of monitoring and maintaining reactor 

water chemistry are presented in Chapter XI.M2, “Water Chemistry.”

3. Parameters Monitored/Inspected: The program monitors the effects of cracking on the 

intended function of the component by detection and sizing of cracks by inspection in 

accordance with the guidelines of applicable and approved BWRVIP documents and the 

requirements of the American Society of Mechanical Engineers (ASME) Code, Section XI, 

Table IWB 2500-1 (2001 edition7 including the 2002 and 2003 Addenda). An applicant 

may use the guidelines of BWRVIP-62 for inspection relief for vessel internal components 

with hydrogen water chemistry provided such relief is submitted under the provisions of 

10 CFR 50.55a and approved by the staff.

4. Detection of Aging Effects: The extent and schedule of the inspection and test 

techniques prescribed by the applicable and approved BWRVIP guidelines are designed 

to maintain structural integrity and ensure that aging effects will be discovered and 

repaired before the loss of intended function of BWR vessel internals. Inspection can 

reveal cracking. Vessel internal components are inspected in accordance with the 

 

7

An applicant may rely on a different version of the ASME Code, but should justify such use. An 

applicant may wish to refer to the SOC for an update of 10 CFR § 50.55a to justify use of a more recent 

edition of the Code.
NUREG-1801, Rev. 1 XI M-36 September 2005

requirements of ASME Section XI, Subsection IWB, examination category B-N-2. The 

ASME Section XI inspection specifies visual VT-1 examination to detect discontinuities 

and imperfections, such as cracks, corrosion, wear, or erosion, on the surfaces of 

components. This inspection also specifies visual VT-3 examination to determine the 

general mechanical and structural condition of the component supports by (a) verifying 

parameters, such as clearances, settings, and physical displacements, and (b) detecting 

discontinuities and imperfections, such as loss of integrity at bolted or welded 

connections, loose or missing parts, debris, corrosion, wear, or erosion.

The applicable and approved BWRVIP guidelines recommend more stringent inspections, 

such as enhanced visual VT-1 examinations or ultrasonic methods of volumetric 

inspection, for certain selected components and locations. The nondestructive 

examination (NDE) techniques appropriate for inspection of BWR vessel internals 

including the uncertainties inherent in delivering and executing NDE techniques in a BWR, 

are included in BWRVIP-03.

5. Monitoring and Trending: Inspections scheduled in accordance with the applicable and 

approved BWRVIP guidelines provide timely detection of cracks. The scope of 

examination and reinspection must be expanded beyond the baseline inspection if flaws 

are detected.

6. Acceptance Criteria: Any indication detected is evaluated in accordance with ASME 

Section XI or the applicable staff-approved BWRVIP guidelines. Approved BWRVIP-14, 

BWRVIP-59, and BWRVIP-60 documents provide guidelines for evaluation of crack 

growth in stainless steels (SSs), nickel alloys, and low-alloy steels, respectively.

7. Corrective Actions: Repair and replacement procedures are equivalent to those 

requirements in ASME Section XI. Repair and replacement is performed in conformance 

with the applicable and approved BWRVIP guidelines listed above. As discussed in the 

appendix to this report, the staff finds that licensee implementation of the guidelines in the 

staff-approved BWRVIP reports will provide an acceptable level of quality for inspection 

and flaw evaluation of the safety-related components addressed in accordance with 

10 CFR Part 50, Appendix B, corrective actions.

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds that licensee implementation of the guidelines in the staff-approved 

BWRVIP reports will provide an acceptable level of quality for inspection and flaw 

evaluation of the safety-related components addressed in accordance with the 10 CFR 

Part 50, Appendix B, confirmation process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: Extensive cracking has been observed in core shrouds at both 

horizontal (Nuclear Regulatory Commission [NRC] Generic Letter [GL] 94-03) and vertical 

(NRC Information Notice [IN] 97-17) welds. It has affected shrouds fabricated from Type 

304 and Type 304L SS, which is generally considered to be more resistant to SCC. Weld 

regions are most susceptible to SCC, although it is not clear whether this is due to 

sensitization and/or impurities associated with the welds or the high residual stresses in 
September 2005 XI M-37 NUREG-1801, Rev. 1

the weld regions. This experience is reviewed in NRC GL 94-03 and NUREG-1544; some 

experiences with visual inspections are discussed in NRC IN 94-42.

Both circumferential (NRC IN 88-03) and radial cracking (NRC IN 92-57) has been 

observed in the shroud support access hole cover made from Alloy 600. Instances of 

cracking in core spray spargers have been reviewed in NRC Bulletin 80-13.

Cracking of the core plate has not been reported, but the creviced regions beneath the 

plate are difficult to inspect. NRC IN 95-17 discusses cracking in top guides of 

United States and overseas BWRs. Related experience in other components is reviewed 

in NRC GL 94-03 and NUREG-1544. Cracking has also been observed in the top guide of 

a Swedish BWR.

Instances of cracking have occurred in the jet pump assembly (NRC Bulletin 80-07), holddown beam (NRC IN 93-101), and jet pump riser pipe elbows (NRC IN 97-02).

Cracking of dry tubes has been observed at 14 or more BWRs. The cracking is 

intergranular and has been observed in dry tubes without apparent sensitization, 

suggesting that IASCC may also play a role in the cracking.

The program guidelines outlined in applicable and approved BWRVIP documents are 

based on an evaluation of available information, including BWR inspection data and 

information on the elements that cause SCC, IGSCC, or IASCC, to determine which 

components may be susceptible to cracking. Implementation of the program provides 

reasonable assurance that cracking will be adequately managed so the intended functions 

of the vessel internal components will be maintained consistent with the current licensing 

basis (CLB) for the period of extended operation.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2005.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 2001 edition including the 2002 and 2003 Addenda, 

American Society of Mechanical Engineers, New York, NY.

BWRVIP-02, BWR Vessel and Internals Project, BWR Core Shroud Repair Design Criteria, 

Rev. 2, March 7, 2000.

BWRVIP-03, BWR Vessel and Internals Project, Reactor Pressure Vessel and Internals 

Examination Guidelines (EPRI TR-105696 R1, March 30, 1999), Final Safety Evaluation 

Report by the Office of Nuclear Reactor Regulation for BWRVIP-03, July 15, 1999.

BWRVIP-07, BWR Vessel and Internals Project, Guidelines for Reinspection of BWR Core 

Shrouds (EPRI TR-105747, Feb. 29, 1996), Final Safety Evaluation Report by the Office of 

Nuclear Reactor Regulation for BWRVIP-07, April 27, 1998.
NUREG-1801, Rev. 1 XI M-38 September 2005

BWRVIP-14, Evaluation of Crack Growth in BWR Stainless Steel RPV Internals 

(EPRI TR-105873, July 11, 2000), Final Safety Evaluation Report by the Office of Nuclear 

Reactor Regulation for BWRVIP-14, December 3, 1999.

BWRVIP-16, Internal Core Spray Piping and Sparger Replacement Design Criteria 

(EPRI TR-106708), March 7, 2000.

BWRVIP-18, BWR Vessel and Internals Project, BWR Core Spray Internals Inspection and Flaw 

Evaluation Guidelines (EPRI TR-106740, July 1996), Final License Renewal Safety 

Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-18 for 

Compliance with the License Renewal Rule (10 CFR Part 54), December 7, 2000.

BWRVIP-19, Internal Core Spray Piping and Sparger Repair Design Criteria (EPRI TR 106893), 

March 7, 2000.

BWRVIP-25, BWR Vessel and Internals Project, BWR Core Plate Inspection and Flaw 

Evaluation Guidelines (EPRI TR-107284, Dec. 1996), Final License Renewal Safety 

Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-25 for 

Compliance with the License Renewal Rule (10 CFR Part 54), December 7, 2000.

BWRVIP-26, BWR Vessel and Internals Project, Top Guide Inspection and Flaw Evaluation 

Guidelines (EPRI TR-107285, Dec. 1996), Final License Renewal Safety Evaluation Report 

by the Office of Nuclear Reactor Regulation for BWRVIP-26 for Compliance with the License 

Renewal Rule (10 CFR Part 54), December 7, 2000.

BWRVIP-29, BWR Vessel and Internals Project, BWR Water Chemistry Guidelines–1993 

Revision, Normal and Hydrogen Water Chemistry (EPRI TR-103515), February 1994.

BWRVIP-38, BWR Vessel and Internals Project, BWR Shroud Support Inspection and Flaw 

Evaluation Guidelines (EPRI TR-108823, September 1997), Final License Renewal Safety 

Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-38 for 

Compliance with the License Renewal Rule (10 CFR Part 54), March 1, 2001.

BWRVIP-41, BWR Vessel and Internals Project, BWR Jet Pump Assembly Inspection and Flaw 

Evaluation Guidelines (EPRI TR-108728, October 1997), Final License Renewal Safety 

Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-41 for 

Compliance with the License Renewal Rule (10 CFR Part 54), June 15, 2001.

BWRVIP-42, BWR Vessel and Internals Project, BWR LPCI Coupling Inspection and Flaw 

Evaluation Guidelines (EPRI TR-108726, December 1997), Final License Renewal Safety 

Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-42 for 

Compliance with the License Renewal Rule (10 CFR Part 54), January 9, 2001.

BWRVIP-44, Underwater Weld Repair of Nickel Alloy Reactor Vessel Internals 

(EPRI TR-108708, April 3, 2000), Final Safety Evaluation Report by the Office of Nuclear 

Reactor Regulation for BWRVIP-44, June 9, 1999.

BWRVIP-45, Weldability of Irradiated LWR Structural Components (EPRI TR-108707), June 14, 

2000.
September 2005 XI M-39 NUREG-1801, Rev. 1

BWRVIP-47, BWR Vessel and Internals Project, BWR Lower Plenum Inspection and Flaw 

Evaluation Guidelines (EPRI TR-108727, December 1997), Final License Renewal Safety 

Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-47 for 

Compliance with the License Renewal Rule (10 CFR Part 54), December 7, 2000.

BWRVIP-50, Top Guide/Core Plate Repair Design Criteria (EPRI TR-108722), April 3, 2000.

BWRVIP-51, Jet Pump Repair Design Criteria (EPRI TR-108718, March 7, 2000), Initial Safety 

Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-51, 

October 28, 2000.

BWRVIP-52, Shroud Support and Vessel Bracket Repair Design Criteria (EPRI TR-108720, 

June 26, 1998), Initial Safety Evaluation Report by the Office of Nuclear Reactor Regulation 

for BWRVIP-52, November 2, 2000.

BWRVIP-56, LPCI Coupling Repair Design Criteria (EPRI TR-108717), March 24, 2000.

BWRVIP-57, Instrument Penetration Repair Design Criteria (EPRI TR-108721), BWRVIP and 

Electric Power Research Institute, Palo Alto, CA, March 24, 2000.

BWRVIP-58, CRD Internal Access Weld Repair (EPRI TR-108703, March 7, 2000.

BWRVIP-59, Evaluation of Crack Growth in BWR Nickel-Base Austenitic Alloys in RPV Internals 

(EPRI TR-108710), March 24, 2000.

BWRVIP-60, BWR Vessel and Internals Project, Evaluation of Crack Growth in BWR Low Alloy 

Steel RPV Internals (EPRI TR-108709, April 14, 2000), Final Safety Evaluation Report by 

the Office of Nuclear Reactor Regulation for BWRVIP-60, July 8, 1999.

BWRVIP-62, BWR Vessel and Internals Project, Technical Basis for Inspection Relief for BWR 

Internal Components with Hydrogen Injection (EPRI TR-108705), March 7, 2000.

BWRVIP-63, BWR Vessel and Internals Project, Shroud Vertical Weld Inspection and 

Evaluation Guidelines (EPRI TR-113117, Feb. 29, 2000), Initial Safety Evaluation Report by 

the Office of Nuclear Reactor Regulation for BWRVIP-63, April 18, 2000.

BWRVIP-76, BWR Vessel and Internals Project, BWR Core Shroud Inspection and Flaw 

Evaluation Guidelines (EPRI TR-114232, November 1999).

NRC Generic Letter 94-03, Intergranular Stress Corrosion Cracking of Core Shrouds in Boiling 

Water Reactors, U.S. Nuclear Regulatory Commission, July 25, 1994.

NRC Bulletin No. 80-07, BWR Jet Pump Assembly Failure, U.S. Nuclear Regulatory 

Commission, April 4, 1980.

NRC Bulletin No. 80-13, Cracking in Core Spray Spargers, U.S. Nuclear Regulatory 

Commission, May 12, 1980.

NRC Bulletin No. 80-07, Supplement 1, BWR Jet Pump Assembly Failure, U.S. Nuclear 

Regulatory Commission, May 13, 1980.
NUREG-1801, Rev. 1 XI M-40 September 2005

NRC Information Notice 88-03, Cracks in Shroud Support Access Hole Cover Welds, 

U.S. Nuclear Regulatory Commission, February 2, 1988.

NRC Information Notice 92-57, Radial Cracking of Shroud Support Access Hole Cover Welds, 

U.S. Nuclear Regulatory Commission, August 11, 1992.

NRC Information Notice 93-101, Jet Pump Hold-Down Beam Failure, U.S. Nuclear Regulatory 

Commission, December 17, 1993.

NRC Information Notice 94-42, Cracking in the Lower Region of the Core Shroud in Boiling 

Water Reactors, U.S. Nuclear Regulatory Commission, June 7, 1994.

NRC Information Notice 95-17, Reactor Vessel Top Guide and Core Plate Cracking, 

U.S. Nuclear Regulatory Commission, March 10, 1995.

NRC Information Notice 97-02, Cracks Found in Jet Pump Riser Assembly Elbows at Boiling 

Water Reactors, U.S. Nuclear Regulatory Commission, February 6, 1997.

NRC Information Notice 97-17, Cracking of Vertical Welds in the Core Shroud and Degraded 

Repair, U.S. Nuclear Regulatory Commission, April 4, 1997.

NUREG-1544, Status Report: Intergranular Stress Corrosion Cracking of BWR Core Shrouds 

and Other Internal Components, U.S. Nuclear Regulatory Commission, March 1996.
September 2005 XI M-41 NUREG-1801, Rev. 1

XI.M10 BORIC ACID CORROSION

Program Description

The program relies in part on implementation of recommendations in Nuclear Regulatory 

Commission (NRC) Generic Letter (GL) 88-05 to monitor the condition of the reactor coolant 

pressure boundary for borated water leakage. Periodic visual inspection of adjacent structures, 

components, and supports for evidence of leakage and corrosion is an element of the NRC 

GL 88-05 monitoring program. Potential improvements to boric acid corrosion programs have 

been identified as a result of recent operating experience with cracking of certain nickel alloy 

pressure boundary components (NRC Regulatory Issue Summary 2003-013).

Borated water leakage from piping and components that are outside the scope of the program 

established in response to GL 88-05 may affect structures and components that are subject to 

aging management review. Therefore, the scope of the monitoring and inspections of this 

program includes all components that contain borated water that are in proximity to structures 

and components that are subject to aging management review. The scope of the evaluations, 

assessments and corrective actions include all observed leakage sources and the affected 

structures and components.

Borated water leakage may be discovered by activities other than those established specifically 

to detect such leakage. Therefore, the program includes provisions for triggering evaluations 

and assessments when leakage is discovered by other activities.

Evaluation and Technical Basis

1. Scope of Program: The program covers any structures or components on which boric 

acid corrosion may occur (e.g., steel and aluminum), and electrical components on which 

borated reactor water may leak. The program includes provisions in response to the 

recommendations of NRC GL 88-05. The staff guidance of NRC GL 88-05 provides a 

program consisting of systematic measures to ensure that corrosion caused by leaking 

borated coolant does not lead to degradation of the leakage source or adjacent structures 

and components, and provides assurance that the reactor coolant pressure boundary will 

have an extremely low probability of abnormal leakage, rapidly propagating failure, or 

gross rupture. Such a program provides for (a) determination of the principal location of 

leakage, (b) examination requirements and procedures for locating small leaks, and 

(c) engineering evaluations and corrective actions to ensure that boric acid corrosion does 

not lead to degradation of the leakage source or adjacent structures or components, 

which could cause the loss of intended function of the structures or components. 

2. Preventive Actions: Minimizing reactor coolant leakage by frequent monitoring of the 

locations where potential leakage could occur and timely repair if leakage is detected 

prevents or mitigates boric acid corrosion. Preventive measures also include modifications 

in the design or operating procedures to reduce the probability of leaks at locations where 

they may cause corrosion damage and use of suitable corrosion resistant materials or the 

application of protective coatings.

3. Parameters Monitored/Inspected: The aging management program (AMP) monitors the 

effects of boric acid corrosion on the intended function of an affected structure and 

component by detection of borated water leakage. Borated water leakage results in 
NUREG-1801, Rev. 1 XI M-42 September 2005

deposits of white boric acid crystals and the presence of moisture that can be observed by 

the naked eye.

4. Detection of Aging Effects: Degradation of the component due to boric acid corrosion 

cannot occur without leakage of borated water. Conditions leading to boric acid corrosion, 

such as crystal buildup and evidence of moisture, are readily detectable by visual 

inspection, though removal of insulation may be required in some cases. The program 

delineated in NRC GL 88-05 includes guidelines for locating small leaks, conducting 

examinations, and performing engineering evaluations. In addition, the program includes 

appropriate interfaces with other site programs and activities such that borated water 

leakage that is encountered by means other than the monitoring and trending established 

by this program is evaluated and corrected. Thus, the use of the NRC GL 88-05 program 

will assure detection of leakage before the loss of the intended function of the affected 

components.

5. Monitoring and Trending: The program provides monitoring and trending activities as 

delineated in NRC GL 88-05, timely evaluation of evidence of borated water leakage 

identified by other means, and timely detection of leakage by observing boric acid crystals 

during normal plant walkdowns and maintenance. 

6. Acceptance Criteria: Any detected borated water leakage or crystal buildup will be 

evaluated to confirm or restore the intended functions of affected structures and 

components consistent with the design basis prior to continued service.

7. Corrective Actions: Borated water leakage and areas of resulting boric acid corrosion 

are evaluated and corrected in conformance with the applicable provisions of NRC 

GL 88-05 and the corrective action program. Any detected boric acid crystal buildup or 

deposits should be cleaned. NRC GL 88-05 recommends that corrective actions to 

prevent recurrences of degradation caused by borated water leakage be included in the 

program implementation. These corrective actions include any modifications to be 

introduced in the present design or operating procedures of the plant that (a) reduce the 

probability of primary coolant leaks at locations where they may cause corrosion damage, 

and (b) entail the use of suitable corrosion resistant materials or the application of 

protective coatings or claddings. As discussed in the appendix to this report, the staff finds 

the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective 

actions.

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address 

confirmation process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: Boric acid corrosion has been observed in nuclear power plants 

(NRC Information Notices [INs] 86-108 [and supplements 1 through 3] and 2003-02) and 

has resulted in significant impairment of component intended functions in areas that are 

difficult to access/observe (NRC Bulletin 2002-01). 
September 2005 XI M-43 NUREG-1801, Rev. 1

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2005.

NRC Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary 

Components in PWR Plants, U.S. Nuclear Regulatory Commission, March 17, 1988.

NRC Information Notice 86-108 S3, Degradation of Reactor Coolant System Pressure Boundary 

Resulting from Boric Acid Corrosion, U.S. Nuclear Regulatory Commission, December 26, 

1986; Supplement 1, April 20, 1987; Supplement 2, November 19, 1987; and Supplement 3, 

January 5, 1995.

NRC Bulletin 2002-01: Reactor Pressure Vessel Head Degradation and Reactor Coolant 

Pressure Boundary Integrity, U.S. Nuclear Regulatory Commission, March 18, 2002.

NRC Bulletin 2002-02: Reactor Pressure Vessel Head and Vessel Head Penetration Nozzle 

Inspection Programs, U.S. Nuclear Regulatory Commission, August 9, 2002.

NRC Information Notice 2002-11: Recent Experience with Degradation of Reactor Pressure 

Vessel Head, U.S. Nuclear Regulatory Commission, March 12, 2002.

NRC Information Notice 2002-13: Possible Indicators of Ongoing Reactor Pressure Vessel 

Head Degradation, U.S. Nuclear Regulatory Commission, April 4, 2002.

NRC Information Notice 2003-02: Recent Experience with Reactor Coolant System Leakage 

and Boric Acid Corrosion, U.S. Nuclear Regulatory Commission, January 16, 2003.

NRC Regulatory Issue Summary 2003-013: NRC Review of Responses to Bulletin 2002-01, 

'Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary 

Integrity,' U.S. Nuclear Regulatory Commission, July 29, 2003.
NUREG-1801, Rev. 1 XI M-44 September 2005

XI.M11 NICKEL-ALLOY NOZZLES AND PENETRATIONS

This AMP has been replaced in part by AMP 11A, “Nickel-Alloy Penetration Nozzles Welded to 

the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors (PWRs only).” 

Guidance for the aging management of other nickel-alloy nozzles and penetrations is provided 

in the AMR line items of Chapter IV, as appropriate.
September 2005 XI M-45 NUREG-1801, Rev. 1

XI.M11A NICKEL-ALLOY PENETRATION NOZZLES WELDED TO THE UPPER REACTOR 

VESSEL CLOSURE HEADS OF PRESSURIZED WATER REACTORS (PWRS Only)

Program Description

This program is established to ensure that augmented inservice inspections (ISI) of all nickelalloy vessel head penetration (VHP) nozzles welded to the upper reactor vessel (RV) head of a 

PWR-designed light-water reactor will continue to be performed as mandated by the interim 

requirements in Order EA-03-009, “Issuance of Order Establishing Interim Inspection 

Requirements for Reactor Pressure Vessel Heads at Pressurized Water Reactors (PWRs),” as 

amended by the First Revision of the Order, or by any subsequent NRC requirements that may 

be established to supersede the requirements of Order EA-03-009.

Since 1997, the Nuclear Regulatory Commission (NRC) has issued a number of generic 

communications on the topic of primary water stress corrosion cracking (PWSCC) in upper VHP 

nozzles. These generic communications included issuance of NRC Generic Letter (GL) 97-01, 

Bulletin 2001-01, Bulletin 2002-01, and Bulletin 2002-02. In response to its reviews of the 

industry’s responses to these generic communications, the staff determined that PWSCCinduced cracking of upper VHP nozzles was a significant safety issue for operating PWRs that 

warranted issuance of an NRC Order for augmented inspection of PWR upper VHP nozzles and 

upper RV heads. 

On February 11, 2003, the Commission issued Order EA-03-009 to all holders of PWR 

operating licenses. Order EA-03-009 was issued in accordance with the regulatory bases and 

requirements of 10 CFR 2.202 and the adequate protection backfit provisions of 10 CFR 

50.109. In this Order, the NRC required specific augmented inspections of reactor vessel 

closure heads and the associated nickel-alloy penetration nozzles in U.S. PWRs. The NRC 

issued the First Revised Order EA-03-009 on February 20, 2004, to clarify which locations of the 

PWR vessel head penetration nozzles were applicable to the requirements of the Order. All 

PWR licensees in the U.S. were required to submit 20-day and 60-day responses to Order EA03-009 and to First Revised Order EA-03-009 (henceforth referred to in this document 

collectively as “the Order, as amended”).

The Order, as amended, established a mandated augmented inspection process for upper VHP 

nozzles and upper RV heads that supplements the leakage tests and visual VT-2 examinations 

requirements established in Section XI of the ASME Boiler and Pressure Vessel Code, Table 

IWB-2500-1, Examination Category B-P. The interim requirements of the Order, as amended, 

also established the NRC’s required technical method for calculating the susceptibility ranking of 

a plant’s upper VHP nozzles to PWSCC and a required process for establishing the inspection 

methods and inspection frequencies for a plant’s VHP nozzles in accordance with its 

susceptibility ranking.

Evaluation and Technical Basis

Scope of Program: The program is focused on managing the effects of cracking due to 

PWSCC of the nickel-alloy used in the fabrication of the upper VHP nozzles at PWR-designed 

nuclear facilities. The scope of this AMP is limited to upper VHP nozzles, including control rod 

drive mechanism (CRDM) nozzles, control element drive mechanism (CEDM) nozzles, 

thermocouples (TC) nozzles, in-core instrumentation (ICI) nozzles, and vent line nozzles; 

associated J-groove welds; and the adjoining upper RV closure head. 
NUREG-1801, Rev. 1 XI M-46 September 2005

1. Preventive Actions: Preventive measures to mitigate PWSCC are in accordance with 

PWR water chemistry guidelines for primary coolant systems, as established in EPRI 

Topical Report TR-105714 (applicants for license renewal may credit the version of the 

report on record at the facility at the time of submittal of its application). The program 

description and the evaluation and technical basis of monitoring and maintaining reactor 

coolant water chemistry are presented in Chapter XI.M2, "Water Chemistry."

2. Parameters Monitored/Inspected: The program monitors for cracking/PWSCC and loss 

of material/wastage in the upper VHP nozzles to ensure the structural integrity of the VHP 

nozzles prior to a loss of their intended safety function. The program also monitors for 

evidence of reactor coolant leakage as a result of through-wall cracks that may exist in the 

upper VHP nozzles or their associated partial penetration J-groove welds. Evidence of 

reactor coolant leakage may manifest itself in the form of boric acid residues on the upper 

RV head or adjacent components or in the form of corrosion products that result from 

rusting of the low-alloy steel materials used to fabricate the RVs.

3. Detection of Aging Effects: Implementation of inspections required by the Order, as 

amended, or any subsequent NRC requirements, as applicable, assures detection of 

cracks in the upper VHP nozzles and any loss of material/wastage of the upper RV head 

prior to a loss of intended function of the components. Detection of cracking (including 

those induced by PWSCC) is accomplished through implementation of a combination of 

bare-metal visual examination and/or non-visual examination techniques, as discussed in 

the Order, as amended. Bare-metal visual examinations required by the Order, as 

amended, are used to detect reactor coolant leakage from the VHP nozzles or their 

associated J-groove welds and for any loss of material that may be induced as a result of 

boric-acid wastage. Non-visual examination techniques required by the Order, as 

amended, are also used to detect these aging effects and are performed using either 

surface examination techniques (eddy current or penetrant testing) or volumetric 

examination techniques (ultrasonic testing).

The specific types of examinations to be implemented are dependent on a plant’s 

susceptibility ranking for its VHP nozzles. Inspection methods selected for examination 

are implemented in accordance with appropriate inspection requirements of Section IV.C 

of the Order, as amended, as applicable for a plant’s susceptibility ranking (i.e., in 

accordance with the appropriate inspection methods mandated for “Low,” “Moderate,” 

“High,” or “Replaced” susceptibility category plants). Any deviations from implementing the 

appropriate required inspection methods of the Order, as amended, will be submitted for 

NRC review and approval in accordance with the Order, as amended.

4. Monitoring and Trending: As required by the Order, as amended, inspection schedules 

and frequencies for the applicant’s VHP nozzles are implemented in accordance with 

required frequencies for the plant’s susceptibility category (i.e., in accordance with the 

specific inspection frequencies required for “Low,” “Moderate,” “High,” or “Replaced” 

susceptibility categories, as based on the “total effective degradation years”). Any 

deviations from implementing the required inspection frequencies mandated by the Order, 

as amended, will be submitted for NRC review and approval in accordance with the Order, 

as amended. Disposition of flaw indications detected during required examinations is 

implemented in accordance with the Acceptance Criteria and Corrective Actions program 

attributes of this AMP.
September 2005 XI M-47 NUREG-1801, Rev. 1

5. Acceptance Criteria: Relevant flaw indications detected as a result of the augmented 

inspections of the upper VHP nozzles are to be evaluated in accordance with acceptable 

law evaluation criteria provided in a letter from Mr. Richard Barrett, NRC, Office of Nuclear 

Reactor Regulation (NRR), Division of Engineering to Alex Marion, Nuclear Energy 

Institute (NEI), dated April 11, 2003, or in accordance with NRC-approved Code Cases 

that incorporate the flaw evaluation procedures and criteria of the NRC’s April 11, 2003, 

letter to NEI. 

7. Corrective Actions: Relevant flaw indications in the upper VHP nozzles or their 

associated nickel-alloy J-groove weld materials are unacceptable for further service and 

are corrected through implementation of appropriate repair or replacement activities. In 

addition, detection of leakage or evidence of cracking in the VHP nozzles (including 

associated J-groove welds) of plants ranked in the “Low,” “Moderate,” or “Replaced” 

susceptibility categories requires that the plant’s VHP nozzles be immediately reclassified 

to the “High” susceptibility category and that the required augmented inspections for “High” 

susceptibility VHP nozzles be implemented, commencing from the same outage in which 

the leakage or cracking was detected.

Repair and replacement procedures and activities either must comply with ASME 

Section XI, as invoked by the requirements of 10 CFR 50.55a, or conform with applicable 

ASME Code Cases that have been endorsed in 10 CFR 50.55a by reference in the latest 

version of NRC Regulatory Guide 1.147. Alternative repair/replacement activities 

suggested instead of those endorsed by the NRC in either Section XI or NRC-approved 

Code Cases must be requested for NRC approval in accordance with either the 

acceptable alternative provisions of 10 CFR 50.55a(a)(3)(i) or hardship provisions of 10 

CFR 50.55a(a)(3)(ii). 

As discussed in the appendix to this report, the staff finds the requirements of 10 CFR 

Part 50, Appendix B, “Quality Assurance Criteria for Nuclear Power Plants and Fuel 

Reprocessing Plants,” acceptable to address the corrective actions. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes are implemented in accordance with the requirements of 10 CFR Part 50, 

Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 

10 CFR Part 50, Appendix B, “Quality Assurance Criteria for Nuclear Power Plants and 

Fuel Reprocessing Plants,” acceptable to address confirmation process and administrative 

controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: PWSCC is occurring in the VHP nozzles of U.S. PWRs, as

described in the program description above. In addition, applicants for license renewal 

should reference plant-specific operating experience that is applicable to PWSCC of its 

VHP nozzles.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.
NUREG-1801, Rev. 1 XI M-48 September 2005

10 CFR Part 50.55a, Codes and Standards, Office of the Federal Register, National Archives 

and Records Administration, 2005. 

EPRI TR-105714, PWR Primary Water Chemistry Guidelines, Electric Power Research Institute, 

Palo Alto, CA.

Letter from R. Barrett, NRC Office of Nuclear Reactor Regulation (NRR), Division of 

Engineering to Alex Marion, Nuclear Energy Institute, Flaw Evaluation Guidelines, April 11, 

2003 (ADAMS Accession Nos. ML030980322 and ML030980333).

Order EA 03-009, Issuance of Order Establishing Interim Inspection Requirements for Reactor 

Pressure Vessel Heads at Pressurized Water Reactors, February 11, 2003. 

First Revised Order EA-03-009, Issuance of Revised Order EA-09-003 Establishing Interim

Inspection Requirements for Reactor Pressure Vessel Heads at Pressurized Water

Reactors, February 20, 2004.

Bulletin 2001-01, Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure 

Boundary Integrity, U.S. Nuclear Regulatory Commission, August 3, 2001. 

Bulletin 2002-01, Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure 

Boundary Integrity, U.S. Nuclear Regulatory Commission, March 18, 2002. 

Bulletin 2002-02, Reactor Pressure Vessel Head and Vessel Head Penetration Nozzle

Inspection Programs, U.S. Nuclear Regulatory Commission, August 9, 2002.

Generic Letter (GL) 97-01, Degradation of Control Rod Drive Mechanism Nozzle and Other

Vessel Closure Head Penetrations, U.S. Nuclear Regulatory Commission, April 1, 1997.

Information Notice 2003-02, Recent Experience with Reactor Coolant System Leakage and

Boric Acid Corrosion, U.S. Nuclear Regulatory Commission, January 16, 2003.

Information Notice 2002-13, Possible Indicators of Ongoing Reactor Pressure Vessel Head

Degradation, April 4, 2002.

Information Notice 2002-11, Recent Experience with Degradation of Reactor Pressure Vessel 

Head, U.S. Nuclear Regulatory Commission, March 12, 2002.

Information Notice 2001-05, Through-Wall Circumferential Cracking of Reactor Pressure Vessel 

Head Control Rod Drive Mechanism Penetration Nozzles at Oconee Nuclear Station, Unit 3, 

U.S. Nuclear Regulatory Commission, April 30, 2001.

Regulatory Guide 1.147, Revision 13, Inservice Inspection Code Case Acceptability, ASME

Section XI, Division 1, January 2004.
September 2005 XI M-49 NUREG-1801, Rev. 1

XI.M12 THERMAL AGING EMBRITTLEMENT OF CAST AUSTENITIC STAINLESS STEEL 

(CASS)

Program Description

The reactor coolant system components are inspected in accordance with the American Society 

of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section XI. This inspection 

is augmented to detect the effects of loss of fracture toughness due to thermal aging 

embrittlement of cast austenitic stainless steel (CASS) components. This aging management 

program (AMP) includes (a) determination of the susceptibility of CASS components to thermal 

aging embrittlement based on casting method, molybdenum content, and percent ferrite, and 

(b) for “potentially susceptible” components, as defined below, aging management is 

accomplished through either enhanced volumetric examination or plant- or component-specific 

flaw tolerance evaluation. Additional inspection or evaluations to demonstrate that the material 

has adequate fracture toughness are not required for components that are not susceptible to 

thermal aging embrittlement.

For pump casings and valve bodies, based on the assessment documented in the letter dated 

May 19, 2000, from Christopher Grimes, Nuclear Regulatory Commission (NRC), to Douglas 

Walters, Nuclear Energy Institute (NEI), screening for susceptibility to thermal aging is not 

required. The existing ASME Section XI inspection requirements, including the alternative 

requirements of ASME Code Case N-481 for pump casings, are adequate for all pump casings 

and valve bodies.

Evaluation and Technical Basis

1. Scope of Program: The program includes screening criteria to determine which CASS 

components are potentially susceptible to thermal aging embrittlement and require 

augmented inspection. The screening criteria are applicable to all primary pressure 

boundary and reactor vessel internal components constructed from SA-351 Grades CF3, 

CF3A, CF8, CF8A, CF3M, CF3MA, CF8M, with service conditions above 250°C (482°F). 

The screening criteria for susceptibility to thermal aging embrittlement are not applicable 

to niobium-containing steels; such steels require evaluation on a case-by-case basis. For 

potentially susceptible components, aging management is accomplished either through 

volumetric examination or plant- or component-specific flaw tolerance evaluation.

Based on the criteria set forth in the May 19, 2000 NRC letter, the susceptibility to thermal 

aging embrittlement of CASS components is determined in terms of casting method, 

molybdenum content, and ferrite content. For low-molybdenum content (0.5 wt.% max.) 

steels, only static-cast steels with >20% ferrite are potentially susceptible to thermal 

embrittlement. Static-cast low-molybdenum steels with ≤20% ferrite and all centrifugalcast low-molybdenum steels are not susceptible. For high-molybdenum content (2.0 to 

3.0 wt.%) steels, static-cast steels with >14% ferrite and centrifugal-cast steels with >20% 

ferrite are potentially susceptible to thermal embrittlement. Static-cast high-molybdenum 

steels with ≤14% ferrite and centrifugal-cast high-molybdenum steels with ≤20% ferrite are 

not susceptible. In the susceptibility screening method, ferrite content is calculated by 

using the Hull’s equivalent factors (described in NUREG/CR-4513, Rev. 1) or a method 

producing an equivalent level of accuracy (±6% deviation between measured and 

calculated values). A fracture toughness value of 255 kJ/m2 (1,450 in.-lb/in.2) at a crack 

depth of 2.5 mm (0.1 in.) is used to differentiate between CASS materials that are 
NUREG-1801, Rev. 1 XI M-50 September 2005

nonsusceptible and those that are potentially susceptible to thermal aging embrittlement. 

Extensive research data indicate that for nonsusceptible CASS materials, the saturated 

lower-bound fracture toughness is greater than 255 kJ/m2 (NUREG/CR-4513, Rev. 1).

For pump casings and valve bodies, screening for susceptibility to thermal aging 

embrittlement is not required. The staff’s conservative bounding integrity analysis shows 

that thermally aged CASS valve bodies and pump casings are resistant to failure. For all 

pump casings and valve bodies greater than nominal pipe size (NPS) 4 in., the existing 

ASME Section XI inspection requirements, including the alternative requirements of 

ASME Code Case N-481 for pump casings, are adequate. ASME Section XI, Subsection 

IWB, requires only surface examination of valve bodies less than NPS 4 in. For valve 

bodies less than NPS 4 in., the adequacy of inservice inspection (ISI) according to ASME 

Section XI has been demonstrated by an NRC-performed bounding integrity analysis 

(Reference letter from Christopher Grimes dated May 19, 2000).

2. Preventive Actions: The program consists of evaluation and inspection and provides no 

guidance on methods to mitigate thermal aging embrittlement.

