Generic Aging Lessons

Learned (GALL) Report

Final Report 

Office of Nuclear Reactor Regulation

NUREG-1801, Rev. 2
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Generic Aging Lessons

Learned (GALL) Report

Final Report 

Manuscript Completed: December 2010 

Date Published: December 2010

Office of Nuclear Reactor Regulation

NUREG-1801, Rev. 2
 
December 2010 iii NUREG-1801, Rev. 2

ABSTRACT

NUREG-1801, “The Generic Aging Lessons Learned (GALL) Report” (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 period of extended operation. The evaluation results 

documented in the GALL Report indicate that many of the existing programs are adequate to 

manage the aging effects for 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. The GALL Report should be 

treated as an approved topical report. However, if an applicant takes credit for a program in the 

GALL Report, it is incumbent on the applicant to ensure that the conditions and operating 

experience at the plant are bounded by the conditions and operating experience for which the 

GALL Report program was evaluated. If these bounding conditions are not met, it is incumbent 

on the applicant to address the additional effects of aging and augment the GALL Report aging 

management program(s) as appropriate. The staff will verify that the applicant’s programs are 

consistent with those described in the GALL Report and/or with plant conditions and operating 

experience during the performance of an aging management program audit and review. The 

focus of the balance of the staff’s review of a license renewal application is on those programs 

that an applicant has enhanced to be consistent with the GALL Report, those programs for 

which the applicant has taken an exception to the program described in the GALL Report, and 

plant-specific programs not described in the GALL Report. The information in the GALL Report 

has been incorporated into the NUREG-1800, “Standard Review Plan for Review of License 

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

efficiency of the license renewal process.

December 2010 v NUREG-1801, Rev. 2

TABLE OF CONTENTS

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

List of Contributors ...................................................................................................................xi

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

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

Background................................................................................................................................. 2 

Overview of the GALL Report Evaluation Process.................................................................. 5 

Application of the GALL Report ................................................................................................ 8 

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 Bldg., PWR Shield 

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

A2 Group 2 Structures (BWR Reactor Bldg. 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 
NUREG-1801, Rev. 2 vi December 2010

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 

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 
December 2010 vii NUREG-1801, Rev. 2

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 

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 

E5 Waste Water Systems...................................................................................VII E5-1 

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 
NUREG-1801, Rev. 2 viii December 2010

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

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

A Introduction.......................................................................................................... IX-1 

B Structures and Components................................................................................ IX-2 

C Materials.............................................................................................................. IX-7 

D Environment ...................................................................................................... IX-14 

E Aging Effects ..................................................................................................... IX-22 

F Significant Aging Mechanisms .......................................................................... IX-27

G References ........................................................................................................ IX-41 

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

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

X.M1 Fatigue Monitoring.......................................................................................... X M1-1 

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

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

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

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

IWD........................................................................................................... XI M1-1 

XI.M2 Water Chemistry ....................................................................................... XI M2-1 

XI.M3 Reactor Head Closure Stud Bolting .......................................................... XI M3-1 

XI.M4 BWR Vessel ID Attachment Welds ........................................................... XI M4-1 

XI.M5 BWR Feedwater Nozzle............................................................................ XI M5-1 

XI.M6 BWR Control Rod Drive Return Line Nozzle ............................................ XI M6-1 

XI.M7 BWR Stress Corrosion Cracking............................................................... XI M7-1 

XI.M8 BWR Penetrations .................................................................................... XI M8-1 

XI.M9 BWR Vessel Internals ............................................................................... XI M9-1 

XI.M10 Boric Acid Corrosion ............................................................................... XI M10-1 

XI.M11B Cracking of Nickel-Alloy Components and Loss of Material Due to 

Boric Acid-Induced Corrosion in Reactor Coolant Pressure Boundary 

Components (PWRs only) ....................................................................XI M11B-1 

XI.M12 Thermal Aging Embrittlement of Cast Austenitic

Stainless Steel (CASS)........................................................................... XI M12-1 

XI.M16A PWR Vessel Internals ...........................................................................XI M16A-1 

XI.M17 Flow-Accelerated Corrosion.................................................................... XI M17-1 

XI.M18 Bolting Integrity ....................................................................................... XI M18-1 

XI.M19 Steam Generators................................................................................... XI M19-1 

XI.M20 Open-Cycle Cooling Water System ........................................................ XI M20-1 

XI.M21A Closed Treated Water Systems ............................................................XI M21A-1 

XI.M22 Boraflex Monitoring ................................................................................. XI M22-1 

XI.M23 Inspection of Overhead Heavy Load and Light Load (Related to 

Refueling) Handling Systems.................................................................. XI M23-1 

XI.M24 Compressed Air Monitoring .................................................................... XI M24-1 
December 2010 ix NUREG-1801, Rev. 2

XI.M25 BWR Reactor Water Cleanup System .................................................... XI M25-1 

XI.M26 Fire Protection......................................................................................... XI M26-1 

XI.M27 Fire Water System .................................................................................. XI M27-1 

XI.M29 Aboveground Metallic Tanks................................................................... XI M29-1 

XI.M30 Fuel Oil Chemistry .................................................................................. XI M30-1 

XI.M31 Reactor Vessel Surveillance ................................................................... XI M31-1 

XI.M32 One-Time Inspection............................................................................... XI M32-1 

XI.M33 Selective Leaching.................................................................................. XI M33-1 

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

XI.M36 External Surfaces Monitoring of Mechanical Components ..................... XI M36-1 

XI.M37 Flux Thimble Tube Inspection................................................................. XI M37-1 

XI.M38 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components............................................................................................ XI M38-1 

XI.M39 Lubricating Oil Analysis........................................................................... XI M39-1 

XI.M40 Monitoring of Neutron-Absorbing Materials Other than Boraflex ............ XI M40-1 

XI.M41 Buried and Underground Piping and Tanks............................................ XI M41-1 

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

XI.S2 ASME Section XI, Subsection IWL................................................................. XI S2-1 

XI.S3 ASME Section XI, Subsection IWF ................................................................XI S3-1 

XI.S4 10 CFR Part 50, Appendix J...........................................................................XI S4-1 

XI.S5 Masonry Walls................................................................................................XI S5-1 

XI.S6 Structures Monitoring .....................................................................................XI S6-1 

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

Nuclear Power Plants ...............................................................................XI S7-1 

XI.S8 Protective Coating Monitoring and Maintenance Program ............................XI S8-1 

XI.E1 Insulation Material for Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements ........................XI E1-1 

XI.E2 Insulation Material for Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Used in 

Instrumentation Circuits .............................................................................XI E2-1 

XI.E3 Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements........................................................................XI E3-1 

XI.E4 Metal Enclosed Bus........................................................................................XI E4-1 

XI.E5 Fuse Holders ..................................................................................................XI E5-1 

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

Qualification Requirements........................................................................XI E6-1 

Appendix: Quality Assurance for Aging Management Programs ....................................... A-i 