3. Parameters Monitored/Inspected: The AMP monitors the effects of loss of fracture 

toughness on the intended function of the component by identifying the CASS materials 

that are susceptible to thermal aging embrittlement. For potentially susceptible materials, 

the program consists of either enhanced volumetric examination to detect and size cracks 

or plant- or component-specific flaw tolerance evaluation (loss of fracture toughness is of 

consequence only if cracks exist).

4. Detection of Aging Effects: For pump casings and valve bodies and “not susceptible” 

piping, no additional inspection or evaluations are required to demonstrate that the 

material has adequate fracture toughness. For “potentially susceptible” piping, because 

the base metal does not receive periodic inspection per ASME Section XI, the CASS AMP 

provides for volumetric examination of the base metal, with the scope of the inspection 

covering the portions determined to be limiting from the standpoint of applied stress, 

operating time, and environmental considerations. Examination methods that meet the 

criteria of the ASME Section XI, Appendix VIII, are acceptable. Alternatively, a plant- or 

component-specific flaw tolerance evaluation, using specific geometry and stress 

information, can be used to demonstrate that the thermally-embrittled material has 

adequate toughness.

5. Monitoring and Trending: Inspection schedules in accordance with IWB-2400 or IWC2400 and reliable examination methods provide timely detection of cracks.

6. Acceptance Criteria: Flaws detected in CASS components are evaluated in accordance 

with the applicable procedures of IWB-3500 or IWC-3500. Flaw tolerance evaluation for 

components with ferrite content up to 25% is performed according to the principles 

associated with IWB-3640 procedures for submerged arc welds (SAW), disregarding the 

Code restriction of 20% ferrite in IWB-3641(b)(1). Extensive research data indicate that 

the lower-bound fracture toughness of thermally aged CASS materials with up to 25% 

ferrite is similar to that for submerged arc welds (SAWs) with up to 20% ferrite (Lee et al., 

1997). Flaw evaluation for piping with >25% ferrite is performed on a case-by-case basis 

by using fracture toughness data provided by the applicant.
September 2005 XI M-51 NUREG-1801, Rev. 1

7. Corrective Actions: Repair is performed in conformance with IWA-4000 and IWB-4000 

or IWC-4000, and replacement in accordance with IWA-7000 and IWB-7000 or IWC-7000. 

As discussed in the appendix to this report, the staff finds the requirements of 10 CFR 

Part 50, Appendix B, acceptable to address the corrective actions.

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: The AMP was developed by using research data obtained on 

both laboratory-aged and service-aged materials. Based on this information, the effects of 

thermal aging embrittlement on the intended function of CASS components are effectively 

managed.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

10 CFR Part 50.55a, Codes and Standards, Office of the Federal Register, National Archives 

and Records Administration, 2005.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME

Boiler and Pressure Vessel Code, 2001 edition including the 2002 and 2003 Addenda, 

American Society of Mechanical Engineers, New York, NY.

Lee, S., Kuo, P. T., Wichman, K., and Chopra, O., Flaw Evaluation of Thermally Aged Cast 

Stainless Steel in Light-Water Reactor Applications, Int. J. Pres. Ves. and Piping, 

pp. 37-44, 1997.

Letter from Christopher I. Grimes, U.S. Nuclear Regulatory Commission, License Renewal and 

Standardization Branch, to Douglas J. Walters, Nuclear Energy Institute, License Renewal 

Issue No. 98-0030, Thermal Aging Embrittlement of Cast Stainless Steel Components, 

May 19, 2000, (ADAMS Accession No. ML003717179).

NUREG/CR-4513, Rev. 1, Estimation of Fracture Toughness of Cast Stainless Steels During 

Thermal Aging in LWR Systems, U.S. Nuclear Regulatory Commission, August 1994.
NUREG-1801, Rev. 1 XI M-52 September 2005

XI.M13 THERMAL AGING AND NEUTRON IRRADIATION EMBRITTLEMENT OF CAST 

AUSTENITIC STAINLESS STEEL (CASS) 

Program Description

The reactor vessel internals receive a visual inspection in accordance with the American Society 

of Mechanical Engineers (ASME) Code Section XI, Subsection IWB, Category B-N-3. This 

inspection is augmented to detect the effects of loss of fracture toughness due to thermal aging 

and neutron irradiation embrittlement of cast austenitic stainless steel (CASS) reactor vessel 

internals. This aging management program (AMP) includes (a) identification of susceptible 

components determined to be limiting from the standpoint of thermal aging susceptibility (i.e., 

ferrite and molybdenum contents, casting process, and operating temperature) and/or neutron 

irradiation embrittlement (neutron fluence), and (b) for each “potentially susceptible” component, 

aging management is accomplished through either a supplemental examination of the affected 

component based on the neutron fluence to which the component has been exposed as part of 

the applicant’s 10-year inservice inspection (ISI) program during the license renewal term, or a 

component-specific evaluation to determine its susceptibility to loss of fracture toughness. 

Evaluation and Technical Basis

1. Scope of Program: The program provides screening criteria to determine the 

susceptibility of CASS components to thermal aging on the basis of casting method, 

molybdenum content, and percent ferrite. The screening criteria are applicable to all 

primary pressure boundary and reactor vessel internal components constructed from SA351 Grades CF3, CF3A, CF8, CF8A, CF3M, CF3MA, CF8M, with service conditions 

above 250°C (482°F). The screening criteria for susceptibility to thermal aging 

embrittlement are not applicable to niobium-containing steels; such steels require 

evaluation on a case-by-case basis. For “potentially susceptible” components, the 

program provides for the consideration of the synergistic loss of fracture toughness due to 

neutron embrittlement and thermal aging embrittlement. For each such component, an 

applicant can implement either (a) a supplemental examination of the affected component 

as part of a 10-year ISI program during the license renewal term, or (b) a componentspecific evaluation to determine the component’s susceptibility to loss of fracture 

toughness.

Based on the criteria set forth in the May 19, 2000 letter from Christopher Grimes, Nuclear 

Regulatory Commission (NRC), to Mr. Douglas Walters, Nuclear Energy Institute (NEI),

the susceptibility to thermal aging embrittlement of CASS components is determined in 

terms of casting method, molybdenum content, and ferrite content. For low-molybdenum 

content (0.5 wt.% max.) steels, only static-cast steels with >20% ferrite are potentially 

susceptible to thermal embrittlement. Static-cast low-molybdenum steels with ≤20% ferrite 

and all centrifugal-cast low-molybdenum steels are not susceptible. For high-molybdenum 

content (2.0 to 3.0 wt.%) steels, static-cast steels with >14% ferrite and centrifugal-cast 

steels with >20% ferrite are potentially susceptible to thermal embrittlement. Static-cast 

high-molybdenum steels with ≤14% ferrite and centrifugal-cast high-molybdenum steels 

with ≤20% ferrite are not susceptible. In the susceptibility screening method, ferrite 

content is calculated by using the Hull’s equivalent factors (described in NUREG/CR4513, Rev. 1) or a method producing an equivalent level of accuracy (±6% deviation 

between measured and calculated values). A fracture toughness value of 255 kJ/m2

(1,450 in.-lb/in.2) at a crack depth of 2.5 mm (0.1 in.) is used to differentiate between 
September 2005 XI M-53 NUREG-1801, Rev. 1

CASS materials that are nonsusceptible and those that are potentially susceptible to 

thermal aging embrittlement. Extensive research data indicate that for nonsusceptible 

CASS materials, the saturated lower-bound fracture toughness is greater than 255 kJ/m2

(NUREG/CR-4513, Rev. 1).

2. Preventive Actions: The program consists of evaluation and inspection and provides no 

guidance on methods to mitigate thermal aging and neutron irradiation embrittlement. 

3. Parameters Monitored/Inspected: The program specifics depend on the neutron fluence 

and thermal embrittlement susceptibility of the component. The AMP monitors the effects 

of loss of fracture toughness on the intended function of the component by identifying the 

CASS materials that either have a neutron fluence of greater than 1017 n/cm2 (E>1 MeV) 

or are determined to be susceptible to thermal aging embrittlement. For such materials, 

the program consists of either supplemental examination of the affected component based 

on the neutron fluence to which the component has been exposed, or component-specific 

evaluation to determine the component’s susceptibility to loss of fracture toughness. 

4. Detection of Aging Effects: For reactor vessel internal CASS components that have a 

neutron fluence of greater than 1017 n/cm2 (E>1 MeV) or are determined to be susceptible 

to thermal embrittlement, the 10-year ISI program during the renewal period includes a 

supplemental inspection covering portions of the susceptible components determined to 

be limiting from the standpoint of thermal aging susceptibility (i.e., ferrite and molybdenum 

contents, casting process, and operating temperature), neutron fluence, and cracking 

susceptibility (i.e., applied stress, operating temperature, and environmental conditions). 

The inspection technique is capable of detecting the critical flaw size with adequate 

margin. The critical flaw size is determined based on the service loading condition and 

service-degraded material properties. One example of a supplemental examination is 

enhancement of the visual VT-1 examination of Section XI IWA-2210. A description of 

such an enhanced visual VT-1 examination could include the ability to achieve a 0.0005-

in. resolution, with the conditions (e.g., lighting and surface cleanliness) of the inservice 

examination bounded by those used to demonstrate the resolution of the inspection 

technique. Alternatively, the applicant may perform a component-specific evaluation, 

including a mechanical loading assessment to determine the maximum tensile loading on 

the component during ASME Code Level A, B, C, and D conditions. If the loading is 

compressive or low enough (<5 ksi) to preclude fracture, then supplemental inspection of 

the component is not required. Failure to meet this criterion requires continued use of the 

supplemental inspection program. For each CASS component that has been subjected to 

a neutron fluence of less than 1017 n/cm2 (E>1 MeV) and is potentially susceptible to 

thermal aging, the supplement inspection program applies; otherwise, the existing ASME 

Section XI inspection requirements are adequate if the components are not susceptible to 

thermal aging embrittlement.

5. Monitoring and Trending: Inspections scheduled in accordance with IWB-2400 and 

reliable examination methods provide timely detection of cracks.

6. Acceptance Criteria: Flaws detected in CASS components are evaluated in accordance 

with the applicable procedures of IWB-3500. Flaw tolerance evaluation for components 

with ferrite content up to 25% is performed according to the principles associated with 

IWB-3640 procedures for submerged arc welds (SAW), disregarding the Code restriction 

of 20% ferrite in IWB-3641(b)(1). Extensive research data indicate that the lower-bound 
NUREG-1801, Rev. 1 XI M-54 September 2005

fracture toughness of thermally aged CASS materials with up to 25% ferrite is similar to 

that for SAWs with up to 20% ferrite (Lee et al., 1997). Flaw evaluation for CASS 

components with >25% ferrite is performed on a case-by-case basis by using fracture 

toughness data provided by the applicant.

7. Corrective Actions: Repair is performed in conformance with IWA-4000 and IWB-4000, 

and replacement in accordance with IWA-7000 and IWB-7000. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address the corrective actions.

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: The AMP was developed by using research data obtained on 

both laboratory-aged and service-aged materials. Based on this information, the effects of 

thermal aging embrittlement on the intended function of CASS components are effectively 

managed.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 2001 edition including the 2002 and 2003 Addenda, 

American Society of Mechanical Engineers, New York, NY.

Lee, S., Kuo, P. T., Wichman, K., and Chopra, O., Flaw Evaluation of Thermally Aged Cast 

Stainless Steel in Light-Water Reactor Applications, Int. J. Pres. Ves. and Piping, 

pp. 37-44, 1997.

Letter from Christopher I. Grimes, U.S. Nuclear Regulatory Commission, License Renewal and 

Standardization Branch, to Douglas J. Walters, Nuclear Energy Institute, License Renewal 

Issue No. 98-0030, Thermal Aging Embrittlement of Cast Stainless Steel Components, 

May 19, 2000, (ADAMS Accession No. ML003717179).

NUREG/CR-4513, Rev. 1, Estimation of Fracture Toughness of Cast Stainless Steels during 

Thermal Aging in LWR Systems, U.S. Nuclear Regulatory Commission, August 1994.
September 2005 XI M-55 NUREG-1801, Rev. 1

XI.M14 LOOSE PART MONITORING

Program Description

The program relies on an inservice monitoring program to detect and monitor loose parts in 

light-water reactor (LWR) power plants. This in-service loose part monitoring (LPM) program is 

based on the recommendations from the American Society of Mechanical Engineers operation 

and maintenance standards and guides (ASME OM-S/G)-1997, Part 12, “Loose Part Monitoring 

in Light-Water Reactor Power Plants.”

Evaluation and Technical Basis

1. Scope of Program: The program includes measures to monitor and detect metallic loose 

parts by using transient signals analysis on acoustic data generated due to loose parts 

impact. The program is applicable, but not necessarily limited to, the reactor vessel and 

primary coolant systems in pressurized water reactors (PWRs) and the reactor 

recirculation system in boiling water reactors (BWRs). The detection and monitoring 

system includes a set of accelerometers installed in the vicinity of regions where loose 

parts impact is likely to occur. The system incorporates the capability of automatic 

annunciation (audible and visual), audio monitoring, automatic and manual signal 

recording, and acoustic signal analysis/evaluation. Measures for personnel radiation 

exposure and safety are included as part of the requirements of the LPM system. The 

objective of the LPM program is to provide early indication of component degradation.

2. Preventive Actions: The aging management program (AMP) is a monitoring/detection 

program that provides early indication and detection of the onset of aging degradation. It 

does not rely on preventive actions.

3. Parameters Monitored/Inspected: The program relies on the use of transient acoustic 

signals to provide information on the occurrence of metallic loose part impact. Reactor 

coolant system (RCS) background noise may mask the noise generated due to loose part 

impact. These background noises may arise from sources such as coolant flow and 

mechanically and hydraulically generated vibrations. To differentiate loose part impact 

noise from background noise, ASME OM-S/G-1997, Part 12, recommends that the 

monitoring system sensitivity be set on the basis of the background noise and that 

maximum sensitivity be accomplished that is consistent with an acceptable false alarm 

rate arising from the background noise.

4. Detection of Aging Effects: Impact signals contain significant information on the size of 

the impacting object, the impact force and energy, and the composition and shape of both 

the component struck and the impacting object. In general, the magnitude of the impact 

signal increases with the impact mass and impact velocity. However, the frequency 

response increases with increasing velocity and decreasing mass. These data may be 

used to extract information on possible loose part impact and differentiate it from 

background noise. 

5. Monitoring and Trending: The impact signals, collected data, frequency, and 

characteristics are recorded, monitored, and evaluated to locate and identify the source 

and cause of the acoustic signals for the purpose of determining the need and urgency for 

a detailed inspection and examination of the suspected reactor vessel internals 

components. These activities are performed and associated personnel are qualified in 
NUREG-1801, Rev. 1 XI M-56 September 2005

accordance with site controlled procedures and processes, as indicated by vendor, 

industry, or regulatory guidance documents. 

6. Acceptance Criteria: The LPM alarms that suggest metallic impacts are further 

evaluated to verify LPM operability and to determine the location of the impact, the impact 

energy, and mass. Plant process data are reviewed for anomalous behavior, and 

diagnostic results are assessed by plant personnel.

7. Corrective Actions: If LPM diagnostics indicate the presence of loose parts, then 

corrective actions are taken. In some cases, the results of the diagnostic may indicate the 

signal is due to a change in the plant background noise characteristics and not due to the 

presence of loose parts. In such cases, the LPM alarm rates may in time become so high 

as to be unacceptable in practice. Adjustment of the alarm threshold (set points) is 

allowed. However, the reason for the change in background noise is to be investigated 

and understood, and the set point change is to be documented. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address the corrective actions.

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: The loose part monitoring program is extensively and effectively 

used by the industry. The program has been developed and published as a standard in 

the ASME “Standards and Guides for Operation and Maintenance of Nuclear Power 

Plants,” Part 12, an American National Standard. Part 12 was developed on the basis of 

knowledge gained from operating experience and research conducted since the Nuclear 

Regulatory Commission (NRC) issued Regulatory Guide (RG) 1.133 in May 1981.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

10 CFR Part 50.55a, Codes and Standards, Office of the Federal Register, National Archives 

and Records Administration, 2005.

ANSI S2.11-1969, American National Standard for the Selection of Calibrations and Tests for 

Electrical Transducers Used for Monitoring Shock and Vibrations, American National Standards 

Institute, Washington, DC, 1969.

ASME OM-S/G-1997, Part 12, Loose Part Monitoring in Light-Water Reactor Power Plants, 

American Society of Mechanical Engineers, New York, NY, 1997.

NRC Regulatory Guide 1.133, Rev. 1, Loose Part Detection Program for the Primary System of 

Light Water Cooled Reactors, U.S. Nuclear Regulatory Commission, 1981. 
September 2005 XI M-57 NUREG-1801, Rev. 1

XI.M15 Neutron Noise Monitoring

Program Description

The program relies on monitoring the excore neutron detector signals due to core motion to 

detect and monitor significant loss of axial preload at the core support barrel’s upper support 

flange in pressurized water reactors (PWRs). This inservice monitoring program is based on the 

recommendations from the American Society of Mechanical Engineers operation and 

maintenance standards and guides (ASME OM-S/G)-1997, Part 5, “Inservice Monitoring of Core 

Support Barrel Axial Preload in Pressurized Water Reactors Power Plants.”

Evaluation and Technical Basis

1. Scope of Program: The program includes measures to monitor and detect loss of axial 

preload (loss of axial restraint) at the core support barrel’s upper support flange in PWRs. 

The loss of axial restraint may arise from long-term changes resulting from abnormal wear 

at the reactor vessel core barrel mating surface or short-term changes due to improper 

installation of the reactor internals. The program also includes guidelines for further data 

acquisition that may be needed to define future plant operation and/or program plans in 

order to maintain the capability of the structure/components to perform the intended 

function.

2. Preventive Actions: The program is a monitoring/detection program that provides early 

indication and detection of the onset of aging degradation of the core support barrelholddown mechanism prior to a scheduled shutdown, thus reducing outage time and avoiding 

potential damage to the core support barrel and fuel assemblies. The AMP does not rely 

on preventive actions.

3. Parameters Monitored/Inspected: The program relies on the use of excore neutron 

detector signals to provide information on the conditions of the axial preload. The excore 

neutron flux signal is composed of a steady state, direct current (DC) component that 

arises from the neutron flux produced by the power operation of the reactor, as well as a 

fluctuating (noise-like) component. This fluctuating signal arises from the core reactivity 

changes due to lateral core motion from the loss of axial preload. This core motion is 

mainly the result of beam mode vibration of the core support barrel. Despite the fact that 

this beam mode vibration provides only a very weak neutron noise source, it may be 

reliably detected and identified through Fourier Analysis of the fluctuating signal 

component of the excore neutron flux signal. This signal component has the 

characteristics of having 180-degree shifts and a high degree of coherence between 

signals obtained from pairs of excore neutron detectors that are positioned on 

diametrically opposite sides of the core. The neutron noise signals are characterized by 

parameters, which include the auto correlation, cross correlation, coherence, and phase. 

These parameters are to be monitored and evaluated.

4. Detection of Aging Effects: Flow-induced vibration of the core support barrel will change 

the thickness of the downcomer annulus (water gap). This variation in the thickness will 

give rise to fluctuating changes in the neutron flux, as monitored by the excore neutron 

detectors. The natural frequencies and the amplitudes of the vibratory motion of the core 

barrel are related to the effective axial preload at the upper support flange of the core 

support barrel. Monitoring of the neutron noise signal obtained with the neutron flux 

detectors located around the external periphery of the reactor vessel provides detection of 
NUREG-1801, Rev. 1 XI M-58 September 2005

anomalous vibrational motion of the core support barrel, and hence significant loss of the 

axial preload. Decrease in the axial preload leads to decreases in the core support barrel 

beam mode frequency and an increase in the magnitude of the noise signal. The overall 

effect of a decrease in the axial preload is to shift the neutron noise power spectrum 

toward larger amplitudes for the lower frequency region.

5. Monitoring and Trending: The neutron noise random fluctuation in the signals from the 

excore detectors are monitored, recorded, and analyzed to identify changes in the beam 

mode natural frequency of the core support barrel and its direction of motion for the 

purpose of a timely determination of the need and urgency for a detailed inspection and 

examination of the reactor vessel internals hold-down mechanism and mating component 

surfaces. These activities and analytical methodology are performed, and associated 

personnel are qualified, in accordance with site-controlled procedures and processes as 

indicated by vendor, industry, or regulatory guidance documents.

The neutron noise monitoring program has three separate phases: a baseline phase, a 

surveillance phase, and a diagnostic phase. The baseline phase establishes the database 

to be used as a reference for developing limits and trends in the surveillance phase and to 

support data evaluation and interpretation in the diagnostic phase. During the baseline 

phase, data on the time history and DC level of each neutron flux detector and each 

cross-core detector pair are obtained. From this database, the characteristic amplitudes 

and frequencies of the core barrel motion are extracted. The wide and narrow frequency 

bands with their associated normalized root mean square (NRMS) values are established. 

The ASME-OMS/G-1997, Part 5, recommends collecting the baseline data during the first 

fuel cycle that the neutron noise monitoring program is applied to an already operating 

plant. Whenever significant changes takes place for the core, reactor internals, or 

operating conditions, additional baseline data is obtained. 

In the surveillance phase, routine neutron noise monitoring of normal plant operations is 

performed over the life of the plant. The DC level and data for frequency analysis of each 

detector and two pair of cross-core detectors, may be collected. Comparisons of the 

measured amplitude and frequency data, with limits established from the baseline data, 

are made. In using neutron noise monitoring, accounts are taken of the effect of core 

burn-up, decreasing boron concentration, changes in fuel management, and in-core 

contact with the reactor vessel mechanical snubbers, which may affect the neutron noise 

signatures. Proper allowances for these factors during the baseline and surveillance 

phases will help toward detecting loss of axial preload before the core barrel becomes 

sufficiently free to wear against the reactor vessel and will also reduce the need to invoke 

the diagnostic phase. 

If the diagnostic phase becomes necessary, then evaluations are carried out to establish 

whether any deviations from the baseline data detected during the surveillance phase 

arises from core barrel motion due to loss of axial preload. The need and frequency of 

additional data collection on the time history and DC level of each neutron flux detector 

and each cross-core detector pair collection are guided by the results of these 

evaluations.

6. Acceptance Criteria: If evaluation of the baseline data indicates normal operation for the 

applicable structure/component, the surveillance phase may commence. If evaluation 

indicates anomalous behavior, the monitoring program enters the diagnostic phase.

During the surveillance phase, if deviations from the baseline fall within predetermined 
September 2005 XI M-59 NUREG-1801, Rev. 1

acceptable limits, the surveillance will continue. Otherwise, the diagnostic phase will 

commence.

7. Corrective Actions: Initial results from the diagnostic phase of the program may be used 

to determine whether there is a need to increase the minimum frequency with which the 

surveillance data are acquired. In addition, if necessary, corrective actions may be taken 

to change the type of data acquisition and analysis from that previously recommended for 

the surveillance part of the program. The data trends may be established to guide further 

data acquisition that may be needed to define future plant operation and/or program 

plans. As discussed in the appendix to this report, the staff finds the requirements of 10 

CFR Part 50, Appendix B, acceptable to address the corrective actions.

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above.

10. Operating Experience: The neutron noise monitoring program and procedures were 

developed by the industry and published as a guide in ASME OM-S/G-1997, Part 5, an 

American National Standard. This monitoring program and procedures have been 

effective in limited industry use for monitoring and detecting loss of core support barrel 

axial preload in PWR power plants.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

10 CFR Part 50.55a, Codes and Standards, Office of the Federal Register, National Archives 

and Records Administration, 2005. 

ASME OM-S/G-1997, Part 5, Inservice Monitoring of Core Support Barrel Axial Preload in 

Pressurized Water Reactor Power Plants, American Society of Mechanical Engineers, 

New York, NY, 1997.
NUREG-1801, Rev. 1 XI M-60 September 2005

XI.M16 PWR VESSEL INTERNALS

Guidance for the aging management of PWR Vessel Internals is provided in the AMR line items 

of Chapter IV, as appropriate.
September 2005 XI M-61 NUREG-1801, Rev. 1

XI.M17 FLOW-ACCELERATED CORROSION

Program Description

The program relies on implementation of the Electric Power Research Institute (EPRI) 

guidelines in the Nuclear Safety Analysis Center (NSAC)-202L-R2 for an effective 

flow-accelerated corrosion (FAC) program. The program includes performing (a) an analysis to 

determine critical locations, (b) limited baseline inspections to determine the extent of thinning at 

these locations, and (c) follow-up inspections to confirm the predictions, or repairing or replacing 

components as necessary. 

Evaluation and Technical Basis

1. Scope of Program: The FAC program, described by the EPRI guidelines in 

NSAC-202L-R2, includes procedures or administrative controls to assure that the 

structural integrity of all carbon steel lines containing high-energy fluids (two phase as well 

as single phase) is maintained. Valve bodies retaining pressure in these high-energy 

systems are also covered by the program. The FAC program was originally outlined in 

NUREG-1344 and was further described through the Nuclear Regulatory Commission 

(NRC) Generic Letter (GL) 89-08. A program implemented in accordance with the EPRI 

guidelines predicts, detects, and monitors FAC in plant piping and other components, 

such as valve bodies, elbows and expanders. Such a program includes the following 

recommendations: (a) conducting an analysis to determine critical locations, 

(b) performing limited baseline inspections to determine the extent of thinning at these 

locations, and (c) performing follow-up inspections to confirm the predictions, or repairing 

or replacing components as necessary. NSAC-202L-R2 (April 1999) provides general 

guidelines for the FAC program. To ensure that all the aging effects caused by FAC are 

properly managed, the program includes the use of a predictive code, such as 

CHECWORKS, that uses the implementation guidance of NSAC-202L-R2 to satisfy the 

criteria specified in 10 CFR Part 50, Appendix B, criteria for development of procedures 

and control of special processes.

2. Preventive Actions: The FAC program is an analysis, inspection, and verification 

program; thus, there is no preventive action. However, it is noted that monitoring of water 

chemistry to control pH and dissolved oxygen content, and selection of appropriate piping 

material, geometry, and hydrodynamic conditions, are effective in reducing FAC. 

3. Parameters Monitored/Inspected: The aging management program (AMP) monitors the 

effects of FAC on the intended function of piping and components by measuring wall 

thickness.

4. Detection of Aging Effects: Degradation of piping and components occurs by wall 

thinning. The inspection program delineated in NSAC-202L-R2 consists of identification of 

susceptible locations as indicated by operating conditions or special considerations. 

Ultrasonic and radiographic testing is used to detect wall thinning. The extent and 

schedule of the inspections assure detection of wall thinning before the loss of intended 

function.

5. Monitoring and Trending: CHECWORKS or a similar predictive code is used to predict 

component degradation in the systems conducive to FAC, as indicated by specific plant 

data, including material, hydrodynamic, and operating conditions. CHECWORKS is 
NUREG-1801, Rev. 1 XI M-62 September 2005

acceptable because it provides a bounding analysis for FAC. CHECWORKS was 

developed and benchmarked by using data obtained from many plants. The inspection 

schedule developed by the licensee on the basis of the results of such a predictive code 

provides reasonable assurance that structural integrity will be maintained between 

inspections. Inspection results are evaluated to determine if additional inspections are 

needed to assure that the extent of wall thinning is adequately determined, assure that 

intended function will not be lost, and identify corrective actions.

6. Acceptance Criteria: Inspection results are input for a predictive computer code, such as 

CHECWORKS, to calculate the number of refueling or operating cycles remaining before 

the component reaches the minimum allowable wall thickness. If calculations indicate that 

an area will reach the minimum allowed wall thickness before the next scheduled outage, 

the component is to be repaired, replaced, or reevaluated.

7. Corrective Actions: Prior to service, components for which the acceptance criteria are 

not satisfied are reevaluated, repaired, or replaced. Long-term corrective actions could 

include adjusting operating parameters or selecting materials resistant to FAC. As 

discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 

50, Appendix B, acceptable to address the corrective actions.

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: Wall-thinning problems in single-phase systems have occurred in 

feedwater and condensate systems (NRC IE Bulletin No. 87-01; NRC Information Notices 

[INs] 81-28, 92-35, 95-11) and in two-phase piping in extraction steam lines (NRC 

INs 89-53, 97-84) and moisture separation reheater and feedwater heater drains (NRC 

INs 89-53, 91-18, 93-21, 97-84). Operating experience shows that the present program, 

when properly implemented, is effective in managing FAC in high-energy carbon steel 

piping and components.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

10 CFR Part 50.55a, Codes and Standards, Office of the Federal Register, National Archives 

and Records Administration, 2005.

NRC Generic Letter 89-08, Erosion/Corrosion-Induced Pipe Wall Thinning, U.S. Nuclear 

Regulatory Commission, May 2, 1989.

NRC IE Bulletin 87-01, Thinning of Pipe Walls in Nuclear Power Plants, U.S. Nuclear 

Regulatory Commission, July 9, 1987.
September 2005 XI M-63 NUREG-1801, Rev. 1

NRC Information Notice 81-28, Failure of Rockwell-Edward Main Steam Isolation Valves, 

U.S. Nuclear Regulatory Commission, September 3, 1981.

NRC Information Notice 89-53, Rupture of Extraction Steam Line on High Pressure Turbine, 

U.S. Nuclear Regulatory Commission, June 13, 1989.

NRC Information Notice 91-18, High-Energy Piping Failures Caused by Wall Thinning, 

U.S. Nuclear Regulatory Commission, March 12, 1991.

NRC Information Notice 91-18, Supplement 1, High-Energy Piping Failures Caused by Wall 

Thinning, U.S. Nuclear Regulatory Commission, December 18, 1991.

NRC Information Notice 92-35, Higher than Predicted Erosion/Corrosion in Unisolable Reactor 

Coolant Pressure Boundary Piping inside Containment at a Boiling Water Reactor, 

U.S. Nuclear Regulatory Commission, May 6, 1992.

NRC Information Notice 93-21, Summary of NRC Staff Observations Compiled during 

Engineering Audits or Inspections of Licensee Erosion/Corrosion Programs, U.S. Nuclear 

Regulatory Commission, March 25, 1993.

NRC Information Notice 95-11, Failure of Condensate Piping Because of Erosion/Corrosion at a 

Flow Straightening Device, U.S. Nuclear Regulatory Commission, February 24, 1995.

NRC Information Notice 97-84, Rupture in Extraction Steam Piping as a Result of FlowAccelerated Corrosion, U.S. Nuclear Regulatory Commission, December 11, 1997.

NSAC-202L-R2, Recommendations for an Effective Flow Accelerated Corrosion Program, 

Electric Power Research Institute, Palo Alto, CA, April 8, 1999.

NUREG-1344, Erosion/Corrosion-Induced Pipe Wall Thinning in U.S. Nuclear Power Plants, 

P. C. Wu, U.S. Nuclear Regulatory Commission, April 1989.
NUREG-1801, Rev. 1 XI M-64 September 2005

XI.M18 BOLTING INTEGRITY

Program Description

The program relies on recommendations for a comprehensive bolting integrity program, as 

delineated in NUREG-1339, and industry recommendations, as delineated in the Electric Power 

Research Institute (EPRI) NP-5769, with the exceptions noted in NUREG-1339 for safetyrelated bolting. The program relies on industry recommendations for comprehensive bolting 

maintenance, as delineated in EPRI TR-104213 for pressure retaining bolting and structural 

bolting. 

The program generally includes periodic inspection of closure bolting for indication of loss of 

preload, cracking, and loss of material due to corrosion, rust, etc. The program also includes 

preventive measures to preclude or minimize loss of preload and cracking. 

Other aging management programs, such as XI.M1, “ASME Section XI Inservice Inspection 

(ISI) Subsections IWB, IWC, and IWD” and XI.S3, “ASME Section XI Subsection IWF” also 

manage inspection of safety-related bolting and supplement this bolting integrity program. 

Evaluation and Technical Basis

1. Scope of Program: This program covers bolting within the scope of license renewal,

including: 1) safety-related bolting, 2) bolting for nuclear steam supply system (NSSS) 

component supports, 3) bolting for other pressure retaining components, including nonsafety-related bolting, and 4) structural bolting (actual measured yield strength ≥ 150 ksi). 

The aging management of reactor head closure studs is addressed by XI.M3, and is not 

included in this program. The staff’s recommendations and guidelines for comprehensive 

bolting integrity programs that encompass all safety-related bolting are delineated in 

NUREG-1339, which include the criteria established in the 1995 edition through the 1996 

addenda of ASME Code Section XI. The industry’s technical basis for the program for 

safety-related bolting and guidelines for material selection and testing, bolting preload 

control, ISI, plant operation, and maintenance, and evaluation of the structural integrity of 

bolted joints, are outlined in EPRI NP-5769, with the exceptions noted in NUREG-1339. 

For other bolting, this information is set forth in EPRI TR-104213.

2. Preventive Actions: Selection of bolting material and the use of lubricants and sealants 

is in accordance with the guidelines of EPRI NP-5769, and the additional 

recommendations of NUREG-1339, to prevent or mitigate degradation and failure of 

safety-related bolting (see element 10, below). NUREG-1339 takes exception to certain 

items in EPRI NP-5769, and recommends additional measures with regard to them. 

Bolting replacement activities include proper torquing of the bolts and checking for 

uniformity of the gasket compression after assembly. Maintenance practices require the 

application of an appropriate preload, based on EPRI documents. 

3. Parameters Monitored/Inspected: This program monitors the effects of aging on the 

intended function of bolting. Specifically, bolting for safety-related pressure retaining 

components is inspected for leakage, loss of material, cracking, and loss of preload/loss 

of prestress. Bolting for other pressure retaining components is inspected for signs of 

leakage.
September 2005 XI M-65 NUREG-1801, Rev. 1

High strength bolts (actual yield strength >150 ksi) used in NSSS component supports are 

monitored for cracking. Structural bolts and fasteners are inspected for indication of 

potential problems including loss of material, cracking, loss of coating integrity, and 

obvious signs of corrosion, rust, etc. 

4. Detection of Aging Effects: Inspection requirements are in accordance with the ASME 

Section XI, Tables IWB 2500-1, IWC 2500-1 and IWD 2500-1 editions endorsed in 10 

CFR 50.55a(b)(2) and the recommendations of EPRI NP-5769. For Class 1 components, 

Table IWB 2500-1, Examination Category B-G-1, for bolts greater than 2-inches in 

diameter, specifies volumetric examination of studs and bolts and visual VT-1 examination 

of surfaces of nuts, washers, bushings, and flanges. Examination Category B-G-2, for 

bolts 2-inches or smaller, requires only visual VT-1 examination of surfaces of bolts, 

studs, and nuts. For Class 2 components, Table IWC 2500-1, Examination Category C-D, 

for bolts greater than 2-inches in diameter, requires volumetric examination of studs and 

bolts. Examination Categories B-P, C-H, and D-B require visual examination (IWA-5240) 

during system leakage testing of all pressure-retaining Class 1, 2 and 3 components, 

according to Tables IWB 2500-1, IWC 2500-1, and IWD 2500-1, respectively. In addition, 

degradation of the closure bolting due to crack initiation, loss of prestress, or loss of 

material due to corrosion of the closure bolting would result in leakage. The extent and 

schedule of inspections, in accordance with Tables IWB 2500-1, IWC 2500-1, and IWD 

2500-1, combined with periodic system walkdowns, assure detection of leakage before 

the leakage becomes excessive.

For other pressure retaining bolting, periodic system walkdowns assure detection of 

leakage before the leakage becomes excessive. 

High strength structural bolts and fasteners (actual yield strength 150 ksi) for NSSS 

component supports, may be subject to stress corrosion cracking (SCC). For this type of 

high strength structural bolts that are potentially subjected to SCC, in sizes greater than 1-

inch nominal diameter, volumetric examination comparable to that of Examination 

Category B-G-1 is required in addition to visual examination. This requirement may be 

waived with adequate plant-specific justification. Structural bolts and fasteners (actual 

yield strength < 150 ksi) both inside and outside containment are inspected by visual 

inspection (e.g., Structures Monitoring Program or equivalent). In addition to visual and 

volumetric examination, degradation of these bolts and fasteners may be detected and 

measured by removing the bolt/fastener, a proof test by tension or torquing, in situ 

ultrasonic tests, or a hammer test. If these bolts and fasteners are found cracked and/or 

corroded, a closer inspection is performed to assess extent of corrosion. An appropriate 

technique is selected on the basis of the bolting application and the applicable code. 

5. Monitoring and Trending: The inspection schedules of ASME Section XI are effective 

and ensure timely detection of applicable aging effects. If bolting connections for pressure 

retaining components (not covered by ASME Section XI) is reported to be leaking, then it 

may be inspected daily. If the leak rate does not increase, the inspection frequency may 

be decreased to biweekly or weekly. 