December 2010 xi NUREG-1801, Rev. 2

LIST OF CONTRIBUTORS

Division of License Renewal, Office of Nuclear Reactor Regulation

B. Holian Division Director

M. Galloway Deputy Division Director

S. Lee Deputy Division Director

L. Lund Deputy Division Director 

R. Auluck Branch Chief

J. Dozier Branch Chief

D. Pelton Branch Chief

A. Hiser Senior Level 

R. Gramm Team Leader

H. Ashar Structural Engineering

M. Banic Mechanical Engineering

A. Buford Structural Engineer

C. Cho Administrative Assistant

J. Davis Materials Engineering

C. Doutt Electrical Engineering

B. Elliot Materials Engineering

A. Erickson General Engineer

S. Figueroa Licensing Assistant

B. Fu Materials Engineering

J. Gavula Mechanical Engineering

W. Holston Mechanical Engineering

E. Keegan Project Manager

I. King Licensing Assistant

R. Li Electrical Engineering

J. Medoff Mechanical Engineering

S. Min Materials Engineering

D. Nguyen Electrical Engineering

V. Perin Mechanical Engineering

A. Prinaris Mechanical Engineering

L. Regner Project Manager

S. Sakai Project Manager

B. Rogers Reactor Engineer

A. Sheikh Structural Engineering

W. Smith Mechanical Engineering

R. Sun Mechanical Engineering

R. Vaucher Mechanical Engineering

A. Wong Mechanical Engineering
NUREG-1801, Rev. 2 xii December 2010

C.Y. Yang Materials Engineering

L. Yee Administrative Assistant

O. Yee Mechanical Engineering

Office of Nuclear Reactor Regulation

G. Casto Branch Chief

T. Chan Branch Chief

M. Khanna Branch Chief

A. Klein Branch Chief

T. Lupold Branch Chief

M. Mitchell Branch Chief

R. Taylor Branch Chief

G. Wilson Branch Chief

R. Hardies Senior Level – Materials Engineering

K. Karwoski Senior Level – Steam Generators

K. Manoly Senior Level – Structural Engineering

D. Alley Materials Engineering

J. Bettle Mechanical Engineering

T. Cheng Structural Engineering

G. Cheruvenki Materials Engineering

J. Collins Mechanical Engineering

R. Davis Materials Engineering

S. Gardocki Mechanical Engineering

M. Hartzman Materials Engineering

K. Hoffman Mechanical Engineering

N. Iqbal Fire Protection Engineering

A. Johnson Mechanical Engineering

S. Jones Mechanical Engineering

B. Lee Mechanical Engineering

R. Mathew Electrical Engineering

P. Patniak Mechanical Engineering

G. Purciarello Mechanical Engineering

A. Tsirigotis Mechanical Engineering

M. Yoder Chemical Engineering

E. Wong Chemical Engineering
December 2010 xiii NUREG-1801, Rev. 2

Region I

G. Meyer Mechanical Engineering

M. Modes Mechanical Engineering

Office of Nuclear Regulatory Research

A. Csontos Branch Chief

M. Gavrilas Branch Chief

R. Hogan Branch Chief

T. Koshy Branch Chief

M. Salley Branch Chief

R. Tregoning Senior Level – Materials Engineering

S. Aggarwal Electrical Engineering

J. Burke Mechanical Engineering

G. Carpenter Materials Engineering

H. Graves Structural Engineering

A. Hull Materials Engineering

B. Lin Structural Engineering

L. Ramadan Electrical Engineering

G. Stevens Materials Engineering

D. Stroup Fire Protection Engineering

G. Wang Mechanical Engineering

Advanced Technologies and Laboratories International, Inc. (ATL)

K. Makeig Project Manager

K. Chang Mechanical Engineering

O. Chopra Materials Engineering

W. Jackson Mechanical Engineering

D. Jones Programming (Project Enhancement Corp.)

M. May Mechanical Engineering 

A. Ouaou Structural Engineering 

E. Patel Mechanical Engineering

J. Davis Materials Engineering

R. Royal Electrical Engineering

T. Brake Technical Editing

December 2010 xv NUREG-1801, Rev. 2

ABBREVIATIONS

ACAR aluminum conductor aluminum alloy reinforced

ACRS aluminum conductor steel reinforced

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

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

EDG emergency diesel generator

EPDM ethylene propylene diene monosomer

EPR ethylene-propylene rubber

EPRI Electric Power Research Institute
NUREG-1801, Rev. 2 xvi December 2010

EQ environmental qualification

FAC flow-accelerated corrosion

FERC Federal Energy Regulatory Commission

FRN Federal Register Notice

FSAR Final Safety Analysis Report

FW feedwater

GALL Generic Aging Lessons Learned

GE General Electric

GL generic letter

HDPE high density polyethylene

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

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
December 2010 xvii NUREG-1801, Rev. 2

LPM loose part monitoring 

LPRM low-power range monitor

LPSI low-pressure safety injection

LRAAI license renewal applicant action items

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

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

PVC polyvinyl chloride

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
NUREG-1801, Rev. 2 xviii December 2010

RG Regulatory Guide

RHR residual heat removal

RMS root mean square

RWC reactor water cleanup

RWST refueling water storage tank

RWT refueling water tank

SAW submerged arc weld

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

SR silicon rubber

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

UCS Union of Concerned Scientists

UHS ultimate heat sink

USI unresolved safety issue

UT ultrasonic testing

UV ultraviolet

XPLE cross-linked polyethylene
December 2010 1 NUREG-1801, Rev. 2

INTRODUCTION

NUREG-1801, “Generic Aging Lessons Learned (GALL) Report,” is referenced as a technical 

basis document in NUREG-1800, “Standard Review Plan for Review of License Renewal 

Applications for Nuclear Power Plants” (SRP-LR). The GALL Report lists generic aging 

management reviews (AMRs) of systems, structures, and components (SSCs) that may be in 

the scope of license renewal applications (LRAs) and identifies aging management programs 

(AMPs) that are determined to be acceptable to manage aging effects of SSCs in the scope of 

license renewal, as required by 10 CFR Part 54, “Requirements for Renewal of Operating 

Licenses for Nuclear Power Plants.” If an applicant takes credit for a program in the GALL 

Report, it is incumbent on the applicant to ensure that the conditions and operating experience 

at the plant are bounded by the conditions and operating experience for which the GALL Report 

was evaluated. If these bounding conditions are not met, it is incumbent on the applicant to 

address the additional effects of aging and augment the GALL report AMPs as appropriate. 

If an LRA references the GALL Report as the approach used to manage aging effect(s), the 

NRC staff will use the GALL Report as a basis for the LRA assessment consistent with 

guidance specified in the SRP-LR.
NUREG-1801, Rev. 2 2 December 2010

BACKGROUND

Revision 0 of the GALL Report

By letter dated March 3, 1999, the Nuclear Energy Institute (NEI) documented the industry’s 

views on how existing plant programs and activities should be credited for license renewal. The 

issue can be summarized as follows: 

To what extent should the staff review existing programs relied on for license renewal to 

determine whether an applicant has demonstrated reasonable assurance that such programs 

will be effective in managing the effects of aging on the functionality of structures and 

components during the period of extended operation? 

In a staff paper (SECY-99-148, “Credit for Existing Programs for License Renewal”) dated June 

3, 1999, the staff described options for crediting existing programs and recommended one 

option that the staff believed would improve the efficiency of the license renewal process.

By a staff requirements memorandum (SRM), dated August 27, 1999, the Commission 

approved the staff’s recommendation and directed the staff to focus the staff review guidance in 

the SRP-LR on areas where existing programs should be augmented for license renewal. The 

staff would develop a GALL Report to document the staff’s evaluation of generic existing 

programs. The GALL Report would document the staff’s basis for determining which existing 

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

for license renewal. The GALL Report would be referenced in the SRP-LR as a basis for 

determining the adequacy of existing programs.

The GALL Report (Revision 0) is built on a previous report, NUREG/CR-6490, “Nuclear Power 

Plant Generic Aging Lessons Learned (GALL),” which is a systematic compilation of plant aging 

information. The GALL Report (Revision 0) extended the information in NUREG/CR-6490 to 

provide an evaluation of the adequacy of AMPs for license renewal. The NUREG/CR-6490 

report was based on information in over 500 documents: Nuclear Plant Aging Research (NPAR) 

program reports sponsored by the Office of Nuclear Regulatory Research, Nuclear 

Management and Resources Council (NUMARC, now NEI) industry reports addressing license 

renewal for major structures and components, licensee event reports (LERs), information 

notices, generic letters, and bulletins. The staff also considered information contained in the 

reports provided by the Union of Concerned Scientists (UCS) in a letter dated May 5, 2000.