6. Acceptance Criteria: Any indications of aging effects in ASME pressure retaining bolting 

are evaluated in accordance with Section XI of the ASME Code. For other pressure 

retaining bolting, NSSS component support bolting and structural bolting, indications of 

aging should be dispositioned in accordance with the corrective action process. 
NUREG-1801, Rev. 1 XI M-66 September 2005

7. Corrective Actions: Replacement of ASME pressure retaining bolting is performed in 

accordance with appropriate requirements of Section XI of the ASME Code, as subject to 

the additional guidelines and recommendations of EPRI NP-5769. Replacement of other 

pressure retaining bolting (i.e., non-Class 1 bolting) and disposition of degraded structural 

bolting is performed in accordance with the guidelines and recommendations of EPRI TR104213. Replacement of NSSS component support bolting is performed in accordance 

with EPRI NP-5769. As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective 

actions. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: See item 8, above. 

10. Operating Experience: Degradation of threaded bolting and fasteners in closures for the 

reactor coolant pressure boundary has occurred from boric acid corrosion, SCC, and 

fatigue loading (NRC IE Bulletin 82-02, NRC Generic Letter 91-17). SCC has occurred in 

high strength bolts used for NSSS component supports (EPRI NP-5769). The bolting 

integrity program developed and implemented in accordance with commitments made in 

response to NRC communications on bolting events have provided an effective means of 

ensuring bolting reliability. These programs are documented in EPRI NP-5769 and TR104213 and represent industry consensus.

Degradation related failures have occurred in downcomer Tee-quencher bolting in BWRs 

designed with drywells (ADAMS Accession Number ML050730347). Leakage from bolted 

connections has been observed in reactor building closed cooling systems of BWRs.

(LER 50-341/2005-001).

The applicant is to evaluate applicable operating experience to support the conclusion that 

the effects of aging are adequately managed.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2005.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 2001 edition including the 2002 and 2003 Addenda, 

American Society of Mechanical Engineers, New York, NY.

EPRI NP-5769, Degradation and Failure of Bolting in Nuclear Power Plants, Volumes 1 and 2, 

April 1988. 

EPRI TR-104213, Bolted Joint Maintenance & Application Guide, Electric , December 1995.
September 2005 XI M-67 NUREG-1801, Rev. 1

NRC Generic Letter 91-17, Generic Safety Issue 79, Bolting Degradation or Failure in Nuclear 

Power Plants, U.S. Nuclear Regulatory Commission, October 17, 1991. 

NRC IE Bulletin No. 82-02, Degradation of Threaded Fasteners in the Reactor Coolant Pressure 

Boundary of PWR Plants, U.S. Nuclear Regulatory Commission, June 2, 1982. 

NUREG-1339, Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear 

Power Plants, U.S. Nuclear Regulatory Commission, June 1990.

Failure of Safety/Relief Valve Tee-Quencher Support Bolts, NRC Morning Report for March 14, 

2005, ADAMS Accession Number ML050730347.
NUREG-1801, Rev. 1 XI M-68 September 2005

XI.M19 STEAM GENERATOR TUBE INTEGRITY

Program Description

The steam generator tube integrity program is applicable to managing the aging of steam 

generator tubes, plugs, sleeves and tube supports.

Mill annealed alloy 600 steam generator (SG) tubes have experienced tube degradation related 

to corrosion phenomena, such as primary water stress corrosion cracking (PWSCC), outside 

diameter stress corrosion cracking (ODSCC), intergranular attack (IGA), pitting, and wastage, 

along with other mechanically induced phenomena, such as denting, wear, impingement 

damage, and fatigue. The dominant degradation mode at this time for thermally treated alloy 

600 and 690 tubes is wear. Nondestructive examination (NDE) techniques are used to inspect 

all tubing materials and sleeves to identify tubes with degradation that may need to be removed 

from service or repaired in accordance with plant technical specifications. In addition, 

operational leakage limits are included to ensure that, should substantial tube leakage develop, 

prompt action is taken. These limits are included in plant technical specifications, such as 

standard technical specifications of NUREG-1430, Rev. 1, for Babcock & Wilcox pressurized 

water reactors (PWRs); NUREG-1431, Rev. 1, for Westinghouse PWRs; and NUREG-1432, 

Rev. 1, for Combustion Engineering PWRs.

The technical specifications specify SG inspection scope, frequency, and acceptance criteria for 

the plugging and repair of flawed tubes. NRC Regulatory Guide (RG) 1.121, “Bases for Plugging 

Degraded Steam Generator Tubes,” provides guidelines for determining the tube repair criteria 

and operational leakage limits. Acceptance criteria for the plugging and repair of flawed tubes 

are incorporated in plant technical specifications. In addition to flaw acceptance (or 

plugging/repair) criteria, the technical specifications also specify acceptable tube repair methods 

(e.g., plugging and/or sleeving). Plants may also apply for changes in their technical 

specifications to provide an alternate repair criteria for SG degradation management.

In addition to plant technical specifications, all PWR licensees have committed voluntarily to a 

SG degradation management program described in the Nuclear Energy Institute (NEI) 97-06, 

“Steam Generator Program Guidelines.” This program references a number of industry 

guidelines and incorporates a balance of prevention, inspection, evaluation, repair, and leakage 

monitoring measures. The NEI 97-06 document (a) includes performance criteria that are 

intended to provide assurance that tube integrity is being maintained consistent with the plant’s 

licensing basis, and (b) provides guidance for monitoring and maintaining the tubes to provide 

assurance that the performance criteria are met at all times between scheduled inspections of 

the tubes. Steam generator tube integrity can be affected by degradation of SG plugs, sleeves 

and tube supports. Therefore, these components are also addressed by this aging management 

program.

The NEI 97-06 program includes an assessment of degradation mechanisms that considers 

operating experience from similar steam generators (SGs) and, for each mechanism, defines 

the inspection techniques as well as the sampling strategy. The industry guidelines provide

criteria for the qualification of personnel, specific techniques, and the associated acquisition and 

analysis of data, including procedures, probe selection, analysis protocols, and reporting 

criteria. The performance criteria pertain to structural integrity, accident-induced leakage, and 

operational leakage. The SG monitoring program includes guidance on assessment of 

degradation mechanisms, inspection, tube integrity assessment, maintenance, plugging, repair, 

and leakage monitoring, as well as procedures for monitoring and controlling secondary-side 
September 2005 XI M-69 NUREG-1801, Rev. 1

and primary-side water chemistry. The water chemistry program for PWRs relies on monitoring 

and control of reactor water chemistry and secondary water chemistry.

Lastly, NRC Generic Letter (GL) 97-06, “Degradation of Steam Generator Internals,” dated 

December 30, 1997, notified the industry of various steam generator tube support plate damage 

mechanisms identified in foreign and domestic steam generators. In response to GL 97-06, 

licensees indicated whether they had a program in place to detect degradation of steam 

generator internals, and included a description of the inspection plans, including the inspection 

scope, frequency, methods, and components.

As evaluated below, the plant technical specifications, including alternate repair criteria for SG 

degradation management that have been previously approved by the staff for that plant, the 

licensee’s response to GL 97-06, and the licensee’s commitment to implement the SG 

degradation management program described in NEI 97-06, are adequate to manage the effects 

of aging on the SG tubes, plugs, sleeves, and tube supports.

Evaluation and Technical Basis

1. Scope of Program: The scope of the program is specific to SG tubes, plugs, sleeves and 

tube supports. The program includes preventive measures to mitigate degradation related 

to corrosion phenomena, assessment of degradation mechanisms, inservice inspection 

(ISI) of steam generator tubes, plugs, sleeves, and tube supports to detect degradation, 

evaluation, and plugging or repair, as needed, and leakage monitoring to maintain the 

structural and leakage integrity of the pressure boundary. Tube and sleeve inspection 

scope and frequency, plugging or repair, and leakage monitoring are in accordance with 

the plant technical specifications and the licensee’s SG degradation management 

program implemented in accordance with NEI 97-06. Plug inspection scope and 

frequency, plugging or repair, and leakage monitoring are in accordance with the 

licensee’s SG degradation management program implemented in accordance with NEI 

97-06. Lastly, tube support plate inspection scope and frequency are in accordance with 

the licensee’s SG degradation management program implemented in accordance with 

NEI 97-06 as well as the program described in the licensee’s response to GL 97-06.

2. Preventive Actions: The program includes preventive measures to mitigate degradation 

related to corrosion phenomena. The guidelines in NEI 97-06 include foreign material 

exclusion as a means to inhibit wear degradation. The water chemistry program for PWRs 

relies on monitoring and control of reactor water chemistry based on the EPRI guidelines 

in TR-05714 for primary water chemistry and TR-102134 for secondary water chemistry. 

The program description and the evaluation and technical basis of monitoring and 

maintaining reactor water chemistry are presented in Chapter XI.M2, “Water Chemistry,” 

of this report.

3. Parameters Monitored/Inspected: The inspection activities in the program detect flaws 

in tubing, plugs, sleeving, and degradation of tube supports needed to maintain tube 

integrity. Tubes are repaired or removed from service based on technical specification 

repair criteria. Sleeves are removed from service based on technical specification repair 

criteria. Degraded plugs and tube supports are evaluated for corrective actions.

4. Detection of Aging Effects: The inspection requirements in the technical specifications 

are intended to detect tube and sleeve degradation (i.e., aging effects), if they should 

occur. NEI 97-06 provides additional guidance on inspection programs to detect 
NUREG-1801, Rev. 1 XI M-70 September 2005

degradation of tubes, sleeves, plugs and tube supports. The intent of the inspection and 

repair criteria is to provide assurance of continued tube integrity between inspections. A 

licensee’s response to GL 97-06 also provides a description of plant-specific inspection 

programs for detection of degraded SG internals.

5. Monitoring and Trending: Condition monitoring assessments are performed to 

determine whether structural and accident leakage criteria have been satisfied. 

Operational assessments are performed after inspections to verify that structural and 

leakage integrity will be maintained for the operating interval between inspections, which 

is selected in accordance with the technical specifications and NEI 97-06 guidelines. 

Comparison of the results of the condition monitoring assessment with the predictions of 

the previous operational assessment provides feedback for evaluation of the adequacy of 

the operational assessment and additional insights that can be incorporated into the next 

operational assessment.

6. Acceptance Criteria: Assessment of tube and sleeve integrity and plugging or repair 

criteria of flawed and sleeved tubes is in accordance with plant technical specifications. 

The criteria for plugging or repairing SG tubes and sleeves are based on NRC RG 1.121 

or other criteria previously reviewed and approved by the staff and incorporated into plant 

technical specifications. Some examples of acceptance criteria that are applicable under 

certain circumstances include F*, L*, or NRC Generic Letter (GL) 95-05, “Voltage-Based 

Repair Criteria for Westinghouse Steam Generator Tubes Affected by Outside-Diameter 

Stress-Corrosion Cracking.” 

7. Corrective Actions: Tubes and sleeves containing flaws that do not meet the acceptance 

criteria are plugged or repaired. Degraded plugs and tube supports are evaluated for 

corrective actions. As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective 

actions. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: Failures to detect some flaws, uncertainties in flaw sizing, 

inaccuracies in flaw locations, and the inability to detect some cracks at locations with 

dents have been reviewed in NRC Information Notice (IN) 97-88. Recent experience 

indicates the importance of performing a complete inspection by using appropriate 

techniques and components for the reliable detection of tube degradation and to provide 

assurance that new forms of degradation are detected. Implementation of the program 

provides reasonable assurance that SG tube integrity is maintained consistent with the 

plants’ licensing basis for the period of extended operation. Experience with the condition 

monitoring and operational assessments required for plants that have implemented the 

alternate repair criteria in NRC GL 95-05 has shown that the predictions of the operational 

assessments have generally been consistent with the results of the subsequent condition 

monitoring assessments. In cases where discrepancies have been noted, adjustments 

have been made in the operational assessment models to improve agreement in 
September 2005 XI M-71 NUREG-1801, Rev. 1

subsequent assessments. In addition, the industry has programs/processes for 

incorporating lessons learned from plant operation into guidelines referenced in NEI 97-

06.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

10 CFR Part 50.55a, Codes and Standards, Office of the Federal Register, National Archives 

and Records Administration, 2005.

EPRI TR-102134, PWR Secondary Water Chemistry Guidelines: Revision 3, Electric Power 

Research Institute, Palo Alto, CA, May 1993.

EPRI TR-105714, PWR Primary Water Chemistry Guidelines: Revision 3, Electric Power 

Research Institute, Palo Alto, CA, November 1995.

EPRI TR-107569, PWR Steam Generator Examination Guidelines: Revision 6, Electric Power 

Research Institute, Palo Alto, CA, October 2002.

NEI 97-06, Rev. 1, Steam Generator Program Guidelines, Nuclear Energy Institute, January 

2001.

NRC Generic Letter 95-05, Voltage-Based Repair Criteria for Westinghouse Steam Generator 

Tubes Affected by Outside-Diameter Stress-Corrosion Cracking, U.S. Nuclear Regulatory 

Commission, August 3, 1995.

NRC Generic Letter 97-06, Degradation of Steam Generator Internals, U.S. Nuclear Regulatory 

Commission, December 30, 1997.

NRC Information Notice, 97-88, Experiences during Recent Steam Generator Inspections, U.S. 

Nuclear Regulatory Commission, December 12, 1997.

NRC Regulatory Guide, 1.83, Rev. 1, Inservice Inspection of Pressurized Water Reactor Steam 

Generator Tubes, U.S. Nuclear Regulatory Commission, July 1975.

NRC Regulatory Guide, 1.121, Bases for Plugging Degraded PWR Steam Generator Tubes, 

U.S. Nuclear Regulatory Commission, August 1976.

NUREG-1430, Rev. 1, Standard Technical Specifications for Babcock and Wilcox Pressurized 

Water Reactors, U.S. Nuclear Regulatory Commission, April 1995.

NUREG-1431, Rev. 1, Standard Technical Specifications for Westinghouse Pressurized Water 

Reactors, U.S. Nuclear Regulatory Commission, April 1995.

NUREG-1432, Rev. 1, Standard Technical Specifications for Combustion Engineering 

Pressurized Water Reactors, U.S. Nuclear Regulatory Commission, April 1995.
NUREG-1801, Rev. 1 XI M-72 September 2005

XI.M20 OPEN-CYCLE COOLING WATER SYSTEM

Program Description

The program relies on implementation of the recommendations of the Nuclear Regulatory 

Commission (NRC) Generic Letter (GL) 89-13 to ensure that the effects of aging on the opencycle cooling water (OCCW) (or service water) system will be managed for the extended period 

of operation. The program includes surveillance and control techniques to manage aging effects 

caused by biofouling, corrosion, erosion, protective coating failures, and silting in the OCCW 

system or structures and components serviced by the OCCW system.

Evaluation and Technical Basis

1. Scope of Program: The program addresses the aging effects of material loss and fouling 

due to micro- or macro-organisms and various corrosion mechanisms. Because the 

characteristics of the service water system may be specific to each facility, the OCCW 

system is defined as a system or systems that transfer heat from safety-related systems, 

structures, and components (SSC) to the ultimate heat sink (UHS). If an intermediate 

system is used between the safety-related SSCs and the system rejecting heat to the 

UHS, that intermediate system performs the function of a service water system and is thus 

included in the scope of recommendations of NRC GL 89-13. The guidelines of NRC 

GL 89-13 include (a) surveillance and control of biofouling; (b) a test program to verify 

heat transfer capabilities; (c) routine inspection and a maintenance program to ensure that 

corrosion, erosion, protective coating failure, silting, and biofouling cannot degrade the 

performance of safety-related systems serviced by OCCW; (d) a system walk down

inspection to ensure compliance with the licensing basis; and (e) a review of maintenance, 

operating, and training practices and procedures.

2. Preventive Actions: The system components are constructed of appropriate materials 

and lined or coated to protect the underlying metal surfaces from being exposed to 

aggressive cooling water environments. Implementation of NRC GL 89-13 includes a 

condition and performance monitoring program; control or preventive measures, such as 

chemical treatment, whenever the potential for biological fouling species exists; or flushing 

of infrequently used systems. Treatment with chemicals mitigates microbiologicallyinfluenced corrosion (MIC) and buildup of macroscopic biological fouling species, such as 

blue mussels, oysters, or clams. Periodic flushing of the system removes accumulations 

of biofouling agents, corrosion products, and silt.

3. Parameters Monitored/Inspected: Adverse effects on system or component 

performance are caused by accumulations of biofouling agents, corrosion products, and 

silt. Cleanliness and material integrity of piping, components, heat exchangers, 

elastomers, and their internal linings or coatings (when applicable) that are part of the 

OCCW system or that are cooled by the OCCW system are periodically inspected, 

monitored, or tested to ensure heat transfer capabilities. The program ensures (a) removal 

of accumulations of biofouling agents, corrosion products, and silt, and (b) detection of 

defective protective coatings and corroded OCCW system piping and components that 

could adversely affect performance of their intended safety functions.

4. Detection of Aging Effects: Inspections for biofouling, damaged coatings, and degraded 

material condition are conducted. Visual inspections are typically performed; however, 

nondestructive testing, such as ultrasonic testing, eddy current testing, and heat transfer 
September 2005 XI M-73 NUREG-1801, Rev. 1

capability testing, are effective methods to measure surface condition and the extent of 

wall thinning associated with the service water system piping and components, when 

determined necessary.

5. Monitoring and Trending: Inspection scope, method (e.g., visual or nondestructive 

examination [NDE]), and testing frequencies are in accordance with the utility 

commitments under NRC GL 89-13. Testing and inspections are done annually and 

during refueling outages. Inspections or nondestructive testing will determine the extent of 

biofouling, the condition of the surface coating, the magnitude of localized pitting, and the 

amount of MIC, if applicable. Heat transfer testing results are documented in plant test 

procedures and are trended and reviewed by the appropriate group.

6. Acceptance Criteria: Biofouling is removed or reduced as part of the surveillance and 

control process. The program for managing biofouling and aggressive cooling water 

environments for OCCW systems is preventive. Acceptance criteria are based on effective 

cleaning of biological fouling organisms and maintenance of protective coatings or linings 

are emphasized. 

7. Corrective Actions: Evaluations are performed for test or inspection results that do not 

satisfy established acceptance criteria and a problem or condition report is initiated to 

document the concern in accordance with plant administrative procedures. The corrective 

actions program ensures that the conditions adverse to quality are promptly corrected. If 

the deficiency is assessed to be significantly adverse to quality, the cause of the condition 

is determined, and an action plan is developed to preclude repetition. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address the corrective actions.

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: Significant microbiologically-influenced corrosion (NRC 

Information Notice [IN] 85-30), failure of protective coatings (NRC IN 85-24), and fouling 

(NRC IN 81-21, IN 86-96) have been observed in a number of heat exchangers. The 

guidance of NRC GL 89-13 has been implemented for approximately 10 years and has 

been effective in managing aging effects due to biofouling, corrosion, erosion, protective 

coating failures, and silting in structures and components serviced by OCCW systems. 

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

NRC Generic Letter 89-13, Service Water System Problems Affecting Safety-Related 

Components, U.S. Nuclear Regulatory Commission, July 18, 1989. 
NUREG-1801, Rev. 1 XI M-74 September 2005

NRC Generic Letter 89-13, Supplement 1, Service Water System Problems Affecting SafetyRelated Components, U.S. Nuclear Regulatory Commission, April 4, 1990.

NRC Information Notice 81-21, Potential Loss of Direct Access to Ultimate Heat Sink, 

U.S. Nuclear Regulatory Commission, July 21, 1981.

NRC Information Notice 85-24, Failures of Protective Coatings in Pipes and Heat Exchangers, 

U.S. Nuclear Regulatory Commission, March 26, 1985.

NRC Information Notice 85-30, Microbiologically Induced Corrosion of Containment Service 

Water System, U.S. Nuclear Regulatory Commission, April 19, 1985.

NRC Information Notice 86-96, Heat Exchanger Fouling Can Cause Inadequate Operability of 

Service Water Systems, U.S. Nuclear Regulatory Commission, November 20, 1986.
September 2005 XI M-75 NUREG-1801, Rev. 1

XI.M21 CLOSED-CYCLE COOLING WATER SYSTEM

Program Description

The program includes (a) preventive measures to minimize corrosion and stress corrosion 

cracking (SCC) and (b) testing and inspection to monitor the effects of corrosion and SCC on 

the intended function of the component. The program relies on maintenance of system 

corrosion inhibitor concentrations within the specified limits of Electric Power Research Institute 

(EPRI) TR-107396 to minimize corrosion and SCC. Non-chemistry monitoring techniques such 

as testing and inspection in accordance with guidance in EPRI TR-107396 for closed-cycle 

cooling water (CCCW) systems provide one acceptable method to evaluate system and 

component performance. These measures will ensure that the intended functions of the CCCW 

system and components serviced by the CCCW system are not compromised by aging.

Evaluation and Technical Basis

1. Scope of Program: A CCCW system is defined as part of the service water system that 

is not subject to significant sources of contamination, in which water chemistry is 

controlled and in which heat is not directly rejected to a heat sink. The program described 

in this section applies only to such a system. If one or more of these conditions are not 

satisfied, the system is to be considered an open-cycle cooling water system. The staff 

notes that if the adequacy of cooling water chemistry control cannot be confirmed, the 

system is treated as an open-cycle system as indicated in Action III of Generic Letter (GL) 

89-13. 

2. Preventive Actions: The program relies on the use of appropriate materials, lining, or 

coating to protect the underlying metal surfaces and maintain system corrosion inhibitor 

concentrations within the specified limits of EPRI TR-107396 to minimize corrosion and 

SCC. The program includes monitoring and control of cooling water chemistry to minimize 

exposure to aggressive environments and application of corrosion inhibitor in the CCCW 

system to mitigate general, crevice, and pitting corrosion as well as SCC.

3. Parameters Monitored/Inspected: The aging management program monitors the effects 

of corrosion and SCC by testing and inspection in accordance with guidance in EPRI TR107396 to evaluate system and component condition. For pumps, the parameters 

monitored include flow, discharge pressures, and suction pressures. For heat exchangers, 

the parameters monitored include flow, inlet and outlet temperatures, and differential 

pressure.

4. Detection of Aging Effects: Control of water chemistry does not preclude corrosion or 

SCC at locations of stagnant flow conditions or crevices. Degradation of a component due 

to corrosion or SCC would result in degradation of system or component performance. 

The extent and schedule of inspections and testing should assure detection of corrosion 

or SCC before the loss of the intended function of the component. Performance and 

functional testing ensures acceptable functioning of the CCCW system or components 

serviced by the CCCW system. For systems and components in continuous operation, 

performance adequacy should be verified by monitoring component performance through

data trends for evaluation of heat transfer capability, system branch flow changes and 

chemistry data trends. Components not normally in operation are periodically tested to 

ensure operability.
NUREG-1801, Rev. 1 XI M-76 September 2005

5. Monitoring and Trending: The frequency of sampling water chemistry varies and can 

occur on a continuous, daily, weekly, or as needed basis, as indicated by plant operating 

conditions and the type of chemical treatment. In accordance with EPRI TR-107396, 

internal visual inspections and performance/functional tests are to be performed 

periodically to demonstrate system operability and confirm the effectiveness of the 

program. Tests to evaluate heat removal capability of the system and degradation of 

system components may also be used. The testing intervals should be established based

on plant-specific considerations such as system conditions, trending, and past operating 

experience, and may be adjusted based on the results of a reliability analysis, type of 

service, frequency of operation, or age of components and systems.

6. Acceptance Criteria: Corrosion inhibitor concentrations are maintained within the limits 

specified in the EPRI water chemistry guidelines for CCCW. System and component 

performance test results are evaluated in accordance with system and component design 

basis requirements. Acceptance criteria and tolerances are to be based on system design 

parameters and functions.

7. Corrective Actions: Corrosion inhibitor concentrations outside the allowable limits are 

returned to the acceptable range within the time period specified in the EPRI water 

chemistry guidelines for CCCW. If the system or component fails to perform adequately, 

corrective actions are taken. As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective 

actions.

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: Degradation of closed-cycle cooling water systems due to 

corrosion product buildup (NRC Licensee Event Report [LER] 50-327/93-029-00) or 

through-wall cracks in supply lines (NRC 50-280/91-019-00) has been observed in 

operating plants. Accordingly, operating experience demonstrates the need for this 

program.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

EPRI TR-107396, Closed Cooling Water Chemistry Guidelines, Electric Power Research 

Institute, Palo Alto, CA, October 1997.

NRC Generic Letter 89-13, Service Water System Problems Affecting Safety-Related 

Components, U.S. Nuclear Regulatory Commission, July 18, 1989.

NRC Generic Letter 89-13, Supplement 1, Service Water System Problems Affecting SafetyRelated Components, U.S. Nuclear Regulatory Commission, April 4, 1990.
September 2005 XI M-77 NUREG-1801, Rev. 1

NRC Licensee Event Report LER 50-280/91-019-00, Loss of Containment Integrity due to Crack 

in Component Cooling Water Piping, October 26, 1991.

NRC Licensee Event Report LER 50-327/93-029-00, Inoperable Check Valve in the Component 

Cooling System as a Result of a Build-Up of Corrosion Products between Valve 

Components, December 13, 1993.
NUREG-1801, Rev. 1 XI M-78 September 2005

XI.M22 BORAFLEX MONITORING

Program Description

A Boraflex monitoring program for the actual Boraflex panels is implemented in the spent fuel 

racks to assure that no unexpected degradation of the Boraflex material would compromise the 

criticality analysis in support of the design of spent fuel storage racks. The applicable aging 

management program (AMP), based on manufacturer’s recommendations, relies on periodic 

inspection, testing, monitoring, and analysis of the criticality design to assure that the required 

5% subcriticality margin is maintained. The frequency of the inspection and testing depends on 

the condition of the Boraflex, with a maximum of five years. Certain accelerated samples are 

tested every two years. Results based on test coupons have been found to be unreliable in 

determining the degree to which the actual Boraflex panels have been degraded. Therefore, this 

AMP includes: (1) performing neutron attenuation testing, called blackness testing, to determine 

gap formation in Boraflex panels; (2) completing sampling and analysis for silica levels in the 

spent fuel pool water and trending the results by using the EPRI RACKLIFE predictive code or 

its equivalent on a monthly, quarterly, or annual basis (depending on Boraflex panel condition); 

and (3) measuring boron areal density by techniques such as the BADGER device. Corrective 

actions are initiated if the test results find that the 5% subcriticality margin cannot be maintained 

because of current or projected future Boraflex degradation.

Evaluation and Technical Basis

1. Scope of Program: The AMP manages the effects of aging on sheets of neutronabsorbing materials affixed to spent fuel racks. For Boraflex panels, gamma irradiation 

and long-term exposure to the wet pool environment cause shrinkage resulting in gap 

formation, gradual degradation of the polymer matrix, and the release of silica to the spent 

fuel storage pool water. This results in the loss of boron carbide in the neutron absorber 

sheets. 

2. Preventive Actions: For Boraflex panels, monitoring silica levels in the storage pool

water, measuring gap formation by blackness testing, periodically measuring boron areal 

density, and applying predictive codes, are performed. These actions ensure that 

degradation of the neutron-absorbing material is identified and corrected so the spent fuel 

storage racks will be capable of performing their intended functions during the period of 

extended operation, consistent with current licensing basis (CLB) design conditions.

3. Parameters Monitored/Inspected: The parameters monitored include physical 

conditions of the Boraflex panels, such as gap formation and decreased boron areal 

density, and the concentration of the silica in the spent fuel pool. These are conditions 

directly related to degradation of the Boraflex material. When Boraflex is subjected to 

gamma radiation and long-term exposure to the spent fuel pool environment, the silicon 

polymer matrix becomes degraded and silica filler and boron carbide are released into the 

spent fuel pool water. As indicated in the Nuclear Regulatory Commission (NRC) 

Information Notice (IN) 95-38 and NRC Generic Letter (GL) 96-04, the loss of boron 

carbide (washout) from Boraflex is characterized by slow dissolution of silica from the 

surface of the Boraflex and a gradual thinning of the material. Because Boraflex contains 

about 25% silica, 25% polydimethyl siloxane polymer, and 50% boron carbide, sampling 

and analysis of the presence of silica in the spent fuel pool provide an indication of 

depletion of boron carbide from Boraflex; however, the degree to which Boraflex has 

degraded is ascertained through measurement of the boron areal density. 
September 2005 XI M-79 NUREG-1801, Rev. 1

4. Detection of Aging Effects: The amount of boron carbide released from the Boraflex 

panel is determined through direct measurement of boron areal density and correlated 

with the levels of silica present with a predictive code. This is supplemented with detection 

of gaps through blackness testing and periodic verification of boron loss through areal 

density measurement techniques such as the BADGER device. 

5. Monitoring and Trending: The periodic inspection measurements and analysis are to be 

compared to values of previous measurements and analysis to provide a continuing level 

of data for trend analysis.

6. Acceptance Criteria: The 5% subcriticality margin of the spent fuel racks is to be 

maintained for the period of extended operation.

7. Corrective Actions: Corrective actions are initiated if the test results find that the 5% 

subcriticality margin cannot be maintained because of the current or projected future 

degradation. Corrective actions consist of providing additional neutron-absorbing capacity 

by Boral or boron steel inserts, or other options, which are available to maintain a 

subcriticality margin of 5%. As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective 

actions.

8. Confirmation Process: Site quality assurance (QA) procedures, site review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: See item 8, above.

10. Operating Experience: The NRC IN 87-43 addresses the problems of development of 

tears and gaps (average 1-2 in., with the largest 4 in.) in Boraflex sheets due to gamma 

radiation-induced shrinkage of the material. NRC INs 93-70 and 95-38 and NRC GL 96-04 

address several cases of significant degradation of Boraflex test coupons due to 

accelerated dissolution of Boraflex caused by pool water flow through panel enclosures 

and high accumulated gamma dose. Two spent fuel rack cells with about 12 years of 

service have only 40% of the Boraflex remaining. In such cases, the Boraflex may be 

replaced by boron steel inserts or by a completely new rack system using Boral. 

Experience with boron steel is limited; however, the application of Boral for use in the 

spent fuel storage racks predates the manufacturing and use of Boraflex. The experience 

with Boraflex panels indicates that coupon surveillance programs are not reliable. 

Therefore, during the period of extended operation, the measurement of boron areal 

density correlated, through a predictive code, with silica levels in the pool water is verified. 

These monitoring programs provide assurance that degradation of Boraflex sheets is 

monitored, so that appropriate actions can be taken in a timely manner if significant loss of 

neutron-absorbing capability is occurring. These monitoring programs ensure that the 

Boraflex sheets will maintain their integrity and will be effective in performing its intended 

function. 
NUREG-1801, Rev. 1 XI M-80 September 2005

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

BNL-NUREG-25582, Corrosion Considerations in the Use of Boral in Spent Fuel Storage Pool 

Racks, January 1979.

EPRI NP-6159, An Assessment of Boraflex Performance in Spent-Nuclear-Fuel Storage Racks, 

Electric Power Research Institute, Palo Alto, CA, December 14, 1988.

EPRI TR-101986, Boraflex Test Results and Evaluation, Electric Power Research Institute, 

Palo Alto, CA, March 1, 1993.

EPRI TR-103300, Guidelines for Boraflex Use in Spent-Fuel Storage Racks, Electric Power 

Research Institute, Palo Alto, CA, December 1, 1993.

NRC Generic Letter 96-04, Boraflex Degradation in Spent Fuel Pool Storage Racks, 

U.S. Nuclear Regulatory Commission, June 26, 1996.

NRC Information Notice 87-43, Gaps in Neutron Absorbing Material in High Density Spent Fuel 

Storage Racks, U.S. Nuclear Regulatory Commission, September 8, 1987.

NRC Information Notice 93-70, Degradation of Boraflex Neutron Absorber Coupons, 

U.S. Nuclear Regulatory Commission, September 10, 1993.

NRC Information Notice 95-38, Degradation of Boraflex Neutron Absorber in Spent Fuel 

Storage Racks, U.S. Nuclear Regulatory Commission, September 8, 1995.

NRC Regulatory Guide 1.26, Rev. 3, Quality Group Classifications and Standards for Water, 

Steam, and Radioactive-Waste-Containing Components of Nuclear Power Plants (for 

Comment), U.S. Nuclear Regulatory Commission, February 1976.
September 2005 XI M-81 NUREG-1801, Rev. 1

XI.M23 INSPECTION OF OVERHEAD HEAVY LOAD AND LIGHT LOAD (RELATED TO 

REFUELING) HANDLING SYSTEMS

Program Description

Most commercial nuclear facilities have between 50 and 100 cranes. Many are industrial grade 

cranes, which meet the requirements of 29 CFR Volume XVII, Part 1910, and Section 1910.179. 

Most are not within the scope of 10 CFR 54.4, and therefore are not required to be part of the 

integrated plant assessment (IPA). 

Normally, fewer than 10 cranes fall within the scope of 10 CFR 54.4. 

The program demonstrates that testing and monitoring programs have been implemented and 

have ensured that the structures, systems, and components of these cranes are capable of 

sustaining their rated loads. This is their intended function during the period of extended 

operation. It is noted that many of the systems and components of these cranes perform an 

intended function with moving parts or with a change in configuration, or subject to replacement 

based on qualified life. In these instances, these types of crane systems and components are 

not within the scope of this aging management program (AMP). This program is primarily 

concerned with structural components that make up the bridge and trolley. NUREG-0612, 

“Control of Heavy Loads at Nuclear Power Plants,” provides specific guidance on the control of 

overhead heavy load cranes. 

Evaluation and Technical Basis

1. Scope of Program: The program manages the effects of general corrosion on the crane 

and trolley structural components for those cranes that are within the scope of 10 CFR 

54.4, and the effects of wear on the rails in the rail system.

2. Preventive Actions: No preventive actions are identified. The crane program is an 

inspection program.

3. Parameters Monitored/Inspected: The program evaluates the effectiveness of the 

maintenance monitoring program and the effects of past and future usage on the 

structural reliability of cranes. 

4. Detection of Aging Effect: Crane rails and structural components are visually inspected 

on a routine basis for degradation.

5. Monitoring and Trending: Monitoring and trending are not required as part of the crane 

inspection program.

6. Acceptance Criteria: Any significant visual indication of loss of material due to corrosion 

or wear is evaluated according to applicable industry standards and good industry 

practice. The crane may also have been designed to a specific Service Class as defined 

in the Crane Manufacturers Association of America, Inc. (CMAA) Specification #70 (or 

later revisions), or CMAA Specification #74 (or later revisions). The specification that was 

applicable at the time the crane was manufactured is used. 
NUREG-1801, Rev. 1 XI M-82 September 2005

7. Corrective Actions: Site corrective actions program, quality assurance (QA) procedures, 

site review and approval process, and administrative controls are implemented in 

accordance with the requirements of 10 CFR Part 50, Appendix B. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address the corrective actions, confirmation process, and administrative 

controls.

8. Confirmation Process: See Item 7, above.

9. Administrative Controls: See Item 7, above.

10. Operating Experience There has been no history of corrosion-related degradation that 

has impaired cranes. Likewise, because cranes have not been operated beyond their 

design lifetime, there have been no significant fatigue-related structural failures.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

Crane Manufactures Association of America, Inc., CMAA Specification No. 70, Specifications for 

Electric Overhead Traveling Cranes, 1970 (or later revisions)

Crane Manufactures Association of America, Inc., CMAA Specification No. 74, Specifications for 

Top Running and Under Running Single Girder Electric Overhead Traveling Cranes, 1974 

(or later revisions)

Electric Overhead Crane Institute, Inc

NUREG-0612, Control of Heavy Loads at Nuclear Power Plants, U.S. Nuclear Regulatory 

Commission, 1980.

NRC Regulatory Guide 1.160, Rev. 2, Monitoring the Effectiveness of Maintenance at Nuclear 

Power Plants, U.S. Nuclear Regulatory Commission, March 1997.
September 2005 XI M-83 NUREG-1801, Rev. 1

XI.M24 COMPRESSED AIR MONITORING

Program Description

The program consists of inspection, monitoring, and testing of the entire system. This includes

(a) frequent leak testing of valves, piping, and other system components, especially those made 

of carbon steel and stainless steel; and (b) preventive monitoring that checks air quality at 

various locations in the system to ensure that oil, water, rust, dirt, and other contaminants are 

kept within the specified limits. The aging management program (AMP) provides for timely 

corrective actions to ensure that the system is operating within specified limits.