Following the general format of NUREG-0800 for major plant sections, except for refueling 

water, chilled water, residual heat removal, condenser circulating water, and condensate 

storage system in pressurized water reactor (PWR) and boiling water reactor (BWR) power 

plants, the staff reviewed the aging effects on components and structures, identified the relevant 

existing programs, and evaluated program attributes to manage aging effects for license 

renewal. The GALL Report (Revision 0) was prepared with the technical assistance of Argonne 

National Laboratory and Brookhaven National Laboratory. As directed in the SRM, the GALL 

Report (Revision 0) had the benefit of the experience of the staff members who conducted the 

review of the initial LRAs. Also, as directed in the SRM, the staff sought stakeholders’ 

participation in the development of this report. The staff held many public meetings and 

workshops to solicit input from the public. The staff also requested comments from the public on 

the draft improved license renewal guidance documents, including the GALL Report, in the 

Federal Register Notice, Vol. 65, No. 170, August 31, 2000. The staff’s analysis of stakeholder 
December 2010 3 NUREG-1801, Rev. 2

comments is documented in NUREG-1739. These documents can be found online at 

http://www.nrc.gov/reading-rm/doc-collections/.

Revision 1 of the GALL Report

Based on lessons learned from the reviews of LRAs and other public input including industry 

comments, the NRC staff proposed changes to the GALL Report (Revision 0) to make the GALL 

Report (Revision 1) more efficient. A preliminary version of Revision 1 of the GALL Report was 

posted on the NRC public web page on September 30, 2004. The draft revisions of the GALL 

Report (Vol. 1 and Vol. 2) were further refined and issued for public comment on January 31, 

2005. The staff also held public meetings with stakeholders to facilitate dialogue and to discuss 

comments. The staff subsequently took into consideration comments received (see NUREG1832) and incorporated its dispositions into the September 2005 version of the GALL Report

(Revision 1). 

Revision 2 of the GALL Report

Based on further lessons learned from the reviews of LRAs, operating experience obtained after

Revision 1 was issued, and other public input including industry comments, the NRC staff 

proposed changes to the GALL Report (Revision 1). A preliminary version of Revision 2 of the 

GALL Report was posted on the NRC public web page on December 23, 2009. The draft 

revision of the GALL Report was further refined and issued for public comment on May 18, 

2010. The staff held public meetings with stakeholders to facilitate dialogue and to discuss 

comments. The staff subsequently took into consideration comments received (see NUREG1950) and incorporated their dispositions into the December 2010, Revision 2 of the GALL 

Report.

Revision 2 – Operating Experience Evaluation

The extended operation of nuclear reactors necessitates a thorough analysis of existing 

experience. An operating experience review was performed by NRC staff to identify necessary 

additions or modifications to the GALL Report based on this experience. Both domestic and 

foreign operating experience was reviewed.

The staff from the Division of License Renewal (DLR) analyzed operating experience 

information during a screening review of domestic operating experience, foreign operating 

experience from the international Incident Reporting System (IRS) database, and NRC generic 

communications. The information reviewed included operating experience from January 2004 to 

approximately April 2009. 

Domestic Operating Experience: The NRC, Office of Research (RES) provided a listing of 

Licensee Event Reports (LERs) related to failures, cracking, degradation, etc. of passive 

components. These results were reviewed by NRC staff. The operating experience elements of 

numerous AMPs were updated to reflect relevant operating experience identified by the review.

In addition, the operating experience review identified a number of examples where vibrationinduced fatigue caused cracking of plant components. The staff subsequently modified GALL 

AMP XI.M35, “One-time Inspection of ASME Code Class 1 Small-bore Piping,” to address these 

concerns. 

Foreign Operating Experience: The international IRS, jointly operated by the International 

Atomic Energy Agency (IAEA) and the Nuclear Energy Agency (NEA), is used to compile and 
NUREG-1801, Rev. 2 4 December 2010

analyze information on NPP events and also promotes a systematic approach to collecting and 

disseminating the lessons learned from international operating experience. Events of safety 

significance and events from which lessons can be learned are reported to the IRS. The main

objective of the IRS is to enhance the safety of NPPs by reducing the frequency and severity of 

safety significant unusual events at NPPs. NRC staff also reviewed international operating 

experience from: (a) the Organization for Economic Co-operation and Development (OECD) 

OECD/NEA Piping Failure Data Exchange database (including the data from 1970 to 2009) and 

(b) the OECD/NEA Stress Corrosion Cracking and Cable Aging database. 