The AMP is based on results of the plant owner’s response to Nuclear Regulatory Commission 

(NRC) Generic Letter (GL) 88-14, augmented by previous NRC Information Notices (IN) 81-38, 

IN 87-28, and IN 87-28 S1, and by the Institute of Nuclear Power Operations Significant 

Operating Experience Report (INPO SOER) 88-01. The NRC GL 88-14, issued after several 

years of study of problems and failures of instrument air systems, recommends each holder of 

an operating license to perform an extensive design and operations review and verification of its 

instrument air system. The GL 88-14 also recommends the licensees to describe their program 

for maintaining proper instrument air quality. The AMP also incorporates provisions conforming 

to the guidance of the Electric Power Research Institute (EPRI) NP-7079, issued in 1990, to 

assist utilities in identifying and correcting system problems in the instrument air system and to 

enable them to maintain required industry safety standards. Subsequent to these initial actions 

by all plant licensees to implement an improved AMP, some utilities decided to replace their 

instrument air system with newer models and types of components. The EPRI then issued 

TR-108147, which addresses maintenance of the latest compressors and other instrument air 

system components currently in use at those plants. The American Society of Mechanical 

Engineers operations and maintenance standards and guides (ASME OM-S/G-1998, Part 17) 

provides additional guidance to the maintenance of the instrument air system by offering 

recommended test methods, test intervals, parameters to be measured and evaluated, 

acceptance criteria, corrective actions, and records requirements.

Evaluation and Technical Basis

1. Scope of Program: The program manages the effects of corrosion and the presence of 

unacceptable levels of contaminants on the intended function of the compressed air 

system. The AMP includes frequent leak testing of valves, piping, and other system 

components, especially those made of carbon steel and stainless steel, and a preventive 

maintenance program to check air quality at several locations in the system.

2. Preventive Actions: The system air quality is monitored and maintained in accordance 

with the plant owner’s testing and inspection plans, which are designed to ensure that the 

system and components meet specified operability requirements. These requirements are 

prepared from consideration of manufacturer's recommendations for individual 

components and guidelines based on ASME OM-S/G-1998, Part 17; ISA-S7.0.01-1996; 

EPRI NP-7079; and EPRI TR-108147. The preventive maintenance program addresses 

various aspects of the inoperability of air-operated components due to corrosion and the 

presence of oil, water, rust, and other contaminants.

3. Parameters Monitored/Inspected: Inservice inspection (ISI) and testing is performed to 

verify proper air quality and confirm that maintenance practices, emergency procedures, 
NUREG-1801, Rev. 1 XI M-84 September 2005

and training are adequate to ensure that the intended function of the air system is 

maintained.

4. Detection of Aging Effects: Guidelines in EPRI NP-7079, EPRI TR-108147, and ASME 

OM-S/G-1998, Part 17, ensure timely detection of degradation of the compressed air 

system function. Degradation of the piping and any components would become evident by 

observation of excessive corrosion, by the discovery of unacceptable leakage rates, and 

by failure of the system or any item of components to meet specified performance limits.

5. Monitoring and Trending: Effects of corrosion and the presence of contaminants are 

monitored by visual inspection and periodic system and component tests, including leak 

rate tests on the system and on individual items of components. These tests verify proper 

operation by comparing measured values of performance with specified performance 

limits. Test data are analyzed and compared to data from previous tests to provide for 

timely detection of aging effects.

6. Acceptance Criteria: Acceptance criteria are established for the system and for 

individual components that contain specific limits or acceptance ranges based on design 

basis conditions and/or components vendor specifications. The testing results are 

analyzed to verify that the design and performance of the system is in accordance with its 

intended function.

7. Corrective Actions: Corrective actions are taken if any parameters are out of acceptable 

ranges, such as moisture content in the system air. As discussed in the appendix to this 

report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to 

address the corrective actions.

8. Confirmation Process: The site corrective actions program, quality assurance (QA) 

procedures, site review and approval process, and administrative controls are 

implemented in accordance with the requirements of 10 CFR Part 50, Appendix B. As 

discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 

50, Appendix B, acceptable to address the confirmation process and administrative 

controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: Potentially significant safety-related problems pertaining to air 

systems have been documented in NRC IN 81-38, IN 87-28, IN 87-28 S1 and license 

event report (LER) 50-237/94-005-3. Some of the systems that have been significantly 

degraded or have failed due to the problems in the air system include the decay heat 

removal, auxiliary feedwater, main steam isolation, containment isolation, and fuel pool 

seal system. As a result of NRC GL 88-14 and consideration of INPO SOER 88-01, EPRI 

NP-7079, and EPRI TR-108147, performance of air systems has improved significantly.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.
September 2005 XI M-85 NUREG-1801, Rev. 1

ASME OM-S/G-1998, Part 17, Performance Testing of Instrument Air Systems Information 

Notice Light-Water Reactor Power Plants, 1ISA-S7.0.1-1996, “Quality Standard for 

Instrument Air,” American Society of Mechanical Engineers, New York, NY, 1998.

EPRI NP-7079, Instrument Air System: A Guide for Power Plant Maintenance Personnel, 

Electric Power Research Institute, Palo Alto, CA, December 1990.

EPRI/NMAC TR-108147, Compressor and Instrument Air System Maintenance Guide: Revision 

to NP-7079, Electric Power Research Institute, Palo Alto, CA., March 1998.

INPO SOER 88-01, Instrument Air System Failures, May 18, 1988.

NRC Generic Letter 88-14, Instrument Air Supply Problems Affecting Safety-Related 

Components, U.S. Nuclear Regulatory Commission, August 8, 1988.

NRC Information Notice 81-38, Potentially Significant Components Failures Resulting from 

Contamination of Air-Operated Systems, U.S. Nuclear Regulatory Commission, 

December 17, 1981.

NRC Information Notice 87-28, Air Systems Problems at U.S. Light Water Reactors, 

U.S. Nuclear Regulatory Commission, June 22, 1987.

NRC Information Notice 87-28, Supplement 1, Air Systems Problems at U.S. Light Water 

Reactors, U.S. Nuclear Regulatory Commission, December 28, 1987.

NRC Licensee Event Report LER 50-237/94-005-3, Manual Reactor Scram due to Loss of 

Instrument Air Resulting from Air Receiver Pipe Failure Caused by Improper Installation of 

Threaded Pipe during Initial Construction, U.S. Nuclear Regulatory Commission, April 23, 

1997.
NUREG-1801, Rev. 1 XI M-86 September 2005

XI.M25 BWR REACTOR WATER CLEANUP SYSTEM

Program Description

The program includes inservice inspection (ISI) and monitoring and control of reactor coolant 

water chemistry to manage the effects of stress corrosion cracking (SCC) or intergranular stress 

corrosion cracking (IGSCC) on the intended function of austenitic stainless steel (SS) piping in 

the reactor water cleanup (RWCU) system. Based on the Nuclear Regulatory Commission 

(NRC) criteria related to inspection guidelines for RWCU piping welds outboard of the second 

isolation valve, the program includes the measures delineated in NUREG-0313, Rev. 2, and 

NRC Generic Letter (GL) 88-01. Coolant water chemistry is monitored and maintained in 

accordance with the Electric Power Research Institute (EPRI) guidelines in boiling water reactor 

vessel and internals project (BWRVIP) -29 (TR-103515) to minimize the potential of cracking

due to SCC or IGSCC.

Evaluation and Technical Basis

1. Scope of Program: Based on the NRC letter (September 15, 1995) on the screening 

criteria related to inspection guidelines for RWCU piping welds outboard of the second 

isolation valve, the program includes the measures delineated in NUREG-0313, Rev. 2, 

and NRC GL 88-01 to monitor SCC or IGSCC and its effects on the intended function of 

austenitic SS piping. The screening criteria include:

a. Satisfactory completion of all actions requested in NRC GL 89-10,

b. No detection of IGSCC in RWCU welds inboard of the second isolation valves 

(ongoing inspection in accordance with the guidance in NRC GL 88-01), and

c. No detection of IGSCC in RWCU welds outboard of the second isolation valves after 

inspecting a minimum of 10% of the susceptible piping.

No IGSCC inspection is recommended for plants that meet all the above three criteria or 

that meet criterion (a) and piping is made of material that is resistant to IGSCC.

2. Preventive Actions: The comprehensive program outlined in NUREG-0313 and 

NRC GL 88-01 addresses improvements in all three elements that, in combination, cause 

SCC or IGSCC. These elements are a susceptible (sensitized) material, a significant 

tensile stress, and an aggressive environment. The program delineated in NUREG-0313 

and NRC GL 88-01 includes recommendations regarding selection of materials that are 

resistant to sensitization, use of special processes that reduce residual tensile stresses, 

and monitoring and maintenance of coolant chemistry. The resistant materials are used 

for new and replacement components and include low-carbon grades of austenitic SS and 

weld metal, with a maximum carbon of 0.035 wt.% and a minimum ferrite of 7.5% in weld 

metal and cast austenitic stainless steel (CASS). Inconel 82 is the only commonly used 

nickel-base weld metal considered resistant to SCC; other nickel-alloys, such as Alloy 

600, are evaluated on an individual basis. Special processes are used for existing as well 

as new and replacement components. These processes include solution heat treatment, 

heat sink welding, induction heating, and mechanical stress improvement.

The program delineated in NUREG-0313 and NRC GL 88-01 varies depending on the 

plant- specific reactor water chemistry to mitigate SCC or IGSCC. 
September 2005 XI M-87 NUREG-1801, Rev. 1

3. Parameters Monitored/Inspected: The aging management program (AMP) monitors 

SCC or IGSCC of austenitic SS piping by detection and sizing of cracks by implementing 

the inspection guidelines delineated in the NRC screening criteria for the RWCU piping 

outboard of isolation valves. The following schedules are followed:

Schedule A: No inspection is required for plants that meet all three criteria set forth above, 

or if they meet only criterion (a). Piping is made of material that is resistant to IGSCC, as 

described above in preventive actions.

Schedule B: For plants that meet only criterion (a): Inspect at least 2% of the welds or two 

welds every refueling outage, whichever sample is larger.

Schedule C: For plants that do not meet criterion (a): Inspect at least 10% of the welds 

every refueling outage.

4. Detection of Aging Effects: The extent, method, and schedule of the inspection and test 

techniques delineated in the NRC inspection criteria for RWCU piping and NRC GL 88-01 

are designed to maintain structural integrity and to detect aging effects before the loss of 

intended function of austenitic SS piping and fittings. Guidelines for the inspection 

schedule, methods, personnel, sample expansion, and leak detection guidelines are 

based on the guidelines of NRC GL 88-01.

NRC GL 88-01 recommends that the detailed inspection procedure, components, and 

examination personnel be qualified by a formal program approved by the NRC. Inspection 

can reveal cracking and leakage of coolant. The extent and frequency of inspections 

recommended by the program are based on the condition of each weld (e.g., whether the 

weldments were made from IGSCC-resistant material, whether a stress improvement 

process was applied to a weldment to reduce the residual stresses, and how the weld was 

repaired if it had been cracked).

5. Monitoring and Trending: The extent and schedule for inspection in accordance with the 

recommendations of NRC GL 88-01 provide timely detection of cracks and leakage of 

coolant. Based on inspection results, NRC GL 88-01 provides guidelines for additional 

samples of welds to be inspected when one or more cracked welds are found in a weld 

category.

6. Acceptance Criteria: The NRC GL 88-01 recommends that any indication detected be 

evaluated in accordance with the requirements of ASME Section XI, Subsection IWB3640 (2001 edition8

 including the 2002 and 2003 Addenda).

7. Corrective Actions: The guidance for weld overlay repair, stress improvement, or 

replacement is provided in NRC GL 88-01. As discussed in the appendix to this report, the 

staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

corrective actions. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with requirements 

 

8

An applicant may rely on a different version of the ASME Code, but should justify such use. An 

applicant may wish to refer to the SOC for an update of 10 CFR § 50.55a to justify use of a more recent 

edition of the Code.
NUREG-1801, Rev. 1 XI M-88 September 2005

of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds 

the requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: The IGSCC has occurred in small- and large-diameter boiling 

water reactor (BWR) piping made of austenitic stainless steels or nickel alloys. The 

comprehensive program outlined in NRC GL 88-01 and NUREG-0313 addresses 

improvements in all elements that cause SCC or IGSCC (e.g., susceptible material, 

significant tensile stress, and an aggressive environment) and is effective in managing 

IGSCC in austenitic SS piping in the RWCU system.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 2001 edition including the 2002 and 2003 Addenda, 

American Society of Mechanical Engineers, New York, NY.

BWRVIP-29 (EPRI TR-103515), BWR Vessel and Internals Project, BWR Water Chemistry 

Guidelines-1993 Revision, Normal and Hydrogen Water Chemistry, Electric Power 

Research Institute, Palo Alto, CA, February 1994.

Letter from Joseph W. Shea, U.S. Nuclear Regulatory Commission, to George A. Hunter, Jr., 

PECO Energy Company, Reactor Water Cleanup (RWCU) System Weld Inspections at 

Peach Bottom Atomic Power Station, Units 2 and 3 (TAC Nos. M92442 and M92443), 

September 15, 1995. 

NRC Generic Letter 89-10, Safety-related Motor Operated Valve Testing and Surveillance, U.S. 

Nuclear Regulatory Commission, June 28, 1989; through supplement 7, January 24, 1996.

NRC Generic Letter 88-01, NRC Position on IGSCC in BWR Austenitic Stainless Steel Piping,

U.S. Nuclear Regulatory Commission, January 25, 1988.

NUREG-0313, Rev. 2, Technical Report on Material Selection and Processing Guidelines for 

BWR Coolant Pressure Boundary Piping, W. S. Hazelton and W. H. Koo, U.S. Nuclear 

Regulatory Commission, 1988.
September 2005 XI M-89 NUREG-1801, Rev. 1

XI.M26 FIRE PROTECTION

Program Description

For operating plants, the fire protection aging management program (AMP) includes 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 penetration 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 the intended function. The AMP also includes periodic inspection and testing of the

halon/carbon dioxide (CO2) fire suppression system. 

Evaluation and Technical Basis

1. Scope of Program: For operating plants, the AMP manages the aging effects on the 

intended function of the penetration seals, fire barrier walls, ceilings, and floors, and all fire 

rated doors (automatic or manual) that perform a fire barrier function. It also manages the 

aging effects on the intended function of the fuel supply line. The AMP also includes 

management of the aging effects on the intended function of the halon/CO2 fire 

suppression system. 

2. Preventive Actions: For operating plants, the fire hazard analysis assesses the fire 

potential and fire hazard in all plant areas. It also specifies measures for fire prevention, 

fire detection, fire suppression, and fire containment and alternative shutdown capability 

for each fire area containing structures, systems, and components important to safety. 

3. Parameters Monitored/Inspected: Visual inspection of approximately 10% of each type 

of penetration seal is performed during walkdowns carried out at least once every 

refueling outage. These inspections examine any sign of degradation such as cracking, 

seal separation from walls and components, separation of layers of material, rupture and 

puncture of seals, which are directly caused by increased hardness, and shrinkage of seal 

material due to weathering. Visual inspection of the fire barrier walls, ceilings, and floors 

examines any sign of degradation such as cracking, spalling, and loss of material caused 

by freeze-thaw, chemical attack, and reaction with aggregates. Fire-rated doors are 

visually inspected on a plant-specific interval to verify the integrity of door surfaces and for 

clearances. The plant-specific inspection intervals are to be determined by engineering 

evaluation to detect degradation of the fire doors prior to the loss of intended function.

The diesel-driven fire pump is under observation during performance tests such as flow 

and discharge tests, sequential starting capability tests, and controller function tests for 

detection of any degradation of the fuel supply line. 

The periodic visual inspection and function test is performed at least once every six 

months to examine the signs of degradation of the halon/CO2 fire suppression system. 

Material conditions that may affect the performance of the system, such as corrosion, 

mechanical damage, or damage to dampers, are observed during these tests.

4. Detection of Aging Effects: Visual inspection of penetration seals detects cracking, seal 

separation from walls and components, and rupture and puncture of seals. Visual 

inspection by fire protection qualified inspectors of approximately 10% of each type of seal 
NUREG-1801, Rev. 1 XI M-90 September 2005

in walkdowns is performed at least once every refueling cycle. If any sign of degradation is 

detected within that sample, the scope of the inspection is expanded to include additional 

seals. Visual inspection by fire protection qualified inspectors of the fire barrier walls, 

ceilings, and floors, performed in walkdowns at least once every refueling outage ensures 

timely detection of concrete cracking, spalling, and loss of material. Visual inspection by 

fire protection qualified inspectors detects any sign of degradation of the fire door such as 

wear and missing parts. Periodic visual inspection and function tests detect degradation of 

the fire doors before there is a loss of intended function. 

Periodic tests performed at least once every refueling outage, such as flow and discharge 

tests, sequential starting capability tests, and controller function tests performed on dieseldriven fire pump ensure fuel supply line performance. The performance tests detect 

degradation of the fuel supply lines before the loss of the component intended function. 

Visual inspections of the halon/CO2 fire suppression system detect any sign of added 

degradation, such as corrosion, mechanical damage, or damage to dampers. The periodic 

function test and inspection performed at least once every six months detects degradation 

of the halon/CO2 fire suppression system before the loss of the component intended 

function. 

5. Monitoring and Trending: The aging effects of weathering on fire barrier penetration 

seals are detectable by visual inspection and, based on operating experience, visual 

inspections are performed at least once every refueling outage to detect any sign of 

degradation of fire barrier penetration seals prior to loss of the intended function. 

Concrete cracking, spalling, and loss of material are detectable by visual inspection and, 

based on operating experience, visual inspection performed at least once every refueling 

outage detects any sign of degradation of the fire barrier walls, ceilings, and floors before 

there is a loss of the intended function. Based on operating experience, degraded integrity 

or clearances in the fire door are detectable by visual inspection performed on a plantspecific frequency. The visual inspections detect degradation of the fire doors prior to loss 

of the intended function.

The performance of the fire pump is monitored during the periodic test to detect any 

degradation in the fuel supply lines. Periodic testing provides data (e.g., pressure) for 

trending necessary. 

The performance of the halon/CO2 fire suppression system is monitored during the 

periodic test to detect any degradation in the system. These periodic tests provide data 

necessary for trending. 

6. Acceptance Criteria: Inspection results are acceptable if there are no visual indications 

(outside those allowed by approved penetration seal configurations) of cracking, 

separation of seals from walls and components, separation of layers of material, or 

ruptures or punctures of seals; no visual indications of concrete cracking, spalling and loss 

of material of fire barrier walls, ceilings, and floors; no visual indications of missing parts, 

holes, and wear and no deficiencies in the functional tests of fire doors. No corrosion is 

acceptable in the fuel supply line for the diesel-driven fire pump. Also, any signs of 

corrosion and mechanical damage of the halon/CO2 fire suppression system are not 

acceptable. 
September 2005 XI M-91 NUREG-1801, Rev. 1

7. Corrective Actions: For fire protection structures and components identified within scope 

that are subject to an AMR for license renewal, the applicant’s 10 CFR Part 50, Appendix 

B, program is used for corrective actions, confirmation process, and administrative 

controls for aging management during the period of extended operation. This commitment 

is documented in the final safety analysis report (FSAR) supplement in accordance with 

10 CFR 54.21(d). As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective 

actions, confirmation process, and administrative controls. 

8. Confirmation Process: See Item 7, above. 

9. Administrative Controls: See Item 7, above. 

10. Operating Experience: Silicone foam fire barrier penetration seals have experienced 

splits, shrinkage, voids, lack of fill, and other failure modes (IN 88-56, IN 94-28, and IN 97-

70). Degradation of electrical racing way fire barrier such as small holes, cracking, and 

unfilled seals are found on routine walkdown (IN 91-47 and GL 92-08). Fire doors have 

experienced wear of the hinges and handles. 

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

NRC Generic Letter 92-08, Thermo-Lag 330-1 Fire Barrier, U.S. Nuclear Regulatory 

Commission, December 17, 1992.

NRC Information Notice 88-56, Potential Problems with Silicone Foam Fire Barrier Penetration 

Seals, U.S. Nuclear Regulatory Commission, August 14, 1988. 

NRC Information Notice 91-47, Failure of Thermo-Lag Fire Barrier Material to Pass Fire 

Endurance Test, U.S. Nuclear Regulatory Commission, August 6, 1991. 

NRC Information Notice 94-28, Potential problems with Fire-Barrier Penetration Seals, U.S. 

Nuclear Regulatory Commission, April 5, 1994. 

NRC Information Notice 97-70, Potential problems with Fire Barrier Penetration Seals, U.S. 

Nuclear Regulatory Commission, September 19, 1997. 
NUREG-1801, Rev. 1 XI M-92 September 2005

XI. M27 FIRE WATER SYSTEM

Program Description

This aging management program (AMP) applies to water-based fire protection systems that 

consist of sprinklers, nozzles, fittings, valves, hydrants, hose stations, standpipes, water storage 

tanks, and aboveground and underground piping and components that are tested in accordance 

with the applicable National Fire Protection Association (NFPA) codes and standards. Such 

testing assures the minimum functionality of the systems. Also, these systems are normally 

maintained at required operating pressure and monitored such that loss of system pressure is 

immediately detected and corrective actions initiated. 

A sample of sprinkler heads is to be inspected by using the guidance of NFPA 25 “Inspection, 

Testing and Maintenance of Water-Based Fire Protection Systems” (1998 Edition), Section 2-

3.1.1, or NFPA 25 (2002 Edition), Section 5.3.1.1.1. This NFPA section states “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.

The fire protection system piping is to be subjected to required flow testing in accordance with 

guidance in NFPA 25 to verify design pressure or evaluated for wall thickness (e.g., nonintrusive volumetric testing or plant maintenance visual inspections) to ensure that aging effects 

are managed and that wall thickness is within acceptable limits. These inspections are 

performed before the end of the current operating term and at plant-specific intervals thereafter 

during the period of extended operation. The plant-specific inspection intervals are to be 

determined by engineering evaluation of the fire protection piping to ensure that degradation will 

be detected before the loss of intended function. The purpose of the full flow testing and wall 

thickness evaluations is to ensure that corrosion, MIC, or biofouling is managed such that the 

system function is maintained.

Evaluation and Technical Basis

1. Scope of Program: The AMP focuses on managing loss of material due to corrosion, 

MIC, or biofouling of carbon steel and cast-iron components in fire protection systems 

exposed to water. Hose stations and standpipes are considered as piping in the AMP. 

2. Preventive Actions: To ensure no significant corrosion, MIC, or biofouling has occurred 

in water-based fire protection systems, periodic flushing, system performance testing, and 

inspections may be conducted. 

3. Parameters Monitored/Inspected: Loss of material due to corrosion and biofouling could 

reduce wall thickness of the fire protection piping system and result in system failure. 

Therefore, the parameters monitored are the system’s ability to maintain pressure and 

internal system corrosion conditions. Periodic flow testing of the fire water system is

performed using the guidelines of NFPA 25, or wall thickness evaluations may be 

performed to ensure that the system maintains its intended function.

4. Detection of Aging Effects: Fire protection system testing is performed to assure that 

the system functions by maintaining required operating pressures. Wall thickness 

evaluations of fire protection piping are performed on system components using non-
September 2005 XI M-93 NUREG-1801, Rev. 1

intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to 

corrosion. These inspections are performed before the end of the current operating term 

and at plant-specific intervals thereafter during the period of extended operation. As an 

alternative to non-intrusive testing, the plant maintenance process may include a visual 

inspection of the internal surface of the fire protection piping upon each entry to the 

system for routine or corrective maintenance, as long as it can be demonstrated that 

inspections are performed (based on past maintenance history) on a representative 

number of locations on a reasonable basis. These inspections must be capable of 

evaluating (1) wall thickness to ensure against catastrophic failure and (2) the inner 

diameter of the piping as it applies to the design flow of the fire protection system. If the

environmental and material conditions that exist on the interior surface of the below grade 

fire protection piping are similar to the conditions that exist within the above grade fire 

protection piping, the results of the inspections of the above grade fire protection piping 

can be extrapolated to evaluate the condition of below grade fire protection piping. If not, 

additional inspection activities are needed to ensure that the intended function of below 

grade fire protection piping will be maintained consistent with the current licensing basis 

for the period of extended operation. Continuous system pressure monitoring, system flow 

testing, and wall thickness evaluations of piping are effective means to ensure that 

corrosion and biofouling are not occurring and the system’s intended function is 

maintained.

General requirements of existing fire protection programs include testing and maintenance 

of fire detection and protection systems and surveillance procedures to ensure that fire 

detectors, as well as fire protection systems and components are operable.

Visual inspection of yard fire hydrants performed annually in accordance with NFPA 25 

ensures timely detection of signs of degradation, such as corrosion. Fire hydrant hose 

hydrostatic tests, gasket inspections, and fire hydrant flow tests, performed annually, 

ensure that fire hydrants can perform their intended function and provide opportunities for 

degradation to be detected before a loss of intended function can occur. 

Sprinkler heads are inspected before the end of the 50-year sprinkler head service life and 

at 10-year intervals thereafter during the extended period of operation to ensure that signs 

of degradation, such as corrosion, are detected in a timely manner.

5. Monitoring and Trending: System discharge pressure is monitored continuously. 

Results of system performance testing are monitored and trended as specified by the 

associated plant commitments pertaining to NFPA codes and standards. Degradation 

identified by non-intrusive or internal inspection is evaluated. 

6. Acceptance Criteria: The acceptance criteria are (a) the ability of a fire protection system 

to maintain required pressure, (b) no unacceptable signs of degradation observed during 

non-intrusive or visual assessment of internal system conditions, and (c) that no biofouling 

exists in the sprinkler systems that could cause corrosion in the sprinkler heads. 

7. Corrective Actions: Repair and replacement actions are initiated as necessary. For fire 

water systems and components identified within scope that are subject to an AMR for 

license renewal, the applicant’s 10 CFR Part 50, Appendix B, program is used for 

corrective actions, confirmation process, and administrative controls for aging 

management during the period of extended operation. As discussed in the appendix to 
NUREG-1801, Rev. 1 XI M-94 September 2005

this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to 

address the corrective actions, confirmation process, and administrative controls.

8. Confirmation Process: See Item 7, above. 

9. Administrative Controls: See Item 7, above. 

10. Operating Experience: Water-based fire protection systems designed, inspected, tested 

and maintained in accordance with the NFPA minimum standards have demonstrated 

reliable performance. 

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

NFPA 25: Inspection, Testing and Maintenance of Water-Based Fire Protection Systems, 1998 

Edition.

NFPA 25: Inspection, Testing and Maintenance of Water-Based Fire Protection Systems, 2002 

Edition.
September 2005 XI M-95 NUREG-1801, Rev. 1

XI.M28 BURIED PIPING AND TANKS SURVEILLANCE

Program Description

The program includes surveillance and preventive measures to mitigate corrosion by protecting 

the external surface of buried carbon steel piping and tanks. Surveillance and preventive 

measures are in accordance with standard industry practice, based on National Association of 

Corrosion Engineers (NACE) Standards RP-0285-95 and RP-0169-96, and include external 

coatings, wrappings, and cathodic protection systems.

Evaluation and Technical Basis

1. Scope of Program: The program relies on preventive measures, such as coating, 

wrapping, and cathodic protection, and surveillance, based on NACE Standard RP-0285-

95 and NACE Standard RP-0169-96, to manage the effects of corrosion on the intended 

function of buried tanks and piping, respectively.

2. Preventive Actions: In accordance with industry practice, underground piping and tanks 

are coated during installation with a protective coating system, such as coal tar enamel 

with a fiberglass wrap and a kraft paper outer wrap, a polyolifin tape coating, or a fusion 

bonded epoxy coating to protect the piping from contacting the aggressive soil 

environment. A cathodic protection system is used to mitigate corrosion where pinholes in 

the coating allow the piping or components to be in contact with the aggressive soil 

environment. The cathodic protection imposes a current from an anode onto the pipe or 

tank to stop corrosion from occurring at defects in the coating.

3. Parameters Monitored/Inspected: The effectiveness of the coatings and cathodic 

protection system, per standard industry practice, is determined by measuring coating 

conductance, by surveying pipe-to-soil potential, and by conducting bell hole examinations 

to visually examine the condition of the coating.

4. Detection of Aging Effects: Coatings and wrapping can be damaged during installation 

or while in service and the cathodic protection system is relied upon to avoid any 

corrosion at the damaged locations. Degradation of the coatings and wrapping during 

service will result in the requirement for more current from the cathodic protection rectifier 

in order to maintain the proper cathodic protect potentials. Any increase in current 

requirements is an indication of coating and wrapping degradation. A close interval pipeto-soil potential survey can be used to locate the locations where degradation has 

occurred. 

5. Monitoring and Trending: Monitoring the coating conductance versus time or the current 

requirement versus time provides an indication of the condition of the coating and 

cathodic protection system when compared to predetermined values.

6. Acceptance Criteria: In accordance with accepted industry practice, per NACE Standard 

RP-0285-95 and NACE Standard RP-0169-96, the assessment of the condition of the 

coating and cathodic protection system is to be conducted on an annual basis and 

compared to predetermined values.
NUREG-1801, Rev. 1 XI M-96 September 2005

7. Corrective Actions: The site corrective actions program, quality assurance (QA) 

procedures, site review and approval process, and administrative controls are 

implemented in accordance with the requirements of 10 CFR Part 50, Appendix B. As 

discussed in the appendix to this report, the staff finds the requirements of 10 CFR 

Part 50, Appendix B, acceptable to address the corrective actions, confirmation process, 

and administrative controls.

8. Confirmation Process: See Item 7, above.

9. Administrative Controls: See Item 7, above.

10. Operating Experience: Corrosion pits from the outside diameter have been discovered in 

buried piping with far less than 60 years of operation. Buried pipe that is coated and 

cathodically protected is unaffected after 60 years of service. Accordingly, operating 

experience from application of the NACE standards on non-nuclear systems 

demonstrates the effectiveness of this program. 

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

NACE Standard RP-0169-96, Control of External Corrosion on Underground or Submerged 

Metallic Piping Systems, 1996. 

NACE Standard RP-0285-95, Corrosion Control of Underground Storage Tank Systems by 

Cathodic Protection, Approved March 1985, revised February 1995. 
September 2005 XI M-97 NUREG-1801, Rev. 1

XI.M29 ABOVEGROUND STEEL TANKS

Program Description

The program includes preventive measures to mitigate corrosion by protecting the external 

surface of steel tanks with paint or coatings in accordance with standard industry practice. The 

program also relies on periodic system walkdowns to monitor degradation of the protective paint 

or coating. However, for storage tanks supported on earthen or concrete foundations, corrosion 

may occur at inaccessible locations, such as the tank bottom. Accordingly, verification of the 

effectiveness of the program is to be performed to ensure that significant degradation in 

inaccessible locations is not occurring and the component intended function will be maintained 

during the extended period of operation. For reasons set forth below, an acceptable verification 

program consists of thickness measurement of the tank bottom surface.

Evaluation and Technical Basis

1. Scope of Program: The program consists of (a) preventive measures to mitigate 

corrosion by protecting the external surfaces of carbon steel tanks protected with paint or 

coatings and (b) periodic system walkdowns to manage the effects of corrosion on the 

intended function of these tanks. Plant walkdowns cover the entire outer surface of the 

tank up to its surface in contact with soil or concrete.

2. Preventive Actions: In accordance with industry practice, tanks are coated with 

protective paint or coating to mitigate corrosion by protecting the external surface of the 

tank from environmental exposure. Sealant or caulking at the interface edge between the 

tank and concrete or earthen foundation mitigates corrosion of the bottom surface of the 

tank by preventing water and moisture from penetrating the interface, which would lead to 

corrosion of the bottom surface.

3. Parameters Monitored/Inspected: The AMP utilizes periodic plant system walkdowns to 

monitor degradation of coatings, sealants, and caulking because it is a condition directly 

related to the potential loss of materials.

4. Detection of Aging Effects: Degradation of exterior carbon steel surfaces cannot occur 

without degradation of paint or coatings on the outer surface and of sealant and caulking 

at the interface between the component and concrete. Periodic system walkdowns to 

confirm that the paint, coating, sealant, and caulking are intact is an effective method to 

manage the effects of corrosion on the external surface of the component. However, 

corrosion may occur at inaccessible locations, such as the tank bottom surface, thus, 

thickness measurement of the tank bottom is to be taken to ensure that significant 

degradation is not occurring and the component intended function will be maintained 

during the extended period of operation.

5. Monitoring and Trending: The effects of corrosion of the aboveground external surface 

are detectable by visual techniques. Based on operating experience, plant system 

walkdowns during each outage provide for timely detection of aging effects. The effects of 

corrosion of the underground external surface are detectable by thickness measurement 

of the tank bottom and are monitored and trended if significant material loss is detected.

6. Acceptance Criteria: Any degradation of paint, coating, sealant, and caulking is reported 

and will require further evaluation. Degradation consists of cracking, flaking, or peeling of 
NUREG-1801, Rev. 1 XI M-98 September 2005

paint or coatings, and drying, cracking or missing sealant and caulking. Thickness 

measurements of the tank bottom are evaluated against the design thickness and 

corrosion allowance.

7. Corrective Actions: The site corrective actions program, quality assurance (QA) 

procedures, site review and approval process, and administrative controls are 

implemented in accordance with 10 CFR Part 50, Appendix B. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address the corrective actions, confirmation process, and administrative 

controls.

8. Confirmation Process: See Item 7, above.

9. Administrative Controls: See Item 7, above.

10. Operating Experience: Coating degradation, such as flaking and peeling, has occurred 

in safety-related systems and structures (Nuclear Regulatory Commission [NRC] Generic 

Letter [GL] 98-04). Corrosion damage near the concrete-metal interface and sand-metal 

interface has been reported in metal containments (NRC Information Notice [IN] 89-79, 

Supplement 1, and NRC IN 86-99, Supplement 1).

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

NRC Generic Letter 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, 

U.S. Nuclear Regulatory Commission, July 14, 1998.

NRC Information Notice 86-99, Degradation of Steel Containments, U.S. Nuclear Regulatory 

Commission, December 8, 1986.

NRC Information Notice 86-99, Supplement 1, Degradation of Steel Containments, U.S. Nuclear 

Regulatory Commission, February 14, 1991.

NRC Information Notice 89-79, Degraded Coatings and Corrosion of Steel Containment Vessel, 

U.S. Nuclear Regulatory Commission, December 1, 1989.

NRC Information Notice 89-79, Supplement 1, Degraded Coatings and Corrosion of Steel 

Containment Vessel, U.S. Nuclear Regulatory Commission, June 29, 1990.
September 2005 XI M-99 NUREG-1801, Rev. 1

XI.M30 FUEL OIL CHEMISTRY

Program Description

The program includes (a) surveillance and maintenance procedures to mitigate corrosion and 

(b) measures to verify the effectiveness of an aging management program (AMP) and confirm 

the insignificance of an aging effect. Fuel oil quality is maintained by monitoring and controlling 

fuel oil contamination in accordance with the plant’s technical specifications and the guidelines 

of the American Society for Testing Materials (ASTM) Standards D 1796, D 2276, D 2709, 

D6217, and D 4057. Exposure to fuel oil contaminants, such as water and microbiological 

organisms, is minimized by periodic draining or cleaning of tanks and by verifying the quality of 

new oil before its introduction into the storage tanks. However, corrosion may occur at locations 

in which contaminants may accumulate, such as tank bottoms. Accordingly, the effectiveness of 

the program is verified to ensure that significant degradation is not occurring and the 

component’s intended function will be maintained during the extended period of operation. 

Thickness measurement of tank bottom surfaces is an acceptable verification program.

Evaluation and Technical Basis

1. Scope of Program: The program is focused on managing the conditions that cause 

general, pitting, and microbiologically-influenced corrosion (MIC) of the diesel fuel tank 

internal surfaces in accordance with the plant’s technical specifications ( i.e., NUREG1430, NUREG-1431, NUREG-1432, NUREG-1433) on fuel oil purity and the guidelines of 

ASTM Standards D1796, D2276, D2709, D6217, and D4057. The program serves to 

reduce the potential of exposure of the tank internal surface to fuel oil contaminated with 

water and microbiological organisms.

2. Preventive Actions: The quality of fuel oil is maintained by additions of biocides to 

minimize biological activity, stabilizers to prevent biological breakdown of the diesel fuel, 

and corrosion inhibitors to mitigate corrosion. Periodic cleaning of a tank allows removal of 

sediments, and periodic draining of water collected at the bottom of a tank minimizes the 

amount of water and the length of contact time. Accordingly, these measures are effective 

in mitigating corrosion inside diesel fuel oil tanks. Coatings, if used, prevent or mitigate 

corrosion by protecting the internal surfaces of the tank from contact with water and 

microbiological organisms.

3. Parameters Monitored/Inspected: The AMP monitors fuel oil quality and the levels of 

water and microbiological organisms in the fuel oil, which cause the loss of material of the 

tank internal surfaces. The ASTM Standard D 4057 is used for guidance on oil sampling. 

The ASTM Standards D 1796 and D 2709 are used for determination of water and 

sediment contamination in diesel fuel. For determination of particulates, modified ASTMD 

2276, Method A, is used. The modification consists of using a filter with a pore size of 

3.0 μm, instead of 0.8 μm. These are the principal parameters relevant to tank structural 

integrity.

4. Detection of Aging Effects: Degradation of the diesel fuel oil tank cannot occur without 

exposure of the tank internal surfaces to contaminants in the fuel oil, such as water and 

microbiological organisms. Compliance with diesel fuel oil standards in item 3, above, and 

periodic multilevel sampling provide assurance that fuel oil contaminants are below 

unacceptable levels. Internal surfaces of tanks that are drained for cleaning are visually 

inspected to detect potential degradation. However, corrosion may occur at locations in 
NUREG-1801, Rev. 1 XI M-100 September 2005

which contaminants may accumulate, such as a tank bottom, and an ultrasonic thickness 

measurement of the tank bottom surface ensures that significant degradation is not 

occurring. 

5. Monitoring and Trending: Water and biological activity or particulate contamination 

concentrations are monitored and trended in accordance with the plant’s technical 

specifications or at least quarterly. Based on industry operating experience, quarterly 

sampling and analysis of fuel oil provides for timely detection of conditions conducive to 

corrosion of the internal surface of the diesel fuel oil tank before the potential loss of its 

intended function.

6. Acceptance Criteria: The ASTM Standard D 4057 is used for guidance on oil sampling. 

The ASTM Standards D 1796 and D 2709 are used for guidance on the determination of 

water and sediment contamination in diesel fuel. ASTM D 6217 and Modified D 2276, 

Method A are used for guidance for determination of particulates. The modification to 

D 2276 consists of using a filter with a pore size of 3.0 μm, instead of 0.8 μm. 

7. Corrective Actions: Specific corrective actions are implemented in accordance with the 

plant quality assurance (QA) program. For example, corrective actions are taken to 

prevent recurrence when the specified limits for fuel oil standards are exceeded or when 

water is drained during periodic surveillance. Also, when the presence of biological activity 

is confirmed, a biocide is added to fuel oil. As discussed in the appendix to this report, the 

staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

corrective actions.

8. Confirmation Process: Site QA procedures, review and approval processes, and 

administrative controls are implemented in accordance with the requirements of 10 CFR 

Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation

process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: The operating experience at some plants has included 

identification of water in the fuel, particulate contamination, and biological fouling. 

However, no instances of fuel oil system component failures attributed to contamination 

have been identified.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

ASTM D 1796-,Standard Test Method for Water and Sediment in Fuel Oils by the Centrifuge 

Method, American Society for Testing Materials, West Conshohocken, PA., 1997.

ASTM D 2276-00,Standard Test Method for Particulate Contaminant in Aviation Fuel by Line 

Sampling, American Society for Testing Materials, West Conshohocken, PA., 2000.

ASTM D 2709-96,Standard Test Method for Water and Sediment in Middle Distillate Fuels by 

Centrifuge, American Society for Testing Materials, West Conshohocken, PA., 1996.
September 2005 XI M-101 NUREG-1801, Rev. 1

ASTM D 4057-95, Standard Practice for Manual Sampling of Petroleum and Petroleum 

Products, American Society for Testing Materials, West Conshohocken, PA., 2000.

NUREG-1430, Standard Technical Specifications Babcock and Wilcox Plants, Revision 3, June 

2004.

NUREG-1431, Standard Technical Specifications (STS) Westinghouse Plants, Revision 3, June 

2004.

NUREG-1432, Standard Technical Specifications Combustion Engineering Plants, Revision 3, 

June 2004.

NUREG-1433, Standard Technical Specifications General Electric Plants, BWR/4, Revision 3, 

June 2004.

NUREG-1433, Standard Technical Specifications General Electric Plants, BWR/6, Revision 3, 

June 2004.
NUREG-1801, Rev. 1 XI M-102 September 2005

XI.M31 REACTOR VESSEL SURVEILLANCE

Program Description

The Code of Federal Regulations, 10 CFR Part 50, Appendix H, requires that peak neutron 

fluence at the end of the design life of the vessel will not exceed 1017 n/cm2 (E >1MeV), or that 

reactor vessel beltline materials be monitored by a surveillance program to meet the American 

Society for Testing and Materials (ASTM) E 185 Standard. However, the surveillance program 

in ASTM E 185 is based on plant operation during the current license term, and additional 

surveillance capsules may be needed for the period of extended operation. Alternatively, an 

integrated surveillance program for the period of extended operation may be considered for a 

set of reactors that have similar design and operating features in accordance with 10 CFR 

Part 50, Appendix H, Paragraph II.C. Additional surveillance capsules may also be needed for 

the period of extended operation for this alternative.

The existing reactor vessel material surveillance program provides sufficient material data and 

dosimetry to monitor irradiation embrittlement at the end of the period of extended operation, 

and to determine the need for operating restrictions on the inlet temperature, neutron spectrum, 

and neutron flux. If surveillance capsules are not withdrawn during the period of extended 

operation, operating restrictions are to be established to ensure that the plant is operated under 

the conditions to which the surveillance capsules were exposed.

All capsules in the reactor vessel that are removed and tested must meet the test procedures 

and reporting requirements of ASTM E 185-82, to the extent practicable, for the configuration of 

the specimens in the capsule. Any changes to the capsule withdrawal schedule, including spare 

capsules, must be approved by the Nuclear Regulatory Commission (NRC) prior to 

implementation. Untested capsules placed in storage must be maintained for future insertion. 

An acceptable reactor vessel surveillance program consists of the following:

1. The extent of reactor vessel embrittlement for upper-shelf energy and pressuretemperature limits for 60 years is projected in accordance with the NRC Regulatory Guide 

(RG) 1.99, Rev. 2, “Radiation Embrittlement of Reactor Vessel Materials.” When using 

NRC RG 1.99, Rev. 2, an applicant has a choice of the following:

a. Neutron Embrittlement Using Chemistry Tables

An applicant may use the tables in NRC RG 1.99, Rev. 2, to project the extent of reactor 

vessel neutron embrittlement for the period of extended operation based on material 

chemistry and neutron fluence. This is described as Regulatory Position 1 in the RG.

b. Neutron Embrittlement Using Surveillance Data

When credible surveillance data is available, the extent of reactor vessel neutron 

embrittlement for the period of extended operation may be projected according to 

Regulatory Position 2 in NRC RG 1.99, Rev. 2, based on best fit of the surveillance data. 

The credible data could be collected during the current operating term. The applicant may 

have a plant-specific program or an integrated surveillance program during the period of 

extended operation to collect additional data.
September 2005 XI M-103 NUREG-1801, Rev. 1

2. An applicant that determines embrittlement by using the NRC RG 1.99, Rev. 2, tables 

(see item 1[a], above) uses the applicable limitations in Regulatory Position 1.3 of the RG. 

The limits are based on material properties, temperature, material chemistry, and fluence.

3. An applicant that determines embrittlement by using surveillance data (see item 1[b], 

above) defines the applicable bounds of the data, such as cold leg operating temperature 

and neutron fluence. These bounds are specific for the referenced surveillance data. For 

example, the plant-specific data could be collected within a smaller temperature range 

than that in the RG.

4. All pulled and tested capsules, unless discarded before August 31, 2000, are placed in 

storage. (Note: These specimens are saved for future reconstitution use, in case the 

surveillance program is reestablished.)

5. If an applicant has a surveillance program that consists of capsules with a projected 

fluence of less than the 60-year fluence at the end of 40 years, at least one capsule is to 

remain in the reactor vessel and is tested during the period of extended operation. The 

applicant may either delay withdrawal of the last capsule or withdraw a standby capsule 

during the period of extended operation to monitor the effects of long-term exposure to 

neutron irradiation.

6. If an applicant has a surveillance program that consists of capsules with a projected 

fluence exceeding the 60-year fluence at the end of 40 years, the applicant withdraws one 

capsule at an outage in which the capsule receives a neutron fluence equivalent to the 60-

year fluence and tests the capsule in accordance with the requirements of ASTM E 185. 

Any capsules that are left in the reactor vessel provide meaningful metallurgical data (i.e., 

the capsule fluence does not significantly exceed the vessel fluence at an equivalent of 

60 years). For example, in a reactor with a lead factor of three, after 20 years the capsule 

test specimens would have received a neutron exposure equivalent to what the reactor 

vessel would see in 60 years; thus, the capsule is to be removed because further 

exposure would not provide meaningful metallurgical data. Other standby capsules are 

removed and placed in storage. These standby capsules (and archived test specimens 

available for reconstitution) would be available for reinsertion into the reactor if additional 

license renewals are sought (e.g., 80 years of operation). If all surveillance capsules have 

been removed, operating restrictions are to be established to ensure that the plant is 

operated under conditions to which the surveillance capsules were exposed. The 

exposure conditions of the reactor vessel are monitored to ensure that they continue to be 

consistent with those used to project the effects of embrittlement to the end of license. If 

the reactor vessel exposure conditions (neutron flux, spectrum, irradiation temperature, 

etc.) are altered, then the basis for the projection to 60 years is reviewed; and, if deemed 

appropriate, an active surveillance program is re-instituted. Any changes to the reactor 

vessel exposure conditions and the potential need to re-institute a vessel surveillance 

program is discussed with the NRC staff prior to changing the plant's licensing basis.

7. Applicants without in-vessel capsules use alternative dosimetry to monitor neutron fluence 

during the period of extended operation, as part of the aging management program (AMP) 

for reactor vessel neutron embrittlement.

8. The applicant may choose to demonstrate that the materials in the inlet, outlet, and safety 

injection nozzles are not controlling, so that such materials need not be added to the 

material surveillance program for the license renewal term. 
NUREG-1801, Rev. 1 XI M-104 September 2005

The reactor vessel monitoring program provides that, if future plant operations exceed the 

limitations or bounds specified in item 2 or 3, above (as applicable), such as operating at a 

lower cold leg temperature or higher fluence, the impact of plant operation changes on the 

extent of reactor vessel embrittlement will be evaluated and the NRC will be notified. An 

applicant without capsules in its reactor vessel is to propose reestablishing the reactor 

vessel surveillance program to assess the extent of embrittlement. This program will consist 

of (1) capsules from item 6, above; (2) reconstitution of specimens from item 4, above; 

and/or (3) capsules made from any available archival materials; or (4) some combination of 

the three previous options. This program could be a plant-specific program or an integrated 

surveillance program.

Evaluation and Technical Basis

Reactor vessel surveillance program is 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 submits its proposed 

withdrawal schedule for approval prior to implementation. Thus, further staff evaluation is 

required for license renewal.

References

10 CFR Part 50, Appendix H, Reactor Vessel Material Surveillance Program Requirements, 

Office of the Federal Register, National Archives and Records Administration, 2005.

ASTM E-185, Standard Recommended Practice for Surveillance Tests for Nuclear Reactor 

Vessels, American Society for Testing Materials, Philadelphia, PA. (Versions of ASTM E185 to be used for the various aspects of the reactor vessel surveillance program are as 

specified in 10 CFR Part 50, Appendix.)

NRC Regulatory Guide 1.99, Rev. 2, Radiation Embrittlement of Reactor Vessel Materials, 

U.S. Nuclear Regulatory Commission, May 1988.
September 2005 XI M-105 NUREG-1801, Rev. 1

XI.M32 ONE-TIME INSPECTION 

Program Description

The program includes measures to verify the effectiveness of an aging management program 

(AMP) and confirm the insignificance of an aging effect. Situations in which additional 

confirmation is appropriate include (a) an aging effect is not expected to occur but the data is 

insufficient to rule it out with reasonable confidence; (b) an aging effect is expected to progress 

very slowly in the specified environment, but the local environment may be more adverse than 

that generally expected; or (c) the characteristics of the aging effect include a long incubation 

period. For these cases, there is to be confirmation that either the aging effect is indeed not 

occurring, or the aging effect is occurring very slowly so as not to affect the component or 

structure intended function during the period of extended operation.

A one-time inspection may also be used to provide additional assurance that aging that has not 

yet manifested itself is not occurring, or that the evidence of aging shows that the aging is so 

insignificant that an aging management program is not warranted. (Class 1 piping less than or 

equal to NPS 4 is addressed in Chapter XI.M35, One Time Inspection of ASME Code Class 1 

Small Bore-Piping)

One-time inspections may also be used to verify the system-wide effectiveness of an AMP that 

is designed to prevent or minimize aging to the extent that it will not cause the loss of intended 

function during the period of extended operation. For example, effective control of water 

chemistry can prevent some aging effects and minimize others. However, there may be 

locations that are isolated from the flow stream for extended periods and are susceptible to the 

gradual accumulation or concentration of agents that promote certain aging effects. This 

program provides inspections that either verifies that unacceptable degradation is not occurring 

or trigger additional actions that will assure the intended function of affected components will be 

maintained during the period of extended operation. 

The elements of the program include (a) determination of the sample size based on an 

assessment of materials of fabrication, environment, plausible aging effects, and operating 

experience; (b) identification of the inspection locations in the system or component based on 

the aging effect; (c) determination of the examination technique, including acceptance criteria 

that would be effective in managing the aging effect for which the component is examined; and 

(d) evaluation of the need for follow-up examinations to monitor the progression of aging if agerelated degradation is found that could jeopardize an intended function before the end of the 

period of extended operation. 

When evidence of an aging effect is revealed by a one-time inspection, the routine evaluation of 

the inspection results would identify appropriate corrective actions. 

As set forth below, an acceptable verification program may consist of a one-time inspection of 

selected components and susceptible locations in the system. An alternative acceptable 

program may include routine maintenance or a review of repair or inspection records to confirm 

that these components have been inspected for aging degradation and significant aging 

degradation has not occurred. One-time inspection, or any other action or program, created to 

verify the effectiveness of an AMP and confirm the absence of an aging effect, is to be reviewed 

by the staff on a plant-specific basis.
NUREG-1801, Rev. 1 XI M-106 September 2005

Evaluation and Technical Basis

1. Scope of Program: The program includes measures to verify that unacceptable 

degradation is not occurring, thereby validating the effectiveness of existing AMPs or 

confirming that there is no need to manage aging-related degradation for the period of 

extended operation. The structures and components for which one-time inspection is 

specified to verify the effectiveness of the AMPs (e.g., water chemistry control, etc.) have 

been identified in the Generic Aging Lessons Learned (GALL) Report. Examples include 

the feedwater system components in boiling water reactors (BWRs) and pressurized 

water reactors (PWRs).

2. Preventive Actions: One-time inspection is an inspection activity independent of 

methods to mitigate or prevent degradation.

3. Parameters Monitored/Inspected: The program monitors parameters directly related to 

the degradation of a component. Inspection is to be performed by qualified personnel 

following procedures consistent with the requirements of the American Society of 

Mechanical Engineers (ASME) Code and 10 CFR 50, Appendix B, using a variety of 

nondestructive examination (NDE) methods, including visual, volumetric, and surface 

techniques. 

4. Detection of Aging Effects: The inspection includes a representative sample of the 

system population, and, where practical, focuses on the bounding or lead components 

most susceptible to aging due to time in service, severity of operating conditions, and 

lowest design margin. 

The program will rely on established NDE techniques, including visual, ultrasonic, and 

surface techniques that are performed by qualified personnel following procedures 

consistent with the ASME Code and 10 CFR Part 50, Appendix B. 

The inspection and test techniques will have a demonstrated history of effectiveness in 

detecting the aging effect of concern. Typically, the one time inspections should be 

performed as indicated in the following table. 
September 2005 XI M-107 NUREG-1801, Rev. 1

Examples of Parameters Monitored or Inspected

And Aging Effect for Specific Structure or Component9

Aging

Effect

Aging

Mechanism

Parameter

Monitored

Inspection

Method10

Loss of 

Material

Crevice 

Corrosion

Wall Thickness Visual (VT-1 or equivalent) and/or 

Volumetric (RT or UT)

Loss of 

Material

Galvanic 

Corrosion

Wall Thickness Visual (VT-3 or equivalent) and/or 

Volumetric (RT or UT)

Loss of 

Material

General 

Corrosion

Wall Thickness Visual (VT-3 or equivalent) and/or 

Volumetric (RT or UT)

Loss of 

Material

MIC Wall Thickness Visual (VT-3 or equivalent) and/or 

Volumetric (RT or UT)

Loss of 

Material

Pitting 

Corrosion

Wall Thickness Visual (VT-1 or equivalent) and/or 

Volumetric (RT or UT)

Loss of 

Material

Erosion Wall Thickness Visual (VT-3 or equivalent) and/or 

Volumetric (RT or UT)

Loss of 

Heat 

Transfer

Fouling Tube Fouling Visual (VT-3 or equivalent) or 

Enhanced VT-1 for CASS

Cracking SCC or Cyclic 

Loading

Cracks Enhanced Visual (VT-1 or equivalent) 

and/or Volumetric (RT or UT)

Loss of 

Preload

Thermal 

Effects, 

Gasket Creep 

and Selfloosening

Loosening of 

Components

Visual (VT-3 or equivalent)

With respect to inspection timing, the population of components inspected before the end 

of the current operating term needs to be sufficient to provide reasonable assurance that 

the aging effect will not compromise any intended function at any time during the period of

extended operation. Specifically, inspections need to be completed early enough to ensure 

that the aging effects that may affect intended functions early in the period of extended 

operation are appropriately managed. Conversely, inspections need to be timed to allow 

the inspected components to attain sufficient age to ensure that the aging effects with long 

incubation periods (i.e., those that may affect intended functions near the end of the period 

of extended operation) are identified. Within these constraints, the applicant should 

schedule the inspection no earlier than 10 years prior to the period of extended operation, 

and in such a way as to minimize the impact on plant operations. As a plant will have 

accumulated at least 30 years of use before inspections under this program begin, 

sufficient times will have elapsed for aging effects, if any, to be manifest.

 

9

 The examples provided in the table may not be appropriate for all relevant situations. If the applicant 

chooses to use an alternative to the recommendations in this table, a technical justification should be 

provided as an exception to this AMP. This exception should list the AMR line item component, 

examination technique, acceptance criteria, evaluation standard and a description of the justification.

10 Visual inspection may be used only when the inspection methodology examines the surface potentially 

experiencing the aging effect. 
NUREG-1801, Rev. 1 XI M-108 September 2005

5. Monitoring and Trending: The program provides for increasing of the inspection sample 

size and locations in the event that aging effects are detected. Determination of the 

sample size is based on an assessment of materials of fabrication, environment, plausible 

aging effects, and operating experience. Unacceptable inspection findings are evaluated in 

accordance with the site corrective action process to determine the need for subsequent 

(including periodic) inspections and for monitoring and trending the results.

6. Acceptance Criteria: Any indication or relevant conditions of degradation detected are 

evaluated. For example, the ultrasonic thickness measurements are to be compared to 

predetermined limits, such as the design minimum wall thickness for piping. 

7. Corrective Actions: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

corrective actions, confirmation process, and administrative controls. 

8. Confirmation Process: See Item 7, above.

9. Administrative Controls: See Item 7, above.

10. Operating Experience: This program applies to potential aging effects for which there 

are currently no operating experience indicating the need for an aging management 

program. Nevertheless, the elements that comprise these inspections (e.g., the scope of 

the inspections and inspection techniques) are consistent with industry practice. 

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2005.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 2001 edition including the 2002 and 2003 Addenda, 

American Society of Mechanical Engineers, New York, NY.
September 2005 XI M-109 NUREG-1801, Rev. 1

XI.M33 SELECTIVE LEACHING OF MATERIALS

Program Description

The program for selective leaching of materials ensures the integrity of the components made of 

cast iron, bronze, brass, and other alloys exposed to a raw water, brackish water, treated water, 

or groundwater environment that may lead to selective leaching of one of the metal 

components. The aging management program (AMP) includes 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 for the period 

of extended operation. 

Evaluation and Technical Basis

1. Scope of Program: This AMP determines the acceptability of the components that may 

be susceptible to selective leaching and assesses their ability to perform the intended 

function during the period of extended operation. These components include piping, valve 

bodies and bonnets, pump casings, and heat exchanger components. The materials of 

construction for these components may include cast iron, brass, bronze, or aluminumbronze. These components may be exposed to a raw water, treated water, or 

groundwater environment. The AMP includes a one-time visual inspection and hardness 

measurement of a selected set of sample components to determine whether loss of 

material due to selective leaching is not occurring for the period of extended operation.

The selective leaching process involves the preferential removal of one of the alloying 

elements from the material, which leads to the enrichment of the remaining alloying 

elements. Dezincification (loss of zinc from brass) and graphitization (removal of iron from 

cast iron) are examples of such a process. Susceptible materials, high temperatures, 

stagnant-flow conditions, and corrosive environment such as acidic solutions, for example, 

for brasses with high zinc content, and dissolved oxygen, are conducive to selective 

leaching. 

2. Preventive Actions: The one-time visual inspection and hardness measurement is an 

inspection/verification program; thus, there is no preventive action. However, it is noted 

that monitoring of water chemistry to control pH and concentration of corrosive 

contaminants, and treatment with hydrazine to minimize dissolved oxygen in water are 

effective in reducing selective leaching. 

3. Parameters Monitored/Inspected: The visual inspection and hardness measurement is 

to be a one-time inspection. Because selective leaching is a slow acting corrosion 

process, this measurement is performed just before the beginning of the license renewal 

period. Follow-up of unacceptable inspection findings includes expansion of the inspection 

sample size and location.

4. Detection of Aging Effects: The one-time visual inspection and hardness measurement 

includes close examination of a select set of components to determine whether selective 

leaching has occurred and whether the resulting loss of strength and/or material will affect 

the intended functions of these components during the period of extended operation. 

Selective leaching generally does not cause changes in dimensions and is difficult to 

detect. However, in certain brasses it causes plug-type dezincification, which can be 
NUREG-1801, Rev. 1 XI M-110 September 2005

detected by visual inspection. One acceptable procedure is to visually inspect the 

susceptible components closely and conduct Brinell Hardness testing on the inside 

surfaces of the selected set of components to determine if selective leaching has 

occurred. If it is occurring, an engineering evaluation is initiated to determine acceptability 

of the affected components for further service. 

5. Monitoring and Trending: There is no monitoring and trending for the one-time visual 

inspection and hardness measurement. 

6. Acceptance Criteria: Identification of selective leaching will define the need for further 

engineering evaluation before the affected components can be qualified for further 

service. If necessary, the evaluation will include a root cause analysis. 

7. Corrective Actions: Evaluations are performed for test or inspection results that do not 

satisfy established acceptance criteria. The corrective actions program ensures that 

conditions adverse to quality are promptly corrected. If the deficiency is assessed to be 

significantly adverse to quality, the cause of the condition is determined and an action 

plan is developed to preclude repetition. As discussed in the appendix to this report, the 

staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

corrective actions.

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report,

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: See Item 8, above.

10. Operating Experience: One-time inspection is a new program to be applied by the 

applicant. The elements that comprise these inspections (e.g., the scope of the 

inspections and inspection techniques) are consistent with industry practice and staff 

expectations. 

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

NRC Safety Evaluation Report Related to the License Renewal of Calvert Cliffs Nuclear Power 

Plant, Units 1 and 2, NUREG-1705, December 1999.

NRC Safety Evaluation Report Related to the License Renewal of Oconee Nuclear Station, 

Units 1, 2, and 3, NUREG-1723, March 2000.
September 2005 XI M-111 NUREG-1801, Rev. 1

XI.M34 BURIED PIPING AND TANKS INSPECTION

Program Description

The program includes (a) preventive measures to mitigate corrosion, and (b) periodic inspection 

to manage the effects of corrosion on the pressure-retaining capacity of buried steel piping and 

tanks. Gray cast iron, which is included under the definition of steel, is also subject to a loss of 

material due to selective leaching, which is an aging effect managed under Chapter XI.M33, 

“Selective Leaching of Materials.”

Preventive measures are in accordance with standard industry practice for maintaining external 

coatings and wrappings. Buried piping and tanks are inspected when they are excavated during 

maintenance and when a pipe is dug up and inspected for any reason. 

This program is an acceptable option to manage buried piping and tanks, except further 

evaluation is required for the program element/attributes of detection of aging effects (regarding 

inspection frequency) and operating experience. 

Evaluation and Technical Basis

1. Scope of Program: The program relies on preventive measures such as coating, 

wrapping and periodic inspection for loss of material caused by corrosion of the external 

surface of buried steel piping and tanks. Loss of material in these components, which may 

be exposed to aggressive soil environment, is caused by general, pitting, and crevice 

corrosion, and microbiologically-influenced corrosion (MIC). Periodic inspections are 

performed when the components are excavated for maintenance or for any other reason. 

The scope of the program covers buried components that are within the scope of license 

renewal for the plant.

2. Preventive Actions: In accordance with industry practice, underground piping and tanks 

are coated during installation with a protective coating system, such as coal tar enamel 

with a fiberglass wrap and a kraft paper outer wrap, a polyolifin tape coating, or a fusion 

bonded epoxy coating to protect the piping from contacting the aggressive soil 

environment. 

3. Parameters Monitored/Inspected: The program monitors parameters such as coating 

and wrapping integrity that are directly related to corrosion damage of the external surface 

of buried steel piping and tanks. Coatings and wrappings are inspected by visual 

techniques. Any evidence of damaged wrapping or coating defects, such as coating 

perforation, holidays, or other damage, is an indicator of possible corrosion damage to the 

external surface of piping and tanks. 

4. Detection of Aging Effects: Inspections performed to confirm that coating and wrapping 

are intact are an effective method to ensure that corrosion of external surfaces has not 

occurred and the intended function is maintained. Buried piping and tanks are 

opportunistically inspected whenever they are excavated during maintenance. When 

opportunistic, the inspections are performed in areas with the highest likelihood of 

corrosion problems, and in areas with a history of corrosion problems, within the areas 

made accessible to support the maintenance activity. 
NUREG-1801, Rev. 1 XI M-112 September 2005

The applicant’s program is to be evaluated for the extended period of operation. It is 

anticipated that one or more opportunistic inspections may occur within a ten-year period. 

Prior to entering the period of extended operation, the applicant is to verify that there is at 

least one opportunistic or focused inspection is performed within the past ten years. Upon 

entering the period of extended operation, the applicant is to perform a focused inspection 

within ten years, unless an opportunistic inspection occurred within this ten-year period. 

Any credited inspection should be performed in areas with the highest likelihood of 

corrosion problems, and in areas with a history of corrosion problems.

5. Monitoring and Trending: Results of previous inspections are used to identify 

susceptible locations.

6. Acceptance Criteria: Any coating and wrapping degradations are reported and evaluated 

according to site corrective actions procedures. 

7. Corrective Actions: The site corrective actions program, quality assurance (QA) 

procedures, site review and approval process, and administrative controls are 

implemented in accordance with the requirements of 10 CFR Part 50, Appendix B. The 

staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

corrective actions, confirmation process, and administrative controls.

8. Confirmation Process: See Item 7, above.

9. Administrative Controls: See Item 7, above.

10. Operating Experience: Operating experience shows that the program described here is 

effective in managing corrosion of external surfaces of buried steel piping and tanks. 

However, because the inspection frequency is plant-specific and depends on the plant 

operating experience, the applicant’s plant-specific operating experience is further 

evaluated for the extended period of operation.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.
September 2005 XI M-113 NUREG-1801, Rev. 1

XI.M35 ONE-TIME INSPECTION OF ASME CODE CLASS 1 SMALL-BORE PIPING

Program Description

This program is applicable to small-bore ASME Code Class 1 piping and systems less than -or 

equal to 4 inches nominal pipe size (NPS 4), which includes pipes, fittings, and branch 

connections. According to Table IWB-2500-1, Examination Category B-J Item No. B9.21 of the 

current ASME code, for small-bore Class 1 piping, a surface examination should be included for 

piping less than or equal to NPS 4 and greater than or equal to NPS 1. Also, Examination 

Category B-P requires system leakage and hydrostatic tests. However, the staff believes that, 

for a one-time inspection to detect cracking resulting from thermal and mechanical loading or 

intergranular stress corrosion, the inspection should be a volumetric examination. This is to 

provide additional assurance that either aging of small-bore ASME Code Class 1 piping is not 

occurring or the aging is insignificant, such that an aging management program (AMP) is not 

warranted. This program is applicable only to plants that have not experienced cracking of 

ASME Code Class 1 small-bore piping resulting from stress corrosion or thermal and 

mechanical loading. Should evidence of significant aging be revealed by a one-time inspection 

or previous operating experience, periodic inspection will be proposed, as managed by a plantspecific AMP. 

Evaluation and Technical Basis

1. Scope of Program: This program is a one-time inspection of a sample of ASME Code 

Class 1 piping less than or equal to NPS 4. The program includes measures to verify that 

degradation is not occurring; thereby either confirming that there is no need to manage 

aging-related degradation or validate the effectiveness of any existing AMP for the period 

of extended operation. The one-time inspection program for ASME Code Class 1 smallbore piping includes locations that are susceptible to cracking. Guidelines for identifying 

piping susceptible to potential effects of thermal stratification or turbulent penetration are 

provided in EPRI Report 1000701, "Interim Thermal Fatigue Management Guideline 

(MRP-24)," January 2001.

2. Preventive Actions: This program is an inspection activity independent of methods to 

mitigate or prevent degradation.

3. Parameters Monitored/Inspected: This inspection detects cracking in ASME Code 

Class 1 small-bore piping.

4. Detection of Aging Effects: The inspection is designed to provide assurance, in plants 

that have not experienced cracking of ASME Code Class 1 small-bore piping due to stress 

corrosion or thermal and mechanical loading, that aging of this piping is not occurring or 

that the effects of aging are not significant. For ASME Code Class 1small-bore piping, 

one-time inspections using volumetric examination are performed on selected weld 

locations to detect cracking.

5. Monitoring and Trending: This is a one-time inspection to determine whether cracking 

in ASME Code Class 1 small-bore piping resulting from stress corrosion or thermal and 

mechanical loading is an issue. A one-time volumetric inspection is an acceptable method 

for confirming that cracking of ASME Code Class 1 small-bore piping, as a result of stress 

corrosion or thermal and mechanical loading, is not occurring in plants that have not 

experienced cracking due to these aging effects. However, evaluation of the inspection 
NUREG-1801, Rev. 1 XI M-114 September 2005

results may indicate the need for additional examinations, i.e., a plant-specific AMP, 

consistent with ASME Section XI, Subsection IWB. This inspection should be performed 

at a sufficient number of locations to assure an adequate sample. This number, or sample 

size, will be based on susceptibility, inspectability, dose considerations, operating 

experience, and limiting locations of the total population of ASME Code Class 1 smallbore piping locations. 

6. Acceptance Criteria: If flaws or indications exceed the acceptance criteria of ASME 

Code, Section XI, Paragraph IWB-3400, they will be evaluated in accordance with ASME 

Code, Section XI, Paragraph IWB-3131, and additional examinations are performed in 

accordance with ASME Code, Section XI, Paragraph IWB-2430.

7. Corrective Actions: The site corrective action program, quality assurance (QA) 

procedures, site review and approval process, and administrative controls are 

implemented in accordance with the requirements of 10 CFR Part 50, Appendix B. As 

discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 

50, Appendix B, acceptable to address the corrective actions, confirmation process, and 

administrative controls.

8. Confirmation Process: See Item 7, above.

9. Administrative Controls: See Item 7 above.

10. Operating Experience: This inspection uses volumetric inspection techniques with 

demonstrated capability and a proven industry record to detect cracking in piping weld 

and base material. However, the application of the specific technique to ASME Code 

Class 1 small-bore piping needs to be qualified before the examination.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2005.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 2001 edition including the 2002 and 2003 Addenda, 

American Society of Mechanical Engineers, New York, NY.

NRC Information Notice 97-46, Unisolable Crack in High-Pressure Injection Piping, U.S. Nuclear 

Regulatory Commission, July 9, 1997.

EPRI Report 1000701, “Interim Thermal Fatigue Management Guideline (MRP-24),” January 

2001 (ADAMS Accession No. ML010810162).
September 2005 XI M-115 NUREG-1801, Rev. 1

XI.M36 EXTERNAL SURFACES MONITORING

Program Description

The External Surfaces Monitoring program is based on system inspections and walkdowns. This 

program consists of periodic visual inspections of steel components such as piping, piping 

components, ducting, and other components within the scope of license renewal and subject to 

AMR in order to manage aging effects. The program manages aging effects through visual 

inspection of external surfaces for evidence of material loss. Loss of material due to boric acid 

corrosion is managed by the Boric Acid Corrosion Program. 

Evaluation and Technical Basis

1. Scope of Program: This program visually inspects the external surface of in-scope 

components and monitors external surfaces of steel components in systems within the 

scope of license renewal and subject to AMR for loss of material and leakage. Visual 

inspections are expected to identify loss of material due to general corrosion in accessible 

steel components. Loss of material due to pitting and crevice corrosion may not be 

detectable through these same visual inspections, however, general corrosion is expected 

to be present and detectable such that, should pitting and crevice corrosion exist, general 

corrosion will manifest itself as visible rust or rust byproducts (e.g., discoloration or coating 

degradation) and be detectable prior to any loss of intended function. Therefore, this 

program is acceptable for use in inspecting for loss of material for general, pitting and 

crevice corrosion.

Surfaces that are inaccessible or not readily visible during plant operations are inspected 

during refueling outages. Surfaces that are inaccessible or not readily visible during both 

plant operations and refueling outages are inspected at such intervals that would provide 

reasonable assurance that the effects of aging will be managed such that applicable 

components will perform their intended function during the period of extended operation. 

Surfaces that are insulated may be inspected when the external surface is exposed (i.e., 

maintenance) at such intervals that would provide reasonable assurance that the effects 

of aging will be managed such that applicable components will perform their intended 

function during the period of extended operation.

The program may also be credited with managing loss of material from internal surfaces, 

for situations in which material and environment combinations are the same for internal 

and external surfaces such that external surface condition is representative of internal 

surface condition. When credited, the program should describe the component internal 

environment and the credited similar external component environment inspected.

2. Preventive Actions: The External Surfaces Monitoring Program is a visual monitoring 

program that does not include preventive actions.
NUREG-1801, Rev. 1 XI M-116 September 2005

3. Parameters Monitored/Inspected: The External Surfaces Monitoring Program utilizes 

periodic plant system inspections and walkdowns to monitor for material degradation and 

leakage. This program inspects components such as piping, piping components, ducting 

and other components. Coatings deterioration is an indicator of possible underlying 

degradation. 

Examples of inspection parameters include:

• corrosion and material wastage (loss of material); 

• leakage from or onto external surfaces;

• worn, flaking, or oxide-coated surfaces;

• corrosion stains on thermal insulation;

• protective coating degradation (cracking and flaking)

4. Detection of Aging Effects: Degradation of steel surfaces cannot occur without the 

degradation of the paint or coating. Confirmation of the integrity of the paint or coating is 

an effective method for managing the effects of corrosion on the steel surface. A visual 

inspection is conducted for component surfaces at least once per refueling cycle. This 

frequency accommodates inspections of components that may be in locations that are 

normally only accessible during outages. System walkdowns are normally performed on a 

frequency that exceeds once per fuel cycle. Surfaces that are inaccessible or not readily 

visible during plant operations and refueling outages are inspected at such intervals that 

would ensure the components intended function is maintained. The intervals of

inspections may be adjusted as necessary based on plant-specific inspection results and 

industry experience. 

This program is credited with managing the following aging effects.

• loss of material for external surfaces;

• loss of material for internal surfaces exposed to the same environment as the external

surface 

5. Monitoring and Trending: Visual inspection activities are performed and associated 

personnel are qualified in accordance with site controlled procedures and processes. The 

External Surfaces Monitoring Program uses standardized monitoring and trending 

activities to track degradation. Deficiencies are documented using approved processes 

and procedures such that results can be trended. However, the program does not include 

formal trending. Inspections are performed at frequencies identified in Detection of Aging 

Effects.

6. Acceptance Criteria: For each component/aging effect combination, the acceptance 

criteria are defined to ensure that the need for corrective actions will be identified before 

loss of intended functions. Acceptance criteria include design standards, procedural 

requirements, current licensing basis, industry codes or standards, and engineering 

evaluation.

7. Corrective Actions: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

corrective actions, confirmation process, and administrative controls.
September 2005 XI M-117 NUREG-1801, Rev. 1

8. Confirmation Process: See Item 7, above.

9. Administrative Controls: See Item 7, above.

10. Operating Experience: External surfaces inspections via system inspections and 

walkdowns have been in effect at many utilities since the mid 1990's in support of the 

Maintenance Rule (10 CFR 50.65) and have proven effective in maintaining the material 

condition of plant systems. The elements that comprise these inspections (e.g., the scope 

of the inspections and inspection techniques) are consistent with industry practice.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

INPO Good Practice TS-413, Use of System Engineers, INPO 85-033, May 18, 1988.

EPRI Technical Report 1007933 "Aging Assessment Field Guide," December 2003

EPRI Technical Report 1009743 "Aging Identification and Assessment Checklist," August 27, 

2004.
NUREG-1801, Rev. 1 XI M-118 September 2005

XI.M37 FLUX THIMBLE TUBE INSPECTION 

Program Description

The Flux Thimble Tube Inspection is an inspection program used to monitor for thinning of the 

flux thimble tube wall, which provides a path for the incore neutron flux monitoring system 

detectors and forms part of the RCS pressure boundary. Flux thimble tubes are subject to loss 

of material at certain locations in the reactor vessel where flow-induced fretting causes wear at 

discontinuities in the path from the reactor vessel instrument nozzle to the fuel assembly 

instrument guide tube. An NDE methodology, such as eddy current testing (ECT), or other 

applicant-justified and NRC-accepted inspection method is used to monitor for wear of the flux 

thimble tubes. This program implements the recommendations of NRC Bulletin 88-09, “Thimble 

Tube Thinning in Westinghouse Reactors,” as described below.

Evaluation and Technical Basis

1. Scope of Program: The flux thimble tube Inspection encompasses all of the flux thimble 

tubes that form part of the reactor coolant system pressure boundary. The flux thimble 

guide tubes are not in the scope of this program. Within scope are the licensee responses 

to Bulletin 88-09, as accepted by the staff in its closure letters on the Bulletin, and any 

amendments to the licensee responses as approved by the staff.

2. Preventive Actions: The program consists of inspection and evaluation and provides no 

guidance on preventive actions.

3. Parameters Monitored/Inspected: Flux thimble tube wall thickness will be monitored to 

detect loss of material from the flux thimble tubes during the period of extended operation.

4. Detection of Aging Effects: An inspection methodology (such as ECT) that has been 

demonstrated to be capable of adequately detecting wear of the flux thimble tubes will be 

employed to detect loss of material during the period of extended operation. Justification 

for methods other than ECT should be provided unless use of the alternative method has 

been previously accepted by the Nuclear Regulatory Commission (NRC). The inspection 

results will be evaluated and compared with the acceptance criteria established as 

discussed in element 6 below.

5. Monitoring and Trending: The wall thickness measurements will be trended and wear 

rates will be calculated. Examination frequency will be based upon wear predictions that

have been technically justified as providing conservative estimates of flux thimble tube 

wear. The interval between inspections will be established such that no flux thimble tube 

is predicted to incur wear that exceeds the established acceptance criteria before the next 

inspection. The examination frequency may be adjusted based on plant-specific wear 

projections. Re-baselining of the examination frequency should be justified using plantspecific wear-rate data unless prior plant-specific NRC acceptance for the re-baselining 

was received. If design changes are made to use more wear-resistant thimble tube 

materials (e.g., chrome-plated stainless steel) sufficient inspections will be conducted at 

an adequate inspection frequency, as described above, for the new materials. 

6. Acceptance Criteria: Appropriate acceptance criteria such as percent through-wall wear 

will be established. The acceptance criteria will be technically justified to provide an 

adequate margin of safety to ensure that the integrity of the reactor coolant system 
September 2005 XI M-119 NUREG-1801, Rev. 1

pressure boundary is maintained. The acceptance criteria will include allowances for 

factors such as instrument uncertainty, uncertainties in wear scar geometry, and other 

potential inaccuracies, as applicable, to the inspection methodology chosen for use in the 

program. Acceptance criteria different from those previously documented in NRC 

acceptance letters for the applicant’s response to Bulletin 88-09 and amendments thereto 

should be justified.

7. Corrective Actions: Flux thimble tube wall thickness which do not meet the established 

acceptance criteria must be isolated, capped, plugged, withdrawn, replaced, or otherwise 

removed from service in a manner that ensures the integrity of the reactor coolant system 

pressure boundary is maintained. Analyses may allow repositioning of flux thimble tubes 

that are approaching the acceptance criteria limit. Repositioning of a tube exposes a 

different portion of the tube to the discontinuity that is causing the wear.

Flux thimble tubes that cannot be inspected over the tube length, that is subject to wear 

due to restriction or other defect, and that can not be shown by analysis to be satisfactory 

for continued service, must be removed from service to ensure the integrity of the reactor 

coolant system pressure boundary.

The site corrective actions program, quality assurance (QA) procedures, site review and 

approval process, and administrative controls are implemented in accordance with 

10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds 

the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective 

actions, confirmation process, and administrative controls.

8. Confirmation Process: See Item 7, above.

9. Administrative Controls: See Item 7, above.

10. Operating Experience: In IE Bulletin 88-09, “Thimble Tube Thinning in Westinghouse 

Reactors,” the NRC requested that licensees implement a flux thimble tube inspection 

program due to several instances of leaks, and due to licensees identifying wear. Utilities 

established inspection programs in accordance with IE Bulletin 88-09 which have shown 

excellent results in identifying and managing wear of flux thimble tubes.

As discussed in IE Bulletin 88-09, the amount of vibration the thimble tubes experience is 

determined by many plant-specific factors. Therefore, the only effective method for 

determining thimble tube integrity is through inspections which are adjusted to account for 

plant-specific wear patterns and history.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

NRC Bulletin 88-09, “Thimble Tube Thinning in Westinghouse Reactors,” July 26, 1988.

NRC Information Notice No. 87-44, Supplement 1, "Thimble Tube Thinning in Westinghouse 

Reactors," March 28, 1988.
NUREG-1801, Rev. 1 XI M-120 September 2005

NRC Information Notice No. 87-44, "Thimble Tube Thinning in Westinghouse Reactors," 

September 16, 1987.
September 2005 XI M-121 NUREG-1801, Rev. 1

XI.M38 INSPECTION OF INTERNAL SURFACES IN MISCELLANEOUS PIPING AND 

DUCTING COMPONENTS

Program Description

The program consists of inspections of the internal surfaces of steel piping, piping components, 

ducting, and other components that are not covered by other aging management programs. 

These internal inspections are performed during the periodic system and component 

surveillances or during the performance of maintenance activities when the surfaces are made 

accessible for visual inspection. The program includes visual inspections to assure that existing 

environmental conditions are not causing material degradation that could result in a loss of 

component intended functions. If visual inspection of internal surfaces is not possible, then the 

applicant needs to provide a plant-specific program.

Evaluation and Technical Basis

1. Scope of Program: The program visual inspections include internal surfaces of steel 

piping, piping elements, ducting, and components in an internal environment (such as 

indoor uncontrolled air, condensation, and steam) that are not included in other aging 

management programs for loss of material. Inspections are performed when the internal 

surfaces are accessible during the performance of periodic surveillances, during 

maintenance activities or during scheduled outages. This program includes indication of 

borated water leakage on internal surfaces.

2. Preventive Actions: This program is an inspection activity independent of methods to 

mitigate or prevent degradation.

3. Parameters Monitored/Inspected: Visual inspections of internal surfaces of plant 

components are performed during maintenance or surveillance activities. Parameters 

monitored or inspected include visible evidence of corrosion to indicate possible loss of 

materials. 

4. Detection of Aging Effects: Periodic inspections provide for detection of aging effects 

prior to the loss of component function. For painted or coated surfaces, degradation of 

steel surfaces cannot occur without the degradation of the paint or coating. Confirmation 

of the integrity of the paint or coating is an effective method for managing the effects of 

corrosion on the steel surface. The applicant should identify and justify the inspection 

technique used for detecting the aging effects of concern. Locations should be chosen to 

include conditions likely to exhibit these aging effects. Inspection intervals are established 

such that they provide timely detection of degradation.

5. Monitoring and Trending: Visual inspection activities are performed and associated 

personnel are qualified in accordance with site controlled procedures and processes. 

Maintenance and surveillance activities provide for monitoring and trending of aging 

degradation. Inspection intervals are dependent on component material and environment, 

and take into consideration industry and plant-specific operating experience. Results of 

the periodic inspections are monitored for indications of various corrosion mechanisms 

and fouling. The extent and schedule of inspections and testing assure detection of 

component degradation prior to loss of intended functions. 
NUREG-1801, Rev. 1 XI M-122 September 2005

6. Acceptance Criteria: Indications of various corrosion mechanisms or fouling that would 

impact component intended function are reported and will require further evaluation. The 

acceptance criteria are established in the maintenance and surveillance procedures or 

other established plant procedures. If the results are not acceptable, the corrective action 

program is implemented to assess the material condition and determine whether the 

component intended function is affected.

7. Corrective Actions: Site corrective actions program, quality assurance (QA) procedures, 

site review and approval process, and administrative controls are implemented in 

accordance with the requirements of 10 CFR Part 50, Appendix B. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address the corrective actions, confirmation process, and administrative 

controls.

8. Confirmation Process: See item 7, above.

9. Administrative Controls: See item 7, above.

10. Operating Experience: Inspection of internal surfaces during the performance of periodic 

surveillances and maintenance activities have been in effect at many utilities in support of 

plant components reliability programs. These activities have proven effective in 

maintaining the material condition of plant systems, structures, and components. 

The elements that comprise these inspections (e.g., the scope of the inspections and 

inspection techniques) are consistent with industry practice and staff expectations. 

However, because the inspection frequency is plant-specific and depends on the plant 

operating experience, the applicant’s plant-specific operating experience or applicable 

generic operating experience is further evaluated for the extended period of operation. The 

applicant is to evaluate recent operating experience and provide objective evidence to

support the conclusion that the effects of aging are adequately managed.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.

EPRI Technical Report 1007933 "Aging Assessment Field Guide," December 2003.
September 2005 XI M-123 NUREG-1801, Rev. 1

XI.M39LUBRICATING OIL ANALYSIS PROGRAM

Program Description

The purpose of the Lubricating Oil Analysis Program is to ensure the oil environment in the 

mechanical systems is maintained to the required quality. The Lubricating Oil Analysis Program 

maintains oil systems contaminants (primarily water and particulates) within acceptable limits, 

thereby preserving an environment that is not conducive to loss of material, cracking or 

reduction of heat transfer. Lubricating oil testing activities include sampling and analysis of 

lubricating oil for detrimental contaminants. The presence of water or particulates may also be 

indicative of inleakage and corrosion product buildup.

Evaluation and Technical Basis

1. Scope of Program: On a periodic basis, this program samples lubricating oil from plant 

components subject to aging management review.

2. Preventive Actions: The lubricating oil analysis program maintains oil systems 

contaminants (primarily water and particulates) within acceptable limits.

3. Parameters Monitored/Inspected: For components with periodic oil changes in 

accordance with manufacturer’s recommendations, a particle count and check for water 

are performed to detect evidence of abnormal wear rates, contamination by moisture, or 

excessive corrosion. For components that do not have regular oil changes, viscosity,

neutralization number, and flash point are also determined to verify the oil is suitable for 

continued use. In addition, analytical ferrography and elemental analysis are performed to 

identify wear particles.

4. Detection of Aging Effects: Periodic sampling and compliance with the acceptance 

criteria provide assurance that lube oil contaminants do not exceed acceptable levels, 

thereby preserving an environment that is not conducive to aging mechanisms that could 

lead to the aging effects of loss of material, cracking and reduction of heat transfer. 

5. Monitoring and Trending: Oil analysis results are reviewed to determine if alert levels or 

limits have been reached or exceeded. This review also checks for unusual trends.

6. Acceptance Criteria: Particle concentration will be determined in accordance with 

industry standards such as SAE749D, ISO 4406, ISO 112218, and NAS 1638. Water and 

particle concentration will not exceed limits based on manufacturer’s recommendations or 

industry standards recommended for each components type. Viscosity bands are based 

on a tolerance around the base viscosity of the lubricating oil as recommended by the 

components manufacturer or industry standards. Metal limits as determined by spectral 

analysis and ferrography will be based on original baseline data and manufacturer’s 

recommendations, industry standards, or other justified basis.

7. Corrective Actions: Pursuant to 10 CFR Part 50, Appendix B, specific corrective actions 

are implemented in accordance with the plant quality assurance (QA) program. For 

example, if a limit is reached or exceeded, actions to address the condition are taken. 

These may include increased monitoring, vibration analysis, corrective maintenance, 

further laboratory analysis, and engineering evaluation. As discussed in the appendix to 
NUREG-1801, Rev. 1 XI M-124 September 2005

this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to 

address the corrective actions.

8. Confirmation Process: Site QA procedures, review and approval processes, and 

administrative controls are implemented in accordance with the requirements of 10 CFR 

Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process and administrative controls.

9. Administrative Controls: See item 8, above.

10. Operating Experience: The operating experience at some plants has identified water in 

the lubricating oil, and particulate contamination. However, no instances of component 

failures attributed to lubricating oil contamination have been identified.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2005.
September 2005 XI S-1 NUREG-1801, Rev. 1

XI.S1 ASME SECTION XI, SUBSECTION IWE

Program Description 

10 CFR 50.55a imposes the inservice inspection (ISI) requirements of the American Society of 

Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code, Section XI, 

Subsection IWE for steel containments (Class MC) and steel liners for concrete containments 

(Class CC). The full scope of IWE includes steel containment shells and their integral 

attachments; steel liners for concrete containments and their integral attachments; containment 

hatches and airlocks; seals, gaskets and moisture barriers; and pressure-retaining bolting. This 

evaluation covers the 2001 edition1 including the 2002 and 2003 Addenda, as approved in 

10 CFR 50.55a. ASME Code Section XI, Subsection IWE and the additional requirements 

specified in 10 CFR 50.55a(b)(2) constitute an existing mandated program applicable to 

managing aging of steel containments, steel liners of concrete containments, and other 

containment components for license renewal.

The primary ISI method specified in IWE is visual examination (general visual, VT-3, VT-1). 

Limited volumetric examination (ultrasonic thickness measurement) and surface examination 

(e.g., liquid penetrant) may also be necessary in some instances. Bolt preload is checked by 

either a torque or tension test. IWE specifies acceptance criteria, corrective actions, and 

expansion of the inspection scope when degradation exceeding the acceptance criteria is found. 

The evaluation of 10 CFR 50.55a and Subsection IWE as an aging management program 

(AMP) for license renewal is provided below. 

Evaluation and Technical Basis

1. Scope of Program: Subsection IWE-1000 specifies the components of steel 

containments and steel liners of concrete containments within its scope. The components 

within the scope of Subsection IWE are Class MC pressure-retaining components (steel 

containments) and their integral attachments; metallic shell and penetration liners of Class 

CC containments and their integral attachments; containment seals and gaskets; 

containment pressure-retaining bolting; and metal containment surface areas, including 

welds and base metal. The concrete portions of containments are inspected in 

accordance with Subsection IWL.

Subsection IWE exempts the following from examination:

(1) Components that are outside the boundaries of the containment as defined in the 

plant-specific design specification;

(2) Embedded or inaccessible portions of containment components that met the 

requirements of the original construction code of record;

(3) Components that become embedded or inaccessible as a result of vessel repair or 

replacement, provided IWE-1232 and IWE-5220 are met; and

(4) Piping, pumps, and valves that are part of the containment system or that penetrate 

or are attached to the containment vessel (governed by IWB or IWC).

 

1

An applicant may rely on a different version of the ASME Code, but should justify such use. An 

applicant may wish to refer to the SOC for an update of 10 CFR § 50.55a to justify use of a more recent 

edition of the Code.
NUREG-1801, Rev. 1 XI S-2 September 2005

10 CFR 50.55a(b)(2)(ix) specifies additional requirements for inaccessible areas. It states 

that the licensee is to evaluate the acceptability of inaccessible areas when conditions 

exist in accessible areas that could indicate the presence of or result in degradation to 

such inaccessible areas. Examination requirements for containment supports are not 

within the scope of Subsection IWE.

2. Preventive Action: No preventive actions are specified; Subsection IWE is a monitoring 

program.

3. Parameters Monitored or Inspected: Table IWE-2500-1 specifies seven categories for 

examination. The categories, parts examined, and examination methods are presented in 

the following table. The first six examination categories (E-A through E-G) constitute the 

ISI requirements of IWE. Examination category E-P references 10 CFR Part 50, Appendix 

J leak rate testing. Appendix J leak rate testing is evaluated as a separate AMP for license 

renewal in XI.S4.

CATEGORY PARTS EXAMINED EXAMINATION METHODa

E-A Containment surfaces General visual, visual VT-3

E-B

b Pressure retaining welds Visual VT-1

E-C Containment surfaces requiring 

augmented examination

Visual VT-1, volumetric

E-D Seals, gaskets, and moisture barriers Visual VT-3

E-F

b Pressure retaining dissimilar metal welds Surface

E-G Pressure retaining bolting Visual VT-1, bolt torque or 

tension test

E-P All pressure-retaining components 

(pressure retaining boundary, penetration 

bellows, airlocks, seals, and gaskets)

10 CFR Part 50, Appendix J 

(containment leak rate 

testing)

a

The applicable examination method (where multiple methods are listed) depends on 

the particular subcategory within each category.

b

These two categories are optional, in accordance with 10 CFR 50.55a(b)(2)(ix)(C).

Table IWE-2500-1 references the applicable section in IWE-3500 that identifies the aging 

effects that are evaluated. The parameters monitored or inspected depend on the 

particular examination category. For Examination Category E-A, as an example, metallic 

surfaces (without coatings) are examined for evidence of cracking, discoloration, wear, 

pitting, excessive corrosion, arc strikes, gouges, surface discontinuities, dents, and other 

signs of surface irregularities. For Examination Category E-D, seals, gaskets, and 

moisture barriers are examined for wear, damage, erosion, tear, surface cracks, or other 

defects that may violate the leak-tight integrity.

4. Detection of Aging Effects: The frequency and scope of examination specified in 

10 CFR 50.55a and Subsection IWE ensure that aging effects would be detected before 

they would compromise the design-basis requirements. As indicated in IWE-2400, 

inservice examinations and pressure tests are performed in accordance with one of two 

inspection programs, A or B, on a specified schedule. Under Inspection Program A, there 
September 2005 XI S-3 NUREG-1801, Rev. 1

are four inspection intervals (at 3, 10, 23, and 40 years) for which 100% of the required 

examinations must be completed. Within each interval, there are various inspection 

periods for which a certain percentage of the examinations are to be performed to reach 

100% at the end of that interval. In addition, a general visual examination is performed 

once each inspection period. After 40 years of operation, any future examinations will be 

performed in accordance with Inspection Program B. Under Inspection Program B, 

starting with the time the plant is placed into service, there is an initial inspection interval 

of 10 years and successive inspection intervals of 10 years each, during which 100% of 

the required examinations are to be completed. An expedited examination of containment 

is required by 10 CFR 50.55a in which an inservice (baseline) examination specified for 

the first period of the first inspection interval for containment is to be performed by 

September 9, 2001. Thereafter, subsequent examinations are performed every 10 years 

from the baseline examination. Regarding the extent of examination, all accessible 

surfaces receive a visual examination such as General Visual, VT-1, or VT-3 (see table in 

item 3 above). IWE-1240 requires augmented examinations (Examination Category E-C) 

of containment surface areas subject to degradation. A VT-1 visual examination is 

performed for areas accessible from both sides, and volumetric (ultrasonic thickness 

measurement) examination is performed for areas accessible from only one side. 

5. Monitoring and Trending: With the exception of inaccessible areas, all surfaces are 

monitored by virtue of the examination requirements on a scheduled basis. When 

component examination results require evaluation of flaws, evaluation of areas of 

degradation, or repairs, and the component is found to be acceptable for continued 

service, the areas containing such flaws, degradation, or repairs shall be reexamined 

during the next inspection period, in accordance with Examination Category E-C. When 

these reexaminations reveal that the flaws, areas of degradation, or repairs remain 

essentially unchanged for three consecutive inspection periods, these areas no longer 

require augmented examination in accordance with Examination Category E-C.

IWE-2430 specifies that (a) examinations performed during any one inspection that reveal 

flaws or areas of degradation exceeding the acceptance standards are to be extended to 

include an additional number of examinations within the same category approximately 

equal to the initial number of examinations, and (b) when additional flaws or areas of 

degradation that exceed the acceptance standards are revealed, all of the remaining 

examinations within the same category are to be performed to the extent specified in 

Table IWE-2500-1 for the inspection interval. Alternatives to these examinations are 

provided in 10 CFR 50.55a(b)(2)(ix)(D).

6. Acceptance Criteria: IWE-3000 provides acceptance standards for components of steel 

containments and liners of concrete containments. Table IWE-3410-1 presents criteria to 

evaluate the acceptability of the containment components for service following the 

preservice examination and each inservice examination. This table specifies the 

acceptance standard for each examination category. Most of the acceptance standards 

rely on visual examinations. Areas that are suspect require an engineering evaluation or 

require correction by repair or replacement. For some examinations, such as augmented

examinations, numerical values are specified for the acceptance standards. For the 

containment steel shell or liner, material loss exceeding 10% of the nominal containment 

wall thickness, or material loss that is projected to exceed 10% of the nominal 

containment wall thickness before the next examination, are documented. Such areas are 

to be accepted by engineering evaluation or corrected by repair or replacement in 

accordance with IWE-3122.
NUREG-1801, Rev. 1 XI S-4 September 2005

7. Corrective Actions: Subsection IWE states that components whose examination results 

indicate flaws or areas of degradation that do not meet the acceptance standards listed in 

Table-3410-1 are acceptable if an engineering evaluation indicates that the flaw or area of 

degradation is nonstructural in nature or has no effect on the structural integrity of the 

containment. Except as permitted by 10 CFR 50.55a(b)(ix)(D), components that do not 

meet the acceptance standards are subject to additional examination requirements, and 

the components are repaired or replaced to the extent necessary to meet the acceptance 

standards of IWE-3000. For repair of components within the scope of Subsection IWE, 

IWE-3124 states that repairs and reexaminations are to comply with IWA-4000. IWA-4000 

provides repair specifications for pressure retaining components including metal 

containments and metallic liners of concrete containments. As discussed in the appendix 

to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable 

to address the corrective actions.

8. Confirmation Process: When areas of degradation are identified, an evaluation is 

performed to determine whether repair or replacement is necessary. If the evaluation 

determines that repair or replacement is necessary, Subsection IWE specifies 

confirmation that appropriate corrective actions have been completed and are effective. 

Subsection IWE states that repairs and reexaminations are to comply with the 

requirements of IWA-4000. Reexaminations are conducted in accordance with the 

requirements of IWA-2200, and the recorded results are to demonstrate that the repair 

meets the acceptance standards set forth in Table IWE-3410-1. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address the confirmation process.

9. Administrative Controls: IWA-6000 provides specifications for the preparation, 

submittal, and retention of records and reports. As discussed in the appendix to this 

report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to 

address administrative controls.

10. Operating Experience: ASME Section XI, Subsection IWE was incorporated into 

10 CFR 50.55a in 1996. Prior to this time, operating experience pertaining to degradation 

of steel components of containment was gained through the inspections required by 10 

CFR Part 50, Appendix J and ad hoc inspections conducted by licensees and the Nuclear 

Regulatory Commission (NRC). NRC Information Notice (INs) 86-99, 88-82 and 89-79 

described occurrences of corrosion in steel containment shells. NRC Generic Letter 

(GL) 87-05 addressed the potential for corrosion of boiling water reactor (BWR) Mark I 

steel drywells in the “sand pocket region.” More recently, NRC IN 97-10 identified specific 

locations where concrete containments are susceptible to liner plate corrosion. The 

program is to consider the liner plate and containment shell corrosion concerns described 

in these generic communications. Implementation of the ISI requirements of Subsection 

IWE, in accordance with 10 CFR 50.55a, is a necessary element of aging management 

for steel components of steel and concrete containments through the period of extended 

operation. 

References

10 CFR Part 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled 

Power Reactors, Office of the Federal Register, National Archives and Records 

Administration, 2000.
September 2005 XI S-5 NUREG-1801, Rev. 1

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2005.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components,

Subsection IWA, General Requirements, 2001 edition including the 2002 and 2003 

Addenda, The ASME Boiler and Pressure Vessel Code, The American Society of 

Mechanical Engineers, New York, NY.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components,

Subsection IWB, Requirements for Class 1 Components of Light-Water Cooled Power 

Plants, 2001 edition including the 2002 and 2003 Addenda , The ASME Boiler and Pressure 

Vessel Code, The American Society of Mechanical Engineers, New York, NY.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components,

Subsection IWC, Requirements for Class 2 Components of Light-Water Cooled Power 

Plants, 2001 edition including the 2002 and 2003 Addenda, The ASME Boiler and Pressure 

Vessel Code, The American Society of Mechanical Engineers, New York, NY.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components,

Subsection IWE, Requirements for Class MC and Metallic Liners of Class CC Components 

of Light-Water Cooled Power Plants, 2001 edition including the 2002 and 2003 Addenda, 

The ASME Boiler and Pressure Vessel Code, The American Society of Mechanical 

Engineers, New York, NY.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components,

Subsection IWL, Requirements for Class CC Concrete Components of Light-Water Cooled 

Power Plants, 2001 edition including the 2002 and 2003 Addenda, The ASME Boiler and 

Pressure Vessel Code, The American Society of Mechanical Engineers, New York, NY.

NRC Generic Letter 87-05, Request for Additional Information Assessment of Licensee 

Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywells, U.S. Nuclear 

Regulatory Commission, March 12, 1987.

NRC Information Notice 86-99, Degradation of Steel Containments, U.S. Nuclear Regulatory 

Commission, December 8, 1986 and Supplement 1, February 14, 1991.

NRC Information Notice 88-82, Torus Shells with Corrosion and Degraded Coatings in BWR 

Containments, U.S. Nuclear Regulatory Commission, October 14,1988 and Supplement 1, 

May 2, 1989.

NRC Information Notice 89-79, Degraded Coatings and Corrosion of Steel Containment 

Vessels, U.S. Nuclear Regulatory Commission, December 1, 1989 and Supplement 1, June 

29, 1989.

NRC Information Notice 97-10, Liner Plate Corrosion in Concrete Containment, U.S. Nuclear 

Regulatory Commission, March 13, 1997.
NUREG-1801, Rev. 1 XI S-6 September 2005

XI.S2 ASME SECTION XI, SUBSECTION IWL

Program Description 

10 CFR 50.55a imposes the examination requirements of the American Society of Mechanical 

Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code, Section XI, Subsection IWL for 

reinforced and prestressed concrete containments (Class CC). The scope of IWL includes 

reinforced concrete and unbonded post-tensioning systems. This evaluation covers both the 

1992 edition with the 2001 edition1 including the 2002 and 2003 Addenda, as approved in 

10 CFR 50.55a. ASME Code Section XI, Subsection IWL and the additional requirements 

specified in 10 CFR 50.55a(b)(2) constitute an existing mandated program applicable to 

managing aging of containment reinforced concrete and unbonded post-tensioning systems for 

license renewal.

The primary inspection method specified in IWL is visual examination (VT-3C, VT-1, VT-1C). 

For prestressed containments, tendon wires are tested for yield strength, ultimate tensile 

strength, and elongation. Tendon corrosion protection medium is analyzed for alkalinity, water 

content, and soluble ion concentrations. Prestressing forces are measured in selected sample 

tendons. IWL specifies acceptance criteria, corrective actions, and expansion of the inspection 

scope when degradation exceeding the acceptance criteria is found.

The evaluation of 10 CFR 50.55a and Subsection IWL as an aging management program 

(AMP) for license renewal is provided below. 

Evaluation and Technical Basis

1. Scope of Program: Subsection IWL-1000 specifies the components of concrete 

containments within its scope. The components within the scope of Subsection IWL are 

reinforced concrete and unbonded post-tensioning systems of Class CC containments, as 

defined by CC-1000. Subsection IWL exempts from examination portions of the concrete 

containment that are inaccessible (e.g., concrete covered by liner, foundation material, or 

backfill, or obstructed by adjacent structures or other components).

10 CFR 50.55a(b)(2)(viii) specifies additional requirements for inaccessible areas. It states 

that the licensee is to evaluate the acceptability of concrete in inaccessible areas when 

conditions exist in accessible areas that could indicate the presence of or result in 

degradation to such inaccessible areas. Steel liners for concrete containments and their 

integral attachments are not within the scope of Subsection IWL, but are included within 

the scope of Subsection IWE.

2. Preventive Action: No preventive actions are specified; Subsection IWL is a monitoring 

program. If a coating program is currently credited for managing the effects of aging of 

concrete surfaces, then the program is to be continued during the period of extended 

operation.

3. Parameters Monitored or Inspected: Table IWL-2500-1 specifies two categories for 

examination of concrete surfaces: Category L-A for all concrete surfaces and Category L-

 

1

An applicant may rely on a different version of the ASME Code, but should justify such use. An 

applicant may wish to refer to the SOC for an update of 10 CFR § 50.55a to justify use of a more recent 

edition of the Code.
September 2005 XI S-7 NUREG-1801, Rev. 1

B for concrete surfaces surrounding tendon anchorages. Both of these categories rely on 

visual examination methods. Concrete surfaces are examined for evidence of damage or 

degradation, such as concrete cracks. IWL-2510 specifies that concrete surfaces are 

examined for conditions indicative of degradation, such as those defined in ACI 201.1R77. Table IWL-2500-1 also specifies Category L-B for test and examination requirements 

for unbonded post tensioning systems. Tendon anchorage and wires or strands are 

visually examined for cracks, corrosion, and mechanical damage. Tendon wires or strands 

are also tested for yield strength, ultimate tensile strength, and elongation. Tendon 

corrosion protection medium is tested by analysis for alkalinity, water content, and soluble 

ion concentrations.

4. Detection of Aging Effects: The frequency and scope of examinations specified in 

10 CFR 50.55a and Subsection IWL ensure that aging effects would be detected before 

they would compromise the design-basis requirements. The frequency of inspection is 

specified in IWL-2400. Concrete inspections are performed in accordance with 

Examination Category L-A. Under Subsection IWL, inservice inspections for concrete and 

unbonded post-tensioning systems are required at one, three, and five years following the 

structural integrity test. Thereafter, inspections are performed at five-year intervals. For 

sites with two plants, the schedule for inservice inspection is provided in IWL-2421. In the 

case of tendons, only a sample of the tendons of each tendon type requires examination 

at each inspection. The tendons to be examined during an inspection are selected on a 

random basis. Table IWL-2521-1 specifies the number of tendons to be selected for each 

type (e.g., hoop, vertical, dome, helical, and inverted U) for each inspection period. The 

minimum number of each tendon type selected for inspection varies from 2 to 4%. 

Regarding detection methods for aging effects, all concrete surfaces receive a visual VT3C examination. Selected areas, such as those that indicate suspect conditions and areas 

surrounding tendon anchorages, receive a more rigorous VT-1 or VT-1C examination. 

Prestressing forces in sample tendons are measured. In addition, one sample tendon of 

each type is detensioned. A single wire or strand is removed from each detensioned 

tendon for examination and testing. These visual examination methods and testing would 

identify the aging effects of accessible concrete components and prestressing systems in 

concrete containments.

5. Monitoring and Trending: Except in inaccessible areas, all concrete surfaces are 

monitored on a regular basis by virtue of the examination requirements. For prestressed 

containments, trending of prestressing forces in tendons is required in accordance with 

paragraph (b)(2)(viii) of 10 CFR 50.55a. In addition to the random sampling used for 

tendon examination, one tendon of each type is selected from the first-year inspection 

sample and designated as a common tendon. Each common tendon is then examined 

during each inspection. This procedure provides monitoring and trending information over 

the life of the plant. 10 CFR 50.55a and Subsection IWL also require that prestressing 

forces in all inspection sample tendons be measured by lift-off tests and compared with 

acceptance standards based on the predicted force for that type of tendon over its life.

6. Acceptance Criteria: IWL-3000 provides acceptance criteria for concrete containments. 

For concrete surfaces, the acceptance criteria rely on the determination of the 

"Responsible Engineer" (as defined by the ASME Code) regarding whether there is any 

evidence of damage or degradation sufficient to warrant further evaluation or repair. The 

acceptance criteria are qualitative; guidance is provided in IWL-2510, which references 

ACI 201.1R-77 for identification of concrete degradation. IWL-2320 requires that the 

Responsible Engineer be a registered professional engineer experienced in evaluating 
NUREG-1801, Rev. 1 XI S-8 September 2005

the inservice condition of structural concrete and knowledgeable of the design and 

construction codes and other criteria used in design and construction of concrete 

containments. Quantitative acceptance criteria based on the "Evaluation Criteria" provided 

in Chapter 5 of ACI 349.3R may also be used to augment the qualitative assessment of 

the responsible engineer. The acceptance standards for the unbonded post-tensioning 

system are quantitative in nature. For the post-tensioning system, quantitative acceptance 

criteria are given for tendon force and elongation, tendon wire or strand samples, and 

corrosion protection medium. 10 CFR 50.55a and Subsection IWL do not define the 

method for calculating predicted tendon prestressing forces for comparison to the 

measured tendon lift-off forces. The predicted tendon forces are to be calculated in 

accordance with Regulatory Guide 1.35.1, which provides an acceptable methodology for 

use through the period of extended operation.

7. Corrective Actions: Subsection IWL specifies that items for which examination results do 

not meet the acceptance standards are to be evaluated in accordance with IWL-3300 

"Evaluation" and described in an engineering evaluation report. The report is to include an 

evaluation of whether the concrete containment is acceptable without repair of the item 

and if repair is required, the extent, method, and completion date of the repair or 

replacement. The report also identifies the cause of the condition and the extent, nature, 

and frequency of additional examinations. Subsection IWL also provides repair 

procedures to follow in IWL-4000. This includes requirements for the concrete repair, 

repair of reinforcing steel, and repair of the post-tensioning system. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address the corrective actions.

8. Confirmation Process: When areas of degradation are identified, an evaluation is 

performed to determine whether repair or replacement is necessary. As part of this 

evaluation, IWL-3300 specifies that the engineering evaluation report include the extent, 

nature, and frequency of additional examinations. IWL-4000 specifies the requirements for 

examination of areas that are repaired. Pressure tests following repair or modifications are 

in accordance with IWL-5000. As discussed in the appendix to this report, the staff finds 

the requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process. 

9. Administrative Controls: IWA-1400 specifies the preparation of plans, schedules, and 

inservice inspection summary reports. In addition, written examination instructions and 

procedures, verification of qualification level of personnel who perform the examinations, 

and documentation of a quality assurance program are specified. IWA-6000 specifically 

covers the preparation, submittal, and retention of records and reports. As discussed in 

the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix 

B, acceptable to address the administrative controls.

10. Operating Experience: ASME Section XI, Subsection IWL was incorporated into 

10 CFR 50.55a in 1996. Prior to this time, operating experience pertaining to degradation 

of reinforced concrete and prestressing systems in concrete containments was gained 

through the inspections required by 10 CFR Part 50, Appendix J and ad hoc inspections 

conducted by licensees and the Nuclear Regulatory Commission (NRC). Recently, NRC 

Information Notice (IN) 99-10 described occurrences of degradation in prestressing 

systems. The program is to consider the degradation concerns described in this generic 

communication. Implementation of Subsection IWL, in accordance with 10 CFR 50.55a, is 
September 2005 XI S-9 NUREG-1801, Rev. 1

a necessary element of aging management for concrete containments through the period 

of extended operation. 

References

10 CFR Part 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled 

Power Reactors, Office of the Federal Register, National Archives and Records 

Administration, 2005.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2005.

ACI Standard 201.1R-77, Guide for Making a Condition Survey of Concrete in Service,

American Concrete Institute.

ACI Standard 349.3R-96, Evaluation of Existing Nuclear Safety-Related Concrete Structures,

American Concrete Institute.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components,

Subsection IWA, General Requirements, 2001 edition including the 2002 and 2003 

Addenda, The ASME Boiler and Pressure Vessel Code, The American Society of 

Mechanical Engineers, New York, NY.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components,

Subsection IWE, Requirements for Class MC and Metallic Liners of Class CC Components 

of Light-Water Cooled Power Plants, 2001 edition including the 2002 and 2003 Addenda, 

The ASME Boiler and Pressure Vessel Code, The American Society of Mechanical 

Engineers, New York, NY.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components,

Subsection IWL, Requirements for Class CC Concrete Components of Light-Water Cooled 

Power Plants, 2001 edition including the 2002 and 2003 Addenda, The ASME Boiler and 

Pressure Vessel Code, The American Society of Mechanical Engineers, New York, NY.

NRC Information Notice 99-10, Revision 1, Degradation of Prestressing Tendon Systems in 

Prestressed Concrete Containment, U.S. Nuclear Regulatory Commission, October 7, 1999.
NUREG-1801, Rev. 1 XI S-10 September 2005

XI.S3 ASME SECTION XI, SUBSECTION IWF

Program Description 

10 CFR 50.55a imposes the inservice inspection (ISI) requirements of the American Society of 

Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section XI, for Class 1, 2, 3, 

and MC piping and components and their associated supports. Inservice inspection of supports 

for ASME piping and components is addressed in Section XI, Subsection IWF. This evaluation 

covers the 2001 edition1 including the 2002 and 2003 Addenda, as approved in 10 CFR 50.55a. 

ASME Code Section XI, Subsection IWF constitutes an existing mandated program applicable 

to managing aging of ASME Class 1, 2, 3, and MC supports for license renewal. 

The IWF scope of inspection for supports is based on sampling of the total support population. 

The sample size varies depending on the ASME Class. The largest sample size is specified for 

the most critical supports (ASME Class 1). The sample size decreases for the less critical 

supports (ASME Class 2 and 3). Discovery of support deficiencies during regularly scheduled 

inspections triggers an increase of the inspection scope, in order to ensure that the full extent of 

deficiencies is identified. The primary inspection method employed is visual examination. 

Degradation that potentially compromises support function or load capacity is identified for 

evaluation. IWF specifies acceptance criteria and corrective actions. Supports requiring 

corrective actions are re-examined during the next inspection period.

 

The evaluation of Subsection IWF as an aging management program (AMP) for license renewal 

is provided below. 

Evaluation and Technical Basis

1. Scope of Program: For Class 1 piping and component supports, Subsection IWF 

(1989 edition) refers to Subsection IWB for the inspection scope and schedule. According 

to Table IWB-2500-1, only 25% of nonexempt supports are subject to examination. 

Supports exempt from examination are the supports for piping systems that are exempt 

from examination, according to pipe diameter or service. The same supports are 

inspected in each 10-year inspection interval. For Class 2, 3, and MC piping and 

component supports, Subsection IWF (1989 edition) refers to Subsections IWC, IWD, and 

IWE for the inspection scope and schedule. According to Table IWC-2500-1, 7.5% of 

nonexempt supports are subject to examination for Class 2 systems. The same supports 

are inspected in each 10-year inspection interval. No specific numerical percentages are 

identified in Subsections IWD and IWE for Class 3 and Class MC, respectively.

Starting with the 1990 addenda, the scope of Subsection IWF was revised. The required 

percentages of each type of nonexempt support subject to examination were incorporated 

into Table IWF-2500-1. The revised percentages are 25% of Class 1 nonexempt piping 

supports, 15% of Class 2 nonexempt piping supports, 10% of Class 3 nonexempt piping 

supports, and 100% of supports other than piping supports (Class 1, 2, 3, and MC). For 

pipe supports, the total sample consists of supports from each system (such as main 

steam, feedwater, residual heat removal), where the individual sample sizes are 

proportional to the total number of nonexempt supports of each type and function within 

 

1

An applicant may rely on a different version of the ASME Code, but should justify such use. An 

applicant may wish to refer to the SOC for an update of 10 CFR § 50.55a to justify use of a more recent 

edition of the Code.
September 2005 XI S-11 NUREG-1801, Rev. 1

each system. For multiple components other than piping, within a system of similar 

design, function, and service, the supports of only one of the multiple components are 

required to be examined. To the extent practical, the same supports selected for 

examination during the first inspection interval are examined during each successive 

inspection interval.

2. Preventive Action: No preventive actions are specified; Subsection IWF is an inspection 

program.

3. Parameters Monitored or Inspected: IWF specifies visual examination (VT-3) of 

supports. The parameters monitored or inspected include corrosion; deformation; 

misalignment; improper clearances; improper spring settings; damage to close tolerance 

machined or sliding surfaces; and missing, detached, or loosened support items. The 

visual inspection would be expected to identify relatively large cracks.

Table IWF-2500-1 (1989 edition) specifies examination of the following:

(F1.10) Mechanical connections to pressure-retaining components and building 

structure;

(F1.20) Weld connections to building structure;

(F1.30) Weld and mechanical connections at intermediate joints in multi-connected 

integral and nonintegral supports;

(F1.40) Clearances of guides and stops, alignment of supports, and assembly of support 

items;

(F1.50) Spring supports and constant load supports;

(F1.60) Sliding surfaces;

(F1.70) Hot or cold position of spring supports and constant load supports.

(Starting with the 1990 addenda, these items are listed in paragraph IWF-2500.)

4. Detection of Aging Effects: VT-3 visual examination is specified in Table IWF-2500-1. 

The complete inspection scope is repeated every 10-year inspection interval. The 

qualified VT-3 inspector uses judgment in assessing general corrosion; observed 

degradation is documented if loss of structural capacity is suspected.

5. Monitoring and Trending: There is no requirement to monitor or report progressive, 

time-dependent degradation. Unacceptable conditions, according to IWF-3400, are noted 

for correction or further evaluation. 

6. Acceptance Criteria: The acceptance standards for visual examination are specified in 

IWF-3400. In IWF-3410(b)(5), "roughness or general corrosion which does not reduce the 

load bearing capacity of the support" is given as an example of a "non-relevant condition,” 

which requires no further action. IWF-3410(a) identifies the following conditions as 

unacceptable:

(i) deformations or structural degradations of fasteners, springs, clamps, or other 

support items;

(ii) missing, detached, or loosened support items;

(iii) arc strikes, weld spatter, paint, scoring, roughness, or general corrosion on close 

tolerance machined or sliding surfaces;

(iv) improper hot or cold positions of spring supports and constant load supports;
NUREG-1801, Rev. 1 XI S-12 September 2005

(v) misalignment of supports;

(vi) improper clearances of guides and stops.

Identification of unacceptable conditions triggers an expansion of the inspection scope, in 

accordance with IWF-2430, and reexamination of the supports requiring corrective actions 

during the next inspection period, in accordance with IWF-2420(b).

7. Corrective Actions: In accordance with IWF-3122, supports containing unacceptable 

conditions are evaluated or tested, or corrected before returning to service. Corrective 

actions are delineated in IWF-3122.2. IWF-3122.3 provides an alternative for evaluation or 

testing, to substantiate structural integrity and/or functionality. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address the corrective actions.

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process. 

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: To date, IWF sampling inspections have been effective in 

managing aging effects for ASME Class 1, 2, 3, and MC supports. There is reasonable 

assurance that the Subsection IWF inspection program will be effective through the period 

of extended operation. 

References

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2005.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components,

Subsection IWB, Requirements for Class 1 Components of Light-Water Cooled Power 

Plants, 2001 edition including the 2002 and 2003 Addenda. The ASME Boiler and Pressure 

Vessel Code, The American Society of Mechanical Engineers, New York, NY.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components,

Subsection IWC, Requirements for Class 2 Components of Light-Water Cooled Power 

Plants, 2001 edition including the 2002 and 2003 Addenda. The ASME Boiler and Pressure 

Vessel Code, The American Society of Mechanical Engineers, New York, NY.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components,

Subsection IWD, Requirements for Class 3 Components of Light-Water Cooled Power 

Plants, 2001 edition including the 2002 and 2003 Addenda. The ASME Boiler and Pressure 

Vessel Code, The American Society of Mechanical Engineers, New York, NY.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components,

Subsection IWE, Requirements for Class MC and Metallic Liners of Class CC Components 

of Light-Water Cooled Power Plants, 2001 edition including the 2002 and 2003 Addenda. 
September 2005 XI S-13 NUREG-1801, Rev. 1

The ASME Boiler and Pressure Vessel Code, The American Society of Mechanical 

Engineers, New York, NY.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components,

Subsection IWF, Requirements for Class 1, 2, 3, and MC Component Supports of LightWater Cooled Power Plants, 2001 edition including the 2002 and 2003 Addenda. The ASME 

Boiler and Pressure Vessel Code, The American Society of Mechanical Engineers, New 

York, NY.
NUREG-1801, Rev. 1 XI S-14 September 2005

XI.S4 10 CFR PART 50, APPENDIX J

Program Description 

As described in 10 CFR Part 50, Appendix J, containment leak rate tests are required "to assure 

that (a) leakage through the primary reactor containment and systems and components 

penetrating primary containment shall not exceed allowable leakage rate values as specified in 

the technical specifications or associated bases and (b) periodic surveillance of reactor 

containment penetrations and isolation valves is performed so that proper maintenance and 

repairs are made during the service life of the containment, and systems and components 

penetrating primary containment."

Appendix J provides two options, A and B, either of which can be chosen to meet the 

requirements of a containment LRT program. Under Option A, all of the testing must be 

performed on a periodic interval. Option B is a performance-based approach. Some of the 

differences between these options are discussed below, and more detailed information for 

Option B is provided in the Nuclear Regulatory Commission (NRC) Regulatory Guide 

(RG) 1.163 and NEI 94-01, Rev. 0.

Evaluation and Technical Basis

1. Scope of Program: The scope of the containment LRT program includes all pressureretaining components. Two types of tests are implemented. Type A tests are performed to 

measure the overall primary containment integrated leakage rate, which is obtained by 

summing leakage through all potential leakage paths, including containment welds, 

valves, fittings, and components that penetrate containment. Type B tests are performed 

to measure local leakage rates across each pressure-containing or leakage-limiting

boundary for containment penetrations. Type A and B tests described in 10 CFR Part 50, 

Appendix J, are acceptable methods for performing these LRTs. Leakage testing for 

containment isolation valves (normally performed under Type C tests), if not included 

under this program, is included under LRT programs for systems containing the isolation 

valves.

2. Preventive Action: No preventive actions are specified; the containment LRT program is 

a monitoring program.

3. Parameters Monitored or Inspected: The parameters to be monitored are leakage rates 

through containment shells; containment liners; and associated welds, penetrations, 

fittings, and other access openings.

4. Detection of Aging Effects: A containment LRT program is effective in detecting 

degradation of containment shells, liners, and components that compromise the 

containment pressure boundary, including seals and gaskets. While the calculation of 

leakage rates demonstrates the leak-tightness and structural integrity of the containment, 

it does not by itself provide information that would indicate that aging degradation has 

initiated or that the capacity of the containment may have been reduced for other types of 

loads, such as seismic loading. This would be achieved with the additional implementation 

of an acceptable containment inservice inspection program as described in XI.S1 and 

XI.S2.
September 2005 XI S-15 NUREG-1801, Rev. 1

5. Monitoring and Trending: Because the LRT program is repeated throughout the 

operating license period, the entire pressure boundary is monitored over time. The 

frequency of these tests depends on which option (A or B) is selected. With Option A, 

testing is performed on a regular fixed time interval as defined in 10 CFR Part 50, 

Appendix J. In the case of Option B, the interval for testing may be increased on the basis 

of acceptable performance in meeting leakage limits in prior tests. Additional details for 

implementing Option B are provided in NRC Regulatory Guide 1.163 and NEI 94-01, 

Rev. 0.

6. Acceptance Criteria: Acceptance criteria for leakage rates are defined in plant technical 

specifications. These acceptance criteria meet the requirements in 10 CFR Part 50, 

Appendix J, and are part of each plant's current licensing basis. The current licensing 

basis carries forward to the period of extended operation.

7. Corrective Actions: Corrective actions are taken in accordance with 10 CFR Part 50, 

Appendix J, and NEI 94-01. When leakage rates do not meet the acceptance criteria, an 

evaluation is performed to identify the cause of the unacceptable performance, and 

appropriate corrective actions must be taken. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

corrective actions.

8. Confirmation Process: When corrective actions are implemented to repair a condition 

that causes excessive leakage, confirmation by additional leak rate testing is performed to 

confirm that the deficiency has been corrected. As discussed in the appendix to this 

report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to 

address the confirmation process. 

9. Administrative Controls: Results of the LRT program are documented as described in 

10 CFR Part 50, Appendix J, to demonstrate that the acceptance criteria for leakage have 

been satisfied. The test results that exceed the performance criteria must be assessed 

under 10 CFR 50.72 and 10 CFR 50.73. As discussed in the appendix to this report, the 

staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

administrative controls.

10. Operating Experience: To date, the 10 CFR Part 50, Appendix J, LRT program has been 

effective in preventing unacceptable leakage through the containment pressure boundary. 

Implementation of Option B for testing frequency must be consistent with plant-specific 

operating experience.

References

10 CFR Part 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled 

Power Reactors, Office of the Federal Register, National Archives and Records 

Administration, 2000.

10 CFR 50.72, Immediate Notification Requirements for Operating Nuclear Power Reactors,

Office of the Federal Register, National Archives and Records Administration, 1997.

10 CFR 50.73, Licensee Event Report System, Office of the Federal Register, National Archives 

and Records Administration, 1997.
NUREG-1801, Rev. 1 XI S-16 September 2005

NEI 94-01, Rev. 0, Industry Guideline for Implementing Performance-Based Option of 

 10 CFR Part 50 Appendix J, Nuclear Energy Institute, July 26, 1995.

NRC Regulatory Guide 1.163, Performance-Based Containment Leak-Test Program," 

 U.S. Nuclear Regulatory Commission, September 1995.
September 2005 XI S-17 NUREG-1801, Rev. 1

XI.S5 MASONRY WALL PROGRAM

Program Description 

Nuclear Regulatory Commission (NRC) IE Bulletin (IEB) 80-11, "Masonry Wall Design," and 

NRC Information Notice (IN) 87-67, "Lessons Learned from Regional Inspections of Licensee 

Actions in Response to IE Bulletin 80-11," constitute an acceptable basis for a masonry wall 

aging management program (AMP). IEB 80-11 required the identification of masonry walls in 

close proximity to, or having attachments from, safety-related systems or components, and the 

evaluation of design adequacy and construction practice. NRC IN 87-67 recommended plantspecific condition monitoring of masonry walls and administrative controls to ensure that the 

evaluation basis developed in response to NRC IEB 80-11 is not invalidated by (1) deterioration 

of the masonry walls (e.g., new cracks not considered in the reevaluation), (2) physical plant 

changes such as installation of new safety-related systems or components in close proximity to 

masonry walls, or (3) reclassification of systems or components from non-safety-related to 

safety-related.

Important elements in the evaluation of many masonry walls during the NRC IEB 80-11 program 

included (1) installation of steel edge supports to provide a sound technical basis for boundary 

conditions used in seismic analysis and (2) installation of steel bracing to ensure containment of 

unreinforced masonry walls during a seismic event. Consequently, in addition to the 

development of cracks in the masonry walls, loss of function of the structural steel supports and 

bracing would also invalidate the evaluation basis.

The objective of the masonry wall program is to manage aging effects so that the evaluation 

basis established for each masonry wall within the scope of license renewal remains valid 

through the period of extended operation. Since the issuance of NRC IEB 80-11 and NRC 

IN 87-67, the NRC promulgated 10 CFR 50.65, the Maintenance Rule. Masonry walls may be 

inspected as part of the Structures Monitoring Program (XI.S6) conducted for the Maintenance 

Rule, provided the ten attributes described below are incorporated.

The attributes of an acceptable Masonry Wall Program are described below. 

Evaluation and Technical Basis

1. Scope of Program: The scope includes all masonry walls identified as performing 

intended functions in accordance with 10 CFR 54.4.

2. Preventive Action: No specific preventive actions are required.

3. Parameters Monitored or Inspected: The primary parameter monitored is wall cracking 

that could potentially invalidate the evaluation basis. 

4. Detection of Aging Effects: Visual examination of the masonry walls by qualified 

inspection personnel is sufficient. The frequency of inspection is selected to ensure there 

is no loss of intended function between inspections. The inspection frequency may vary 

from wall to wall, depending on the significance of cracking in the evaluation basis. 

Unreinforced masonry walls, which have not been contained by bracing, warrant the most 

frequent inspection, because the development of cracks may invalidate the existing 

evaluation basis.
NUREG-1801, Rev. 1 XI S-18 September 2005

5. Monitoring and Trending: Trending is not required. Monitoring is achieved by periodic 

examination for cracking.

6. Acceptance Criteria: For each masonry wall, the extent of observed cracking of masonry 

and degradation of steel edge supports and bracing is not to invalidate the evaluation 

basis. Corrective actions are taken if the extent of cracking and steel degradation is 

sufficient to invalidate the evaluation basis. An option is to develop a new evaluation basis 

that accounts for the degraded condition of the wall (i.e., acceptance by further 

evaluation).

7. Corrective Actions: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective 

actions.

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process. 

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: Since 1980, masonry walls that perform an intended function 

have been systematically identified through licensee programs in response to NRC IEB 

80-11, USI A-46, and 10 CFR 50.48. NRC IN 87-67 documented lessons learned from the 

NRC IEB 80-11 program, and provided recommendations for administrative controls and

periodic inspection to ensure that the evaluation basis for each safety-significant masonry 

wall is maintained. Whether conducted as a stand-alone program or as part of structures 

monitoring for MR, a masonry wall AMP that incorporates the recommendations

delineated in NRC IN 87-67 should ensure that the intended functions of all masonry walls 

within the scope of license renewal are maintained for the period of extended operation.

References

10 CFR 50.48, Fire Protection, Office of the Federal Register, National Archives and Records 

Administration, 2000. 

10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power 

Plants, Office of the Federal Register, National Archives and Records Administration, 2000.

NRC Generic Letter 87-02, Verification of Seismic Adequacy of Mechanical and Electrical 

Equipment in Operating Reactors, Unresolved Safety Issue (USI) A-46, U.S. Nuclear 

Regulatory Commission, February 19, 1987.

NRC IE Bulletin 80-11, Masonry Wall Design, U.S. Nuclear Regulatory Commission, 

May 8, 1980.

NRC Information Notice 87-67, Lessons Learned from Regional Inspections of Licensee Actions 

in Response to IE Bulletin 80-11, U.S. Nuclear Regulatory Commission, December 31, 

1987.
September 2005 XI S-19 NUREG-1801, Rev. 1

XI.S6 STRUCTURES MONITORING PROGRAM

Program Description 

Implementation of structures monitoring under 10 CFR 50.65 (the Maintenance Rule) is 

addressed in Nuclear Regulatory Commission (NRC) Regulatory Guide (RG) 1.160, Rev. 2, and 

NUMARC 93-01, Rev. 2. These two documents provide guidance for development of licenseespecific programs to monitor the condition of structures and structural components within the 

scope of the Maintenance Rule, such that there is no loss of structure or structural component 

intended function.

Because structures monitoring programs are licensee-specific, the Evaluation and Technical 

Basis for this aging management program (AMP) is based on the implementation guidance 

provided in Regulatory Guide 1.160, Rev. 2, and NUMARC 93-01, Rev. 2. Existing licenseespecific programs developed for the implementation of structures monitoring under 

10 CFR 50.65 are acceptable for license renewal provided these programs satisfy the 10 

attributes described below.

If protective coatings are relied upon to manage the effects of aging for any structures included 

in the scope of this AMP, the structures monitoring program is to address protective coating 

monitoring and maintenance.

Evaluation and Technical Basis

1. Scope of Program: The applicant specifies the structure/aging effect combinations that 

are managed by its structures monitoring program.

2. Preventive Action: No preventive actions are specified.

3. Parameters Monitored or Inspected: For each structure/aging effect combination, the 

specific parameters monitored or inspected are selected to ensure that aging degradation 

leading to loss of intended functions will be detected and the extent of degradation can be 

determined. Parameters monitored or inspected are to be commensurate with industry 

codes, standards and guidelines, and are to also consider industry and plant-specific 

operating experience. Although not required, ACI 349.3R-96 and ANSI/ASCE 11-90 

provide an acceptable basis for selection of parameters to be monitored or inspected for 

concrete and steel structural elements and for steel liners, joints, coatings, and 

waterproofing membranes (if applicable). If necessary for managing settlement and 

erosion of porous concrete subfoundations, the continued functionality of a site dewatering system is to be monitored. The plant-specific structures monitoring program is to 

contain sufficient detail on parameters monitored or inspected to conclude that this 

program attribute is satisfied.

4. Detection of Aging Effects: For each structure/aging effect combination, the inspection 

methods, inspection schedule, and inspector qualifications are selected to ensure that 

aging degradation will be detected and quantified before there is loss of intended 

functions. Inspection methods, inspection schedule, and inspector qualifications are to be 

commensurate with industry codes, standards and guidelines, and are to also consider 

industry and plant-specific operating experience. Although not required, ACI 349.3R-96 

and ANSI/ASCE 11-90 provide an acceptable basis for addressing detection of aging 
NUREG-1801, Rev. 1 XI S-20 September 2005

effects. The plant-specific structures monitoring program is to contain sufficient detail on 

detection to conclude that this program attribute is satisfied.

5. Monitoring and Trending: Regulatory Position 1.5, "Monitoring of Structures," in RG 

1.160, Rev. 2, provides an acceptable basis for meeting the attribute. A structure is 

monitored in accordance with 10 CFR 50.65 (a)(2) provided there is no significant 

degradation of the structure. A structure is monitored in accordance with 10 CFR 50.65 

(a)(1) if the extent of degradation is such that the structure may not meet its design basis 

or, if allowed to continue uncorrected until the next normally scheduled assessment, may 

not meet its design basis.

6. Acceptance Criteria: For each structure/aging effect combination, the acceptance criteria 

are selected to ensure that the need for corrective actions will be identified before loss of 

intended functions. Acceptance criteria are to be commensurate with industry codes, 

standards and guidelines, and are to also consider industry and plant-specific operating 

experience. Although not required, ACI 349.3R-96 provides an acceptable basis for 

developing acceptance criteria for concrete structural elements, steel liners, joints, 

coatings, and waterproofing membranes. The plant-specific structures monitoring program 

is to contain sufficient detail on acceptance criteria to conclude that this program attribute 

is satisfied.

7. Corrective Actions: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective 

actions.

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process. 

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: Although in many plants structures monitoring programs have 

only recently been implemented, plant maintenance has been ongoing since initial plant 

operation. A plant-specific program that includes the attributes described above will be an 

effective AMP for license renewal.

References

10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power 

Plants, Office of the Federal Register, National Archives and Records Administration, 2005.

ACI Standard 349.3R-96, Evaluation of Existing Nuclear Safety-Related Concrete Structures,

American Concrete Institute.

ANSI/ASCE 11-90, Guideline for Structural Condition Assessment of Existing Buildings,

American Society of Civil Engineers.

NRC Regulatory Guide 1.160, Rev. 2, Monitoring the Effectiveness of Maintenance at Nuclear 

Power Plants, U.S. Nuclear Regulatory Commission, March 1997.
September 2005 XI S-21 NUREG-1801, Rev. 1

NUMARC 93-01, Rev. 2, Industry Guideline for Monitoring the Effectiveness of Maintenance at 

Nuclear Power Plants (Line-In/Line-Out Version), Nuclear Energy Institute, April 1996.
NUREG-1801, Rev. 1 XI S-22 September 2005

XI.S7 RG 1.127, INSPECTION OF WATER-CONTROL STRUCTURES ASSOCIATED WITH 

NUCLEAR POWER PLANTS

Program Description

Nuclear Regulatory Commission (NRC) Regulatory Guide (RG) 1.127, Revision 1, "Inspection of 

Water-Control Structures Associated with Nuclear Power Plants," describes an acceptable basis 

for developing an inservice inspection and surveillance program for dams, slopes, canals, and 

other water-control structures associated with emergency cooling water systems or flood 

protection of nuclear power plants. The RG 1.127 program addresses age-related deterioration, 

degradation due to extreme environmental conditions, and the effects of natural phenomena 

that may affect water-control structures. The RG 1.127 program recognizes the importance of 

periodic monitoring and maintenance of water-control structures so that the consequences of 

age-related deterioration and degradation can be prevented or mitigated in a timely manner.

RG 1.127 provides detailed guidance for the licensee's inspection program for water-control 

structures, including guidance on engineering data compilation, inspection activities, technical 

evaluation, inspection frequency, and the content of inspection reports. Water-control structures 

covered by the RG 1.127 program include concrete structures; embankment structures; spillway 

structures and outlet works; reservoirs; cooling water channels and canals, and intake and 

discharge structures; and safety and performance instrumentation. RG 1.127 delineates current 

NRC practice in evaluating inservice inspection programs for water-control structures. The 

attributes of an acceptable aging management program (AMP) for license renewal are 

described below.

For plants not committed to RG 1.127, Revision 1, aging management of water-control 

structures may be included in the Structures Monitoring Program (XI.S6). Even if plant is 

committed to RG 1.127, Revision 1, aging management of certain structures and components 

may be included in the Structures Monitoring Program (XI.S6). However, details pertaining to 

water-control structures are to incorporate the attributes described herein.

Evaluation and Technical Basis

1. Scope of Program: RG 1.127 applies to water-control structures associated with 

emergency cooling water systems or flood protection of nuclear power plants. The watercontrol structures included in the RG 1.127 program are concrete structures; embankment 

structures; spillway structures and outlet works; reservoirs; cooling water channels and 

canals, and intake and discharge structures; and safety and performance instrumentation.

2. Preventive Action: No preventive actions are specified; RG 1.127 is a monitoring 

program.

3. Parameters Monitored or Inspected: RG 1.127 identifies the parameters to be 

monitored and inspected for water-control structures. The parameters vary depending on 

the particular structure. Parameters to be monitored and inspected for concrete structures 

include cracking, movements (e.g., settlement, heaving, deflection), conditions at 

junctions with abutments and embankments, erosion, cavitation, seepage, and leakage. 

Parameters to be monitored and inspected for earthen embankment structures include 

settlement, depressions, sink holes, slope stability (e.g., irregularities in alignment and 

variances from originally constructed slopes), seepage, proper functioning of drainage 

systems, and degradation of slope protection features. Further details of parameters to be 
September 2005 XI S-23 NUREG-1801, Rev. 1

monitored and inspected for these and other water-control structures are specified in 

Section C.2 of RG 1.127.

4. Detection of Aging Effects: Visual inspections are primarily used to detect degradation 

of water-control structures. In some cases, instruments have been installed to measure 

the behavior of water-control structures. RG 1.127 indicates that the available records and 

readings of installed instruments are to be reviewed to detect any unusual performance or 

distress that may be indicative of degradation. RG 1.127 describes periodic inspections, to 

be performed at least once every five years. Similar intervals of five years are specified in 

ACI 349.3R for inspection of structures continually exposed to fluids or retaining fluids. 

Such intervals have been shown to be adequate to detect degradation of water-control 

structures before they have a significant effect on plant safety. RG 1.127 also describes 

special inspections immediately following the occurrence of significant natural 

phenomena, such as large floods, earthquakes, hurricanes, tornadoes, and intense local 

rainfalls.

5. Monitoring and Trending: Water-control structures are monitored by periodic inspection 

as described in RG 1.127. In addition to monitoring the aging effects identified in Attribute 

(3) above, inspections also monitor the adequacy and quality of maintenance and 

operating procedures. RG 1.127 does not discuss trending.

6. Acceptance Criteria: Acceptance criteria to evaluate the need for corrective actions are 

not specified in RG 1.127. However, the “Evaluation Criteria” provided in Chapter 5 of ACI 

349.3R-96 provides acceptance criteria (including quantitative criteria) for determining the 

adequacy of observed aging effects and specifies criteria for further evaluation. Although 

not required, plant-specific acceptance criteria based on Chapter 5 of ACI 349.3R-96 are 

acceptable. Acceptance criteria for earthen structures such as dams, canals, and 

embankments are to be consistent with programs falling within the regulatory jurisdiction 

of the Federal Energy Regulatory Commission (FERC) or the U.S. Army Corps of 

Engineers.

7. Corrective Actions: RG 1.127 recommends that the licensee's inservice inspection and 

surveillance program include periodic inspections of water-control structures to identify 

deviations in structural conditions due to age-related deterioration and degradation from 

the original design basis. When findings indicate that significant changes have occurred, 

the conditions are to be evaluated. This includes a technical assessment of the causes of 

distress or abnormal conditions, an evaluation of the behavior or movement of the 

structure, and recommendations for remedial or mitigating measures. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address the corrective actions.

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process.

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: Degradation of water-control structures has been detected, 

through RG 1.127 programs, at a number of nuclear power plants, and in some cases, it 
NUREG-1801, Rev. 1 XI S-24 September 2005

has required remedial action. No loss of intended functions has resulted from these 

occurrences. Therefore, it can be concluded that the inspections implemented in 

accordance with the guidance in RG 1.127 have been successful in detecting significant 

degradation before loss of intended function occurs.

NOTE: For dam inspection and maintenance, programs under the regulatory jurisdiction of 

FERC or the U.S. Army Corps of Engineers, continued through the period of extended 

operation, will be adequate for the purpose of aging management. For programs not 

falling under the regulatory jurisdiction of FERC or the U.S. Army Corps of Engineers, the 

staff will evaluate the effectiveness of the aging management program based on 

compatibility to the common practices of the FERC and Corps programs.

References

ACI Standard 349.3R-96, Evaluation of Existing Nuclear Safety-Related Concrete Structures,

American Concrete Institute.

NRC Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear 

Power Plants, Revision 1, U.S. Nuclear Regulatory Commission, March 1978. 
September 2005 XI S-25 NUREG-1801, Rev. 1

XI.S8 PROTECTIVE COATING MONITORING AND MAINTENANCE PROGRAM

Program Description

Proper maintenance of protective coatings inside containment (defined as Service Level I in 

Nuclear Regulatory Commission [NRC] Regulatory Guide [RG] 1.54, Rev. 1) is essential to 

ensure operability of post-accident safety systems that rely on water recycled through the 

containment sump/drain system. Degradation of coatings can lead to clogging of strainers, 

which reduces flow through the sump/drain system. This has been addressed in NRC Generic 

Letter (GL) 98-04.

Maintenance of Service Level I coatings applied to carbon steel surfaces inside containment 

(e.g., steel liner, steel containment shell, penetrations, hatches) also serves to prevent or 

minimize loss of material due to corrosion. Regulatory Position C4 in RG 1.54, Rev. 1, describes 

an acceptable technical basis for a Service Level I coatings monitoring and maintenance 

program that can be credited for managing the effects of corrosion for carbon steel elements 

inside containment. The attributes of an acceptable program are described below.

A comparable program for monitoring and maintaining protective coatings inside containment, 

developed in accordance with RG 1.54, Rev. 0 or the American National Standards Institute 

(ANSI) standards (since withdrawn) referenced in RG 1.54, Rev. 0, and coatings maintenance 

programs described in licensee responses to GL 98-04, is also acceptable as an aging 

management program (AMP) for license renewal.

Evaluation and Technical Basis

1. Scope of Program: The minimum scope of the program is Service Level I coatings, 

defined in RG 1.54, Rev 1, as follows: "Service Level I coatings are used in areas inside 

the reactor containment where the coating failure could adversely affect the operation of 

post-accident fluid systems and thereby impair safe shutdown."

2. Preventive Action: With respect to loss of material due to corrosion of carbon steel 

elements, this program is a preventive action.

3. Parameters Monitored or Inspected: Regulatory Position C4 in RG 1.54, Rev 1, states 

that "ASTM D 5163-96 provides guidelines that are acceptable to the NRC staff for 

establishing an in-service coatings monitoring program for Service Level I coating systems 

in operating nuclear power plants..." ASTM D 5163-96 has been superseded by ASTM D 

5163-05. ASTM D 5163-05, subparagraph 10.2, identifies the parameters monitored or 

inspected to be "any visible defects, such as blistering, cracking, flaking, peeling, rusting, 

and physical damage."

4. Detection of Aging Effects: ASTM D 5163-05, paragraph 6, defines the inspection 

frequency to be each refueling outage or during other major maintenance outages as 

needed. ASTM D 5163-05, paragraph 9, discusses the qualifications for inspection 

personnel, the inspection coordinator and the inspection results evaluator. 

ASTMD 5163-05, subparagraph 10.1, discusses development of the inspection plan and 

the inspection methods to be used. It states, "A general visual inspection shall be 

conducted on all readily accessible coated surfaces during a walk-through. After a walkthrough, or during the general visual inspection, thorough visual inspections shall be 

carried out on previously designated areas and on areas noted as deficient during the 
NUREG-1801, Rev. 1 XI S-26 September 2005

walk-through. A thorough visual inspection shall also be carried out on all coatings near 

sumps or screens associated with the Emergency Core Cooling System (ECCS)." This 

subparagraph also addresses field documentation of inspection results. ASTM D 5163-05, 

subparagraph 10.5, identifies instruments and equipment needed for inspection.

5. Monitoring and Trending: ASTM D 5163-05 identifies monitoring and trending activities 

in subparagraph 7.2, which specifies a pre-inspection review of the previous two 

monitoring reports, and in subparagraph 11.1.2, which specifies that the inspection report 

should prioritize repair areas as either needing repair during the same outage or 

postponed to future outages, but under surveillance in the interim period.

6. Acceptance Criteria: ASTM D 5163-05, subparagraphs 10.2.1 through 10.2.6, 10.3 and 

10.4, contain one acceptable method for characterization, documentation, and testing of 

defective or deficient coating surfaces. Additional ASTM and other recognized test 

methods are available for use in characterizing the severity of observed defects and 

deficiencies. The evaluation covers blistering, cracking, flaking, peeling, delamination, and 

rusting. ASTM D 5163-05, paragraph 12, addresses evaluation. It specifies that the 

inspection report is to be evaluated by the responsible evaluation personnel, who prepare 

a summary of findings and recommendations for future surveillance or repair, including an 

analysis of reasons or suspected reasons for failure. Repair work is prioritized as major or 

minor defective areas. A recommended corrective action plan is required for major 

defective areas, so that these areas can be repaired during the same outage, if 

appropriate.

7. Corrective Actions: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective 

actions.

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process. 

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: NRC Generic Letter 98-04 describes industry experience 

pertaining to coatings degradation inside containment and the consequential clogging of 

sump strainers. RG 1.54, Rev. 1, was issued in July 2000. Monitoring and maintenance of 

Service Level I coatings conducted in accordance with Regulatory Position C4 is expected 

to be an effective program for managing degradation of Service Level I coatings, and 

consequently an effective means to manage loss of material due to corrosion of carbon 

steel structural elements inside containment.

References

ASTM D 5163-05, Guide for Establishing Procedures to Monitor the Performance of Coating 

Service Level I Coating Systems in an Operating Nuclear Power Plant, American Society for 

Testing and Materials, 2005.
NUREG-1801, Rev. 1 XI S-28 September 2005

This Page Intentionally Left Blank
September 2005 XI S-27 NUREG-1801, Rev. 1

ASTM D 5163-96, Standard Guide for Establishing Procedures to Monitor the Performance of 

Safety Related Coatings in an Operating Nuclear Power Plant, American Society for Testing 

and Materials, 1996.

NRC Generic Letter 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,

U.S. Nuclear Regulatory Commission, July 14, 1998.

NRC Regulatory Guide 1.54, Rev. 0, Quality Assurance Requirements for Protective Coatings 

Applied to Water-Cooled Nuclear Power Plants, U.S. Nuclear Regulatory Commission, June 

1973.

NRC Regulatory Guide 1.54, Rev. 1, Service Level I, II, and III Protective Coatings Applied to 

Nuclear Power Plants, U.S. Nuclear Regulatory Commission, July 2000.
September 2005 XI E-1 NUREG-1801, Rev. 1

XI.E1 ELECTRICAL CABLES AND CONNECTIONS NOT SUBJECT TO 10 CFR 50.49 

ENVIRONMENTAL QUALIFICATION REQUIREMENTS

Program Description

In most areas within a nuclear power plant, the actual ambient environments (e.g., temperature, 

radiation, or moisture) are less severe than the plant design environment. However, in a limited 

number of localized areas, the actual environments may be more severe than the plant design 

environment for those areas. Conductor insulation materials used in cables and connections 

may degrade more rapidly than expected in these adverse localized environments. An adverse 

localized environment is a condition in a limited plant area that is significantly more severe than 

the specified service environment for the cable. An adverse variation in environment is 

significant if it could appreciably increase the rate of aging of a component or have an 

immediate adverse effect on operability.

The purpose of the aging management program described herein is to provide reasonable 

assurance that the intended functions of electrical cables and connections that are not subject 

to the environmental qualification requirements of 10 CFR 50.49 and are exposed to adverse 

localized environments caused by heat, radiation, or moisture will be maintained consistent with 

the current licensing basis through the period of extended operation. This program considers 

the technical information and guidance provided in NUREG/CR-5643, IEEE Std. P1205, 

SAND96-0344, and EPRI TR-109619.

The program described herein is written specifically to address cables and connections at plants 

whose configuration is such that most (if not all) cables and connections installed in adverse 

localized environments are accessible. This program, as described, can be thought of as a 

sampling program. Selected cables and connections from accessible areas (the inspection 

sample) are inspected and represent, with reasonable assurance, all cables and connections in 

the adverse localized environments. If an unacceptable condition or situation is identified for a 

cable or connection in the inspection sample, a determination is made as to whether the same 

condition or situation is applicable to other accessible or inaccessible cables or connections. As 

such, this program does not apply to plants in which most cables are inaccessible.

As stated in NUREG/CR-5643, "The major concern with cables is the performance of aged 

cable when it is exposed to accident conditions." The statement of considerations for the final 

license renewal rule (60 Fed. Reg. 22477) states, "The major concern is that failures of 

deteriorated cable systems (cables, connections, and penetrations) might be induced during 

accident conditions." Since they are not subject to the environmental qualification requirements 

of 10 CFR 50.49, the electrical cables and connections covered by this aging management 

program are either not exposed to harsh accident conditions or are not required to remain 

functional during or following an accident to which they are exposed.

Evaluation and Technical Basis

1. Scope of Program: This inspection program applies to accessible electrical cables and 

connections within the scope of license renewal that are installed in adverse localized 

environments caused by heat or radiation in the presence of oxygen.

2. Preventive Actions: This is an inspection program and no actions are taken as part of this 

program to prevent or mitigate aging degradation.
NUREG-1801, Rev. 1 XI E-2 September 2005 

3. Parameters Monitored/Inspected: A representative sample of accessible electrical cables 

and connections installed in adverse localized environments are visually inspected for cable 

and connection jacket surface anomalies. Technical basis for the sample selected is to be 

provided.

4. Detection of Aging Effects: Conductor insulation aging degradation from heat, radiation, 

or moisture in the presence of oxygen causes cable and connection jacket surface 

anomalies. A representative sample of accessible electrical cables and connections installed 

in adverse localized environments are visually inspected for cable and connection jacket 

surface anomalies, such as embrittlement, discoloration, cracking, or surface contamination. 

Accessible electrical cables and connections installed in adverse localized environments are 

visually inspected 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 inspection interval will provide two data points during a 20-year 

period, which can be used to characterize the degradation rate. The first inspection for 

license renewal is to be completed before the period of extended operation.

5. Monitoring and Trending: Trending actions are not included as part of this program 

because the ability to trend inspection results is limited. However, trending would provide 

additional information on the rate of degradation. 

6. Acceptance Criteria: 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. An unacceptable indication is defined as a 

noted condition or situation that, if left unmanaged, could lead to a loss of the intended 

function.

7. Corrective Actions: All unacceptable visual indications of cable and connection jacket 

surface anomalies are subject to an engineering evaluation. Such an evaluation is to 

consider the age and operating environment of the component, as well as the severity of the 

anomaly and whether such an anomaly has previously been correlated to degradation of 

conductor insulation or connections. Corrective actions may include, but are not limited to, 

testing, shielding or otherwise changing the environment, or relocation or replacement of the 

affected cable or connection. When an unacceptable condition or situation is identified, a 

determination is made as to whether the same condition or situation is applicable to other 

accessible or inaccessible cables or connections. As discussed in the appendix to this 

report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to 

address the corrective actions.

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process.

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: Operating experience has shown that adverse localized 

environments caused by heat or radiation for electrical cables and connections may exist 

next to or above (within three feet of) steam generators, pressurizers or hot process pipes, 

such as feedwater lines. These adverse localized environments have been found to cause 
September 2005 XI E-3 NUREG-1801, Rev. 1

degradation of the insulating materials on electrical cables and connections that is visually 

observable, such as color changes or surface cracking. These visual indications can be 

used as indicators of degradation.

References

EPRI TR-109619, Guideline for the Management of Adverse Localized Equipment 

Environments, Electric Power Research Institute, Palo Alto, CA, June 1999.

IEEE Std. P1205-2000, IEEE Guide for Assessing, Monitoring and Mitigating Aging Effects on 

Class 1E Equipment Used in Nuclear Power Generating Stations.

NUREG/CR-5643, Insights Gained From Aging Research, U. S. Nuclear Regulatory 

Commission, March 1992.

SAND96-0344, Aging Management Guideline for Commercial Nuclear Power Plants - Electrical 

Cable and Terminations, prepared by Sandia National Laboratories for the U.S. Department 

of Energy, September 1996.
NUREG-1801, Rev. 1 XI E-4 September 2005 

XI.E2 ELECTRICAL CABLES AND CONNECTIONS NOT SUBJECT TO 10 CFR 50.49 

ENVIRONMENTAL QUALIFICATION REQUIREMENTS USED IN 

INSTRUMENTATION CIRCUITS 

Program Description

In most areas within a nuclear power plant, the actual ambient environments (e.g., temperature, 

radiation, or moisture) are less severe than the plant design environment. However, in a limited 

number of localized areas, the actual environments may be more severe than the design 

environment. Conductor insulation materials used in electrical cables may degrade more rapidly 

in adverse localized environments. An adverse localized environment is significantly more 

severe than the specified service environment for the cable. An adverse variation in 

environment is significant if it could appreciably increase the rate of aging of a component or 

have an immediate adverse effect on operability.

Exposure of electrical cables to adverse localized environments caused by heat, radiation, or 

moisture can result in reduced insulation resistance (IR). Reduced IR causes an increase in 

leakage currents between conductors and from individual conductors to ground. A reduction in 

IR is a concern for circuits with sensitive, high voltage, low-level signals such as radiation 

monitoring and nuclear instrumentation circuits because a reduced IR may contribute to signal 

inaccuracies. 

The purpose of the aging management program described herein is to provide reasonable 

assurance that the intended functions of electrical cables that are not subject to the 

environmental qualification requirements of 10 CFR 50.49 and are used in instrumentation 

circuits with sensitive, high voltage, low-level signals exposed to adverse localized 

environments caused by heat, radiation or moisture will be maintained consistent with the 

current licensing basis through the period of extended operation. This program considers the 

technical information and guidance provided in NUREG/CR-5643, IEEE Std. P1205, SAND96-

0344, and EPRI TR-109619.

In this aging management program, either of two methods can be used to identify the existence 

of aging degradation. In the first method, calibration results or findings of surveillance testing 

programs are evaluated to identify the existence of cable aging degradation. In the second 

method, direct testing of the cable system is performed.

This program applies to high-range-radiation and neutron flux monitoring instrumentation cables 

in addition to other cables used in high voltage, low-level signal applications that are sensitive to 

reduction in IR. For these cables, GALL XI.E1 does not apply.

As stated in NUREG/CR-5643, "The major concern with cables is the performance of aged 

cable when it is exposed to accident conditions." The statement of considerations for the final 

license renewal rule (60 Fed. Reg. 22477) states, "The major concern is that failures of 

deteriorated cable systems (cables, connections, and penetrations) might be induced during 

accident conditions." Since they are not subject to the environmental qualification requirements 

of 10 CFR 50.49, the electrical cables covered by this aging management program are either 

not exposed to harsh accident conditions or are not required to remain functional during or 

following an accident to which they are exposed.
September 2005 XI E-5 NUREG-1801, Rev. 1

Evaluation and Technical Basis

1. Scope of Program: This program applies to electrical cables and connections (cable 

system) used in circuits with sensitive, high voltage, low-level signals such as radiation 

monitoring and nuclear instrumentation that are subject to aging management review.

2. Preventive Actions: No actions are taken as part of this program to prevent or mitigate 

aging degradation.

3. Parameters Monitored/Inspected: The parameters monitored are determined from the 

specific calibration, surveillances or testing performed and are based on the specific 

instrumentation circuit under surveillance or being calibrated, as documented in plant 

procedures.

4. Detection of Aging Effects: Review of calibration results or findings of surveillance 

programs can provide an indication of the existence of aging effects based on acceptance 

criteria related to instrumentation circuit performance. By reviewing the results obtained 

during normal calibration or surveillances, an applicant may detect severe aging degradation 

prior to the loss of the cable and connection intended function. The first reviews will be 

completed before the period of extended operation and at least every ten years thereafter. 

All calibration or surveillance results that fail to meet acceptance criteria will be reviewed for 

aging effects when the results are available.

In cases where a calibration or surveillance program does not include the cabling system in 

the testing circuit, or as an alternative to the review of calibration results described above, 

the applicant will perform cable system testing. A proven cable system test for detecting 

deterioration of the insulation system (such as insulation resistance tests, time domain 

reflectometry tests, or other testing judged to be effective in determining cable insulation 

condition as justified in the application) will be performed. The test frequency of these cables 

shall be determined by the applicant based on engineering evaluation, but the test 

frequency shall be at least once every ten years. The first test shall be completed before 

the period of extended operation.

5. 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. 

However, test results that are trendable provide additional information on the rate of 

degradation.

6. Acceptance Criteria: Calibration results or findings of surveillance and cable system 

testing results are to be within the acceptance criteria, as set out in procedures.

7. Corrective Actions: Corrective actions such as recalibration and circuit trouble-shooting 

are implemented when calibration or surveillance results or findings of surveillances do not 

meet the acceptance criteria. An engineering evaluation is performed when the test 

acceptance criteria are not met in order to ensure that the intended functions of the electrical 

cable system can be maintained consistent with the current licensing basis. Such an 

evaluation is to consider the significance of the test results, the operability of the component, 

the reportability of the event, the extent of the concern, the potential root causes for not 

meeting the test acceptance criteria, the corrective actions required, and likelihood of 
NUREG-1801, Rev. 1 XI E-6 September 2005 

recurrence. As discussed in the appendix to this report, the staff finds the requirements of 

10 CFR Part 50, Appendix B, acceptable to address the corrective actions.

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address confirmation process.

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: Operating experience has identified a case where a change in 

temperature across a high range radiation monitor cable in containment resulted in 

substantial change in the reading of the monitor. Changes in instrument calibration can be 

caused by degradation of the circuit cable and are a possible indication of electrical cable 

degradation.

The vast majority of site specific and industry wide operating experience regarding neutron 

flux instrumentation circuits is related to cable/connector issues inside of containment near 

the reactor vessel.

References

EPRI TR-109619, Guideline for the Management of Adverse Localized Equipment 

Environments, Electric Power Research Institute, Palo Alto, CA, June 1999.

IEEE Std. P1205-2000, IEEE Guide for Assessing, Monitoring and Mitigating Aging Effects on 

Class 1E Equipment Used in Nuclear Power Generating Stations.

NUREG/CR-5643, Insights Gained From Aging Research, U. S. Nuclear Regulatory 

Commission, March 1992.

SAND96-0344, Aging Management Guideline for Commercial Nuclear Power Plants - Electrical 

Cable and Terminations, prepared by Sandia National Laboratories for the U.S. Department 

of Energy, September 1996. 

NRC Information Notice 97-45, Environmental Qualification Deficiency for Cables and 

Containment Penetration Pigtails, U. S, Nuclear Regulatory Commission, July 2, 1997 and 

Supplement 1, February 17, 1998.
September 2005 XI E-7 NUREG-1801, Rev. 1

XI.E3 INACCESSIBLE MEDIUM-VOLTAGE CABLES NOT SUBJECT TO 10 CFR 50.49 

ENVIRONMENTAL QUALIFICATION REQUIREMENTS 

Program Description

Most electrical cables in nuclear power plants are located in dry environments. However, some 

cables may be exposed to condensation and wetting in inaccessible locations, such as conduits, 

cable trenches, cable troughs, duct banks, underground vaults or direct buried installations. 

When an energized medium-voltage cable (2 kV to 35 kV) 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 purpose of the aging management program described herein is to provide reasonable 

assurance that the intended functions of inaccessible medium-voltage cables that are not 

subject to the environmental qualification requirements of 10 CFR 50.49 and are exposed to 

adverse localized environments caused by moisture while energized will be maintained 

consistent with the current licensing basis through the period of extended operation. An adverse 

localized environment is a condition in a limited plant area that is significantly more severe than 

the specified service environment for the cable. An adverse variation in environment is 

significant if it could appreciably increase the rate of aging of a component or have an 

immediate adverse effect on operability. This program considers the technical information and 

guidance provided in NUREG/CR-5643, IEEE Std. P1205, SAND96-0344, and EPRI TR109619.

In this aging management program periodic actions are taken to prevent cables from being 

exposed to significant moisture, such as inspecting for water collection in cable manholes, and 

draining water, as needed. The above actions are not sufficient to assure that water is not 

trapped elsewhere in the raceways. For example, if duct bank conduit has low points in the 

routing, there could be potential for long-term submergence at these low points. In addition, 

concrete raceways may crack due to soil settling over a long period of time and manhole covers 

may not be watertight. Additionally, in certain areas, the water table is high in seasonal cycles 

and therefore, the raceways may get refilled soon after purging. Furthermore, potential 

uncertainties exist with water trees even when duct banks are sloped with the intention to 

minimize water accumulation. Experience has shown that insulation degradation may occur if 

the cables are exposed to 100 percent relative humidity. The above periodic actions are 

necessary to minimize the potential for insulation degradation. In addition to above periodic 

actions, in-scope, medium-voltage cables exposed to significant moisture and significant voltage 

are tested to provide an indication of the condition of the conductor insulation. The specific type 

of test performed will be determined prior to the initial test, and is to be a proven test for 

detecting deterioration of the insulation system due to wetting, such as power factor, partial 

discharge, or polarization index, as described in EPRI TR-103834-P1-2, or other testing that is 

state-of-the-art at the time the test is performed.

As stated in NUREG/CR-5643, "The major concern with cables is the performance of aged 

cable when it is exposed to accident conditions." The statement of considerations for the final 

license renewal rule (60 Fed. Reg. 22477) states, "The major concern is that failures of 

deteriorated cable systems (cables, connections, and penetrations) might be induced during 

accident conditions." Since they are not subject to the environmental qualification requirements 

of 10 CFR 50.49, the electrical cables covered by this aging management program are either 

not exposed to harsh accident conditions or are not required to remain functional during or 

following an accident to which they are exposed.
NUREG-1801, Rev. 1 XI E-8 September 2005 

Evaluation and Technical Basis

1. Scope of Program: This program applies to inaccessible (e.g., in conduit or direct buried) 

medium-voltage cables within the scope of license renewal that are exposed to significant 

moisture simultaneously with significant voltage. Significant 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 twenty-five 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 significant for medium-voltage cables that are designed for 

these conditions (e.g., continuous wetting and continuous energization is not significant for 

submarine cables).

2. Preventive Actions: Periodic actions are taken to prevent cables from being exposed to 

significant moisture, such as inspecting for water collection in cable manholes, and draining 

water, as needed.

3. Parameters Monitored/Inspected: In-scope, medium-voltage cables exposed to 

significant moisture and significant voltage are tested to provide an indication of the 

condition of the conductor insulation. The specific type of test performed will be determined 

prior to the initial test, and is to be a proven test for detecting deterioration of the insulation 

system due to wetting, such as power factor, partial discharge, or polarization index, as 

described in EPRI TR-103834-P1-2, or other testing that is state-of-the-art at the time the 

test is performed.

4. Detection of Aging Effects: Medium-voltage cables exposed to significant moisture and 

significant voltage that are within the scope of this program 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 testing interval

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 inspection for water collection should be performed based on actual plant experience 

with water accumulation in the manhole. However, the inspection frequency should be at 

least once every two years. The first inspection for license renewal is to be completed 

before the period of extended operation.

5. Monitoring and Trending: Trending actions are not included as part of this program 

because the ability to trend results is dependent on the specific type of method chosen. 

However, results that are trendable provide additional information on the rate of 

degradation.

6. Acceptance Criteria: The acceptance criteria for each test is defined by the specific type 

of test performed and the specific cable tested. 

7. Corrective Actions: An engineering evaluation is performed when the test acceptance 

criteria are not met in order to ensure that the intended functions of the electrical cables can 

be maintained consistent with the current licensing basis. Such an evaluation is to consider 

the significance of the test results, the operability of the component, the reportability of the 
September 2005 XI E-9 NUREG-1801, Rev. 1

event, the extent of the concern, the potential root causes for not meeting the test 

acceptance criteria, the corrective actions required, and the likelihood of recurrence. When 

an unacceptable condition or situation is identified, a determination is made as to whether 

the same condition or situation is applicable to other inaccessible, in-scope, medium-voltage 

cables. As discussed in the appendix to this report, the staff finds the requirements of 

10 CFR Part 50, Appendix B, acceptable to address the corrective actions.

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process.

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: 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. Water 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, lessons 

learned can be used to adjust the program, as needed.

References

EPRI TR-103834-P1-2, Effects of Moisture on the Life of Power Plant Cables, Electric Power 

Research Institute, Palo Alto, CA, August 1994.

EPRI TR-109619, Guideline for the Management of Adverse Localized Equipment 

Environments, Electric Power Research Institute, Palo Alto, CA, June 1999.

IEEE Std. P1205-2000, IEEE Guide for Assessing, Monitoring and Mitigating Aging Effects on 

Class 1E Equipment Used in Nuclear Power Generating Stations.

NUREG/CR-5643, Insights Gained From Aging Research, U. S. Nuclear Regulatory 

Commission, March 1992.

SAND96-0344, Aging Management Guideline for Commercial Nuclear Power Plants - Electrical 

Cable and Terminations, prepared by Sandia National Laboratories for the U.S. Department 

of Energy, September 1996.
NUREG-1801, Rev. 1 XI E-10 September 2005 

XI.E4 METAL ENCLOSED BUS

Program Description

Metal enclosed buses (MEBs) are electrical buses installed on electrically insulated supports 

and are constructed with each phase conductor enclosed in a separate metal enclosure or all 

conductors enclosed in a common metal enclosure (non-segregated bus). The conductors are 

adequately separated and insulated from ground by insulating supports. Also, the conductors in 

the non-segregated bus are insulated throughout the conductor length to reduce corona and 

electrical tracking. The MEBs are used in power systems to connect various elements in 

electric power circuits such as switchgear, transformers, main generator, and diesel generators.

Industry operating experience indicates that failures of MEBs have been caused by cracked 

insulation and moisture or debris buildup internal to the bus duct housing. Failures of MEBs 

have been attributed to the cracking of bus bar insulation (bus sleeving), combined with the 

accumulation of moisture or debris in the bus bar enclosure. Cracked insulation has resulted 

from high ambient temperature and contamination from bus bar joint compound. Cracked 

insulation in the presence of moisture or debris has provided phase-to-phase or phase-toground electrical tracking paths, which has resulted in catastrophic failure of the buses. Bus 

failure has led to loss of power to electrical loads connected to the buses, causing subsequent 

reactor trips, and initiating unnecessary challenges to plant systems.

Buses in MEBs may experience loosening of bolted connections resulting from the repeated 

cycling of connected loads. This phenomenon can occur in heavily loaded circuits (i.e., those 

exposed to appreciable ohmic heating). SAND 96-0344 identified instances of termination 

loosening at several plants due to thermal cycling and NRC Information Notice 2000-14 

identified torque relaxation of splice plate connecting bolts as one potential cause of a MEB 

fault.

The purpose of the aging management program is to provide an inspection of MEBs. In this 

aging management program, bolted connections at sample sections of the buses in the MEBs 

will be checked for loose connection. This activity also includes internal visual inspection of the 

MEBs to identify age related degradation of insulating and metallic components and 

moisture/debris intrusion.

Evaluation and Technical Basis

1. Scope of Program: This program applies to MEBs within the scope of license renewal.

2. Preventive Actions: This is an inspection program and no actions are taken as part of this 

program to prevent or mitigate aging degradation.

3. Parameters Monitored/Inspected: A sample of accessible bolted connections will be 

checked for loose connection. Alternatively, bolted connections covered with heat shrink 

tape, sleeving, insulating boots, etc., may be visually inspected for insulation material 

surface anomalies. This program provides for the inspection of the internal portion of the 

MEBs for cracks, corrosion, foreign debris, excessive dust buildup, and evidence of water 

intrusion. The bus insulation will be inspected for signs of embrittlement, cracking, melting, 

swelling, or discoloration, which may indicate overheating or aging degradation. The internal 

bus supports will be inspected for structural integrity and signs of cracks.
September 2005 XI E-11 NUREG-1801, Rev. 1

4. Detection of Aging Effects: A sample of accessible bolted connections will be checked for 

loose connection by using thermography or by measuring connection resistance using a low 

range ohmmeter. MEB internal surfaces will be visually inspected for aging degradation of 

insulating material and for foreign debris and excessive dust buildup, and evidence of 

moisture intrusion. Bus insulation will be visually inspected for signs of embrittlement, 

cracking, melting, swelling, or discoloration, which may indicate overheating or aging 

degradation. Internal bus supports will be visually inspected for structural integrity and signs 

of cracks. This program will be completed before the period of extended operation and every 

10 years thereafter provided visual inspection is not used to check bolted connections. A 10

year inspection interval will provide two data points during a 20-year period, which can be 

used to characterize the degradation rate. This is an adequate period to preclude failures of 

the MEBs since experience has shown that aging degradation is a slow process. 

As an alternative to thermography or measuring connection resistance of bolted 

connections, for the accessible bolted connections that are covered with heat shrink tape, 

sleeving, insulating boots, etc., the applicant may use visual inspection of insulation material 

to detect surface anomalies, such as discoloration, cracking, chipping or surface 

contamination. When this alternative visual inspection is used to check bolted connections, 

the first inspection will be completed before the period of extended operation and every five 

years thereafter.

5. Monitoring and Trending: Trending actions are not included as part of this program 

because the ability to trend inspection results is limited. However, results that are trendable

provide additional information on the rate of degradation.

6. Acceptance Criteria: Bolted connections need to be below the maximum allowed 

temperature for the application when thermography is used or a low resistance value 

appropriate for the application when resistance measurement is used. MEBs are to be free 

from unacceptable visual indications of surface anomalies, which suggest that conductor 

insulation degradation exists. In addition no unacceptable indication of corrosion, cracks, 

foreign debris, excessive dust buildup or evidence of moisture intrusion is to exist. An 

unacceptable indication is defined as a noted condition or situation that, if left unmanaged, 

could lead to a loss of intended function.

When the visual inspection alternative for bolted connections is used, the absence of 

discoloration, cracking, chipping or surface contamination will provide positive indication that 

the bolted connections are not loose. 

7. Corrective Actions: Further investigation and evaluation are performed when the 

acceptance criteria are not met. Corrective actions may include but are not limited to 

cleaning, drying, increased inspection frequency, replacement, or repair of the affected MEB 

components. If an unacceptable condition or situation is identified, a determination is made 

as to whether the same condition or situation is applicable to other accessible or 

inaccessible MEBs. As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions.

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process.
NUREG-1801, Rev. 1 XI E-12 September 2005 

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating experience: Industry experience has shown that failures have occurred on 

MEBs caused by cracked insulation and moisture or debris buildup internal to the MEB. 

Experience has also shown that bus connections in the MEBs exposed to appreciable ohmic 

heating during operation may experience loosening due to repeated cycling of connected 

loads.

References

IEEE Std. P1205-2000, IEEE Guide for Assessing, Monitoring and Mitigating Aging Effects on 

Class 1E Equipment Used in Nuclear Power Generating Stations.

SAND 96-0344, Aging Management Guideline for Commercial Nuclear Power Plants –

Electrical Cable and Terminations, prepared by Sandia National Laboratories for the U.S. 

Department of Energy, September 1996.

EPRI TR-109619, Guideline for the Management of Adverse Localized Equipment 

Environments, Electric Power Research Institute, Palo Alto, CA, June 1999.

Information Notice 89-64, “Electrical Bus Bar Failures.”

Information Notice 98-36, “Inadequate or Poorly Controlled, Non-Safety-Related Maintenance 

Activities Unnecessary Challenged Safety Systems.”

Information Notice 2000-14, “Non-Vital Bus Fault Leads to Fire and Loss of Offsite Power.”
September 2005 XI E-13 NUREG-1801, Rev. 1

XI.E5 FUSE HOLDERS 

Program Description

Fuse holders (fuse blocks) are classified as a specialized type of terminal block because of the 

similarity in fuse holder design and construction to that of a terminal block. Fuse holders are 

typically constructed of blocks of rigid insulating material, such as phenolic resins. Metallic 

clamps (clips) are attached to the blocks to hold each end of the fuse. The clamps, which are 

typically made of copper, can be spring-loaded clips that allow the fuse ferrules or blades to slip 

in, or they can be bolt lugs, to which the fuse ends are bolted.

GALL XI.E1, “Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements,” will manage the aging of insulating material but not the metallic 

clamps of the fuse holders. The aging management program for fuse holders (metallic clamps) 

needs to account for the following aging stressors, if applicable: fatigue, mechanical stress, 

vibration, chemical contamination, and corrosion. GALL XI.E1 is based on only a visual 

inspection of accessible cables and connections. Visual inspection is not sufficient to detect the 

aging effects from fatigue, mechanical stress, vibration, or corrosion on the metallic clamps of 

the fuse holder.

Fuse holders that are within the scope of license renewal should be tested to provide an 

indication of the condition of the metallic clamps of the fuse holders. 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 metallic clamps of the fuse holders, such as thermography, contact resistance 

testing, or other appropriate testing justified in the application.

As stated in NUREG-1760, “Aging Assessment of Safety-Related Fuses Used in Low and 

Medium-Voltage Applications in Nuclear Power Plants,” fuse holders experience a number of 

age-related failures. The major concern is that failures of a deteriorated cable system (cables, 

connections including fuse holders, and penetrations) might be induced during accident 

conditions. Since they are not subject to the environmental qualification requirements of 

10 CFR 50.49, an aging management program is required to manage the aging effects. This 

program will ensure that fuse holders will perform their intended function for the period of 

extended operation.

Evaluation and Technical Basis

1. Scope of Program: This program applies to fuse holders located outside of active devices 

and are considered susceptible to aging effects. Fuse holders inside an active device (e.g., 

switchgears, power supplies, power inverters, battery chargers, and circuit boards) are not 

within the scope of this program.

2. Preventive Actions: No actions are taken as part of this program to prevent or mitigate 

aging degradation.

3. Parameters Monitored/Inspected: This program will focus on the metallic clamp portion of 

the fuse holder. The monitoring includes thermal fatigue in the form of high resistance 

caused by ohmic heating, thermal cycling or electrical transients, mechanical fatigue caused 

by frequent removal/replacement of the fuse or vibration, chemical contamination, corrosion, 

and oxidation.
NUREG-1801, Rev. 1 XI E-14 September 2005 

4. Detection of Aging Effects: Fuse holders within the scope of license renewal will be tested 

at least once every 10 years. Testing may include thermography, contact resistance testing, 

or other appropriate testing methods. This is an adequate period to preclude failures of the 

fuse holders since experience has shown that aging degradation is a slow process. A 10-

year testing interval 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.

5. 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. 

However, results that are trendable provide additional information on the rate of 

degradation.

6. Acceptance Criteria: The acceptance criteria for each test are defined by the specific type 

of test performed and the specific type of fuse holder tested.

7. Corrective Action: An engineering evaluation is performed when the test acceptance 

criteria are not met in order to ensure that the intended functions of the fuse holders can be 

maintained consistent with the current licensing basis. Such an evaluation is to consider the 

significance of the test results, the operability of the component, the reportability of the 

event, the extent of the concern, the potential root causes for not meeting the test 

acceptance criteria, the corrective action necessary, and the likelihood of recurrence. As 

discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, 

Appendix B, acceptable to address the corrective actions.

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process.

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: Operating experience has shown that loosening of fuse holders and 

corrosion of fuse clips are aging mechanisms that, if left unmanaged, can lead to a loss of 

electrical continuity function.

References

NUREG-1760, “Aging Assessment of Safety-Related Fuses Used in Low- and Medium-Voltage 

Applications in Nuclear Power Plants.”

IEEE standard 1205-2000, “IEEE Guide for Assessing, Monitoring, and Mitigating Aging Effects 

on Class 1E Equipment Used in Nuclear Power Generating Stations.”

NRC Information Notice 91-78, “Status Indication of Control Power for Circuit Breakers Used in 

Safety-Related application.”

NRC Information Notice 87-42, “Diesel Generator Fuse Contacts.”

NRC Information Notice 86-87, “Loss of Offsite Power Upon an Automatic Bus Transfer.”
September 2005 XI E-15 NUREG-1801, Rev. 1

XI.E6 ELECTRICAL CABLE CONNECTIONS NOT SUBJECT TO 10 CFR 50.49

ENVIRONMENTAL QUALIFICATION REQUIREMENTS 

Program Description

Cable connections are used to connect cable conductors to other cables or electrical devices. 

Connections associated with cables within the scope of license renewal are part of this program. 

The most common types of connections used in nuclear power plants are splices (butt or 

bolted), crimp-type ring lugs, connectors, and terminal blocks. Most connections involve 

insulating material and metallic parts. This aging management program for electrical cable 

connections (metallic parts) account for the following aging stressors: thermal cycling, ohmic 

heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation. 

GALL XI.E1, “Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements,” manages the aging of insulating material but not the metallic parts 

of the electrical connections. GALL XI.E1 is based on only a visual inspection of accessible 

cables and connections. Visual inspection is not sufficient to detect the aging effects from 

thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, 

corrosion, and oxidation on the metallic parts of cable connections.

Circuits exposed to appreciable ohmic or ambient heating during operation may experience 

loosening related to repeated cycling of connected loads or of the ambient temperature 

environment. Different materials used in various cable system components can produce 

situations where stresses existing between these components change with repeated thermal 

cycling. For example, under loaded conditions, appreciable ohmic heating may raise the 

temperature of a compression termination and cable conductor well above the ambient 

temperature, thereby causing thermal expansion of both components. Different thermal 

expansion coefficients may alter mechanical stresses between the components so that the 

termination may tighten on the conductor. When the load or current is reduced, the affected 

components cool and contract. Repeated cycling in this fashion can produce loosening of the 

termination under ambient conditions, and may lead to high electrical resistance joints or 

eventual separation to compression-type terminations. Threaded connectors, splices, and 

terminal blocks may loosen if subjected to significant thermally induced stress and cycling. 

Cable connections within the scope of license renewal should be tested to provide an indication 

of the integrity of the cable connections. The specific type of test performed will be determined 

prior to the initial test, and is to be a proven test for detecting loose connections, such as 

thermography, contact resistance testing, or other appropriate testing justified in the application.

This program, as described, can be thought of as a sampling program. The following factors 

are considered for sampling: application (high, medium and low voltage), circuit loading, and 

location (high temperature, high humidity, vibration, etc.). The technical basis for the sample 

selections is documented. If an unacceptable condition or situation is identified in the selected 

sample, a determination is made as to whether the same condition or situation is applicable to 

other connections not tested. 

SAND 96-0344, “Aging Management Guidelines for Electrical Cable and Terminations,” 

indicated loose terminations were identified by several plants. The major concern is that failures 

of a deteriorated cable system (cables, connections including fuse holders, and penetrations) 

might be induced during accident conditions. Since the connections are not subject to the 

environmental qualification requirements of 10 CFR 50.49, an aging management program is 
NUREG-1801, Rev. 1 XI E-16 September 2005 

required to manage the aging effects. This program will ensure that electrical cable connections 

will perform their intended function for the period of extended operation.

Evaluation and Technical Basis

1. Scope of Program: Connections associated with cables in scope of license renewal are 

part of this program, regardless of their association with active or passive components. 

2. Preventive Actions: No actions are taken as part of this program to prevent or mitigate 

aging degradation.

3. Parameters Monitored/Inspected: This program will focus on the metallic parts of the 

connection. The monitoring includes loosening of bolted connections due to thermal cycling, 

ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and 

oxidation. A representative sample of electrical cable connections is tested. The following 

factors are to be considered for sampling: application (high, medium and low voltage), circuit 

loading, and location (high temperature, high humidity, vibration, etc.). The technical basis 

for the sample selected is to be documented.

4. Detection of Aging Effects: Electrical connections within the scope of license renewal will 

be tested at least once every 10 years. Testing may include thermography, contact 

resistance testing, or other appropriate testing methods. This is an adequate period to 

preclude failures of the electrical connections since experience has shown that aging 

degradation is a slow process. A 10-year testing interval 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.

5. 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. 

However, test results that are trendable provide additional information on the rate of 

degradation.

6. Acceptance Criteria: The acceptance criteria for each test are defined by the specific type 

of test performed and the specific type of cable connections tested.

7. Corrective Actions: An engineering evaluation is performed when the test acceptance 

criteria are not met in order to ensure that the intended functions of the cable connections 

can be maintained consistent with the current licensing basis. Such an evaluation is to 

consider the significance of the test results, the operability of the component, the 

reportability of the event, the extent of the concern, the potential root causes for not meeting 

the test acceptance criteria, the corrective action necessary, and the likelihood of 

recurrence. When an unacceptable condition or situation is identified, a determination is 

made on whether the same condition or situation is applicable to other in-scope cable 

connections not tested. As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions.

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process.
September 2005 XI E-17 NUREG-1801, Rev. 1

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: Operating experience has shown that loosening of connections and 

corrosion of connections are aging mechanisms that, if left unmanaged, could lead to a loss 

of electrical continuity and potential arcing or fire.

References

EPRI TR-109619, Guideline for the Management of Adverse Localized Equipment 

Environments, Electric Power Research Institute, Palo Alto, CA, June 1999.

IEEE Std. P1205-2000, IEEE Guide for Assessing, Monitoring and Mitigating Aging Effects on 

Class 1E Equipment Used in Nuclear Power Generating Stations.

NUREG/CR-5643, Insights Gained From Aging Research, U. S. Nuclear Regulatory

Commission, March 1992.

SAND96-0344, Aging Management Guideline for Commercial Nuclear Power Plants – Electrical 

Cable and Terminations, prepared by Sandia National Laboratories for the U.S. Department 

of Energy, September 1996.

EPRI TR - 104213, Bolted Joint Maintenance & Application Guide, Electric Power Research 

Institute, Palo Alto, CA, December 1995.
NUREG-1801, Rev. 1 XI E-18 September 2005 

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September 2005 A-i NUREG-1801, Rev. 1

APPENDIX

QUALITY ASSURANCE FOR

AGING MANAGEMENT PROGRAMS 
NUREG-1801, Rev. 1 A-ii September 2005

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September 2005 A-1 NUREG-1801, Rev. 1

QUALITY ASSURANCE FOR AGING MANAGEMENT PROGRAMS

The license renewal applicant must demonstrate that the effects of aging on structures and 

components subject to an aging management review (AMR) will be adequately managed to 

ensure that their intended functions will be maintained consistent with the current licensing basis 

(CLB) of the facility for the period of extended operation. Therefore, those aspects of the AMR 

process that affect the quality of safety-related structures, systems, and components are subject 

to the quality assurance (QA) requirements of Appendix B to 10 CFR Part 50. For non-safetyrelated structures and components subject to an AMR, the existing 10 CFR Part 50, 

Appendix B, QA program may be used to address the elements of corrective actions, 

confirmation process, and administrative controls on the following bases: 

• Criterion XVI of 10 CFR Part 50, Appendix B, requires that measures be established to 

ensure that conditions adverse to quality, such as failures, malfunctions, deviations, 

defective material and equipment, and nonconformances, are promptly identified and 

corrected. In the case of significant conditions adverse to quality, measures must be 

implemented to ensure that the cause of the condition is determined and that corrective 

action is taken to preclude repetition. In addition, the cause of the significant condition 

adverse to quality and the corrective action implemented must be documented and reported 

to appropriate levels of management.

• To preclude repetition of significant conditions adverse to quality, follow-up actions need to 

be taken to verify effective implementation of the proposed corrective action. This 

verification comprises the confirmation process element for aging management programs for 

license renewal. For example, in managing internal corrosion of piping, a mitigation program 

(water chemistry) may be used to minimize susceptibility to corrosion. However, it may also 

be necessary to have a condition monitoring program (ultrasonic inspection) to verify that 

corrosion is indeed insignificant. When corrective actions are necessary for significant 

conditions, follow-up activities are to confirm that the corrective actions implemented are 

effective in preventing recurrence.

• 10 CFR 50.34(b)(6)(i) requires that nuclear power plant license applicants include in the final 

safety analysis report information on the applicant’s organizational structure, allocations or 

responsibilities and authorities, and personnel qualification requirements. 10 CFR 

50.34(b)(6)(ii) also notes that Appendix B to 10 CFR Part 50 sets forth the requirements for 

managerial and administrative controls used to ensure safe operation. Pursuant to 10 CFR 

50.36(c)(5), administrative controls are the provisions related to organization and 

management, procedures, record keeping, review and audit, and reporting necessary to 

ensure operation of the facility in a safe manner. Programs that are consistent with the 

requirements of 10 CFR Part 50, Appendix B, also satisfy the administrative controls 

element necessary for aging management programs (AMPs) for license renewal.

Notwithstanding the suitability of its provisions to address quality-related aspects of the AMR 

process for license renewal, 10 CFR Part 50, Appendix B, covers only safety-related structures, 

systems, and components. Therefore, absent a commitment by the applicant to expand the 

scope of its 10 CFR Part 50, Appendix B, QA program to include non-safety-related structures 

and components subject to an AMR for license renewal, the AMPs applicable to non-safetyrelated structures and components are to include alternative means to address corrective 

actions, confirmation process, and administrative controls. Such alternate means would be 

subject to review by NRC on a case-by-case basis.
NUREG-1801, Rev. 1 A-2 September 2005

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