The foreign operating experience databases were queried for reports relating to aging effects in 

passive components. The identified reports were analyzed to determine if there were any 

revisions necessary for either AMR items or AMP content. Many of the reports identified MEAP 

combinations that were already addressed by the GALL Report. Some of the items were 

specific to foreign plants and not generically applicable to U.S. pressurized water reactors 

(PWRs) and boiling water reactors (BWRs). In addition, the IRS identified that stainless steel 

components are subject to chloride-induced stress corrosion cracking when they are exposed to 

the air-outdoor environment that involves a salt-laden atmospheric condition or salt water spray. 

Based on this review result, relevant SRP-LR sections were added and further evaluation is now 

recommended for those environmental conditions.
December 2010 5 NUREG-1801, Rev. 2

OVERVIEW OF THE GALL REPORT EVALUATION PROCESS

The GALL Report contains 11 chapters and an appendix. The majority of the chapters contain 

summary descriptions and tabulations of evaluations of AMPs for a large number of structures 

and components in major plant systems found in 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). 

Chapter I of the GALL Report 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 AMPs under 10 CFR 

54.21(c)(1)(iii). Chapter XI contains the AMPs for the structures and mechanical and electrical 

components. The Appendix of the GALL Report addresses quality assurance (QA) for AMPs.

The evaluation process for the AMPs and the application of the GALL Report is described in this 

document. The results of the GALL effort are presented in tabular format in the GALL Report. 

Table Column Headings

The following describes the information presented in each column of the tables in Chapters II 

through VIII contained in this report.

Column 

Heading Description

Item Identifies a unique number for the item (i.e., VII.G.A-91). The first part of the 

number indicates the chapter and AMR system (e.g., VII.G is in the auxiliary 

systems, fire protection system), and the second part is a unique chapterspecific identifier within a chapter (e.g., A-91 for auxiliary systems).

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

row identifier from GALL Volume 2, Rev. 1, if the row was derived from the 

earlier version of this report. Otherwise, blanks indicate a new row 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.

Aging Effect/ 

Mechanism

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

GALL Report for more information.

Aging 

Management 

Programs 

Identifies the time-limited aging analysis or AMP found acceptable for 

adequately managing the effects of aging. See Chapters X and XI of the GALL 

Report.

Further 

Evaluation 

Identifies whether further evaluation is needed.
NUREG-1801, Rev. 2 6 December 2010

The staff’s evaluation of the adequacy of each generic AMP to manage certain aging effects for 

particular structures and components is based on its review of the following 10 program 

elements in each AMP.

AMP Element Description

1. Scope of the Program The scope of the program should include the specific 

structures and components subject to an AMR.

2. Preventive Actions Preventive actions should mitigate or prevent the applicable 

aging effects.

3. Parameters Monitored or 

Inspected

Parameters monitored or inspected should be linked to the 

effects of aging on the intended functions of the particular 

structure and component.

4. Detection of Aging Effects Detection of aging effects should occur before there is a loss 

of any structure and component intended function. This 

includes aspects such as method or technique (i.e., visual, 

volumetric, surface inspection), frequency, sample size, data 

collection, and timing of new/one-time inspections to ensure 

timely detection of aging effects.

5. Monitoring and Trending Monitoring and trending should provide for prediction of the 

extent of the effects of aging and timely corrective or 

mitigative actions. 

6. Acceptance Criteria Acceptance criteria, against which the need for corrective 

action will be evaluated, should ensure that the particular 

structure and component’s intended functions are 

maintained under all current licensing basis (CLB) design 

conditions during the period of extended operation.

7. Corrective Actions Corrective actions, including root cause determination and 

prevention of recurrence, should be timely.

8. Confirmation Process The confirmation process should ensure that preventive 

actions are adequate and that appropriate corrective actions 

have been completed and are effective.

9. Administrative Controls Administrative controls should provide a formal review and 

approval process.

10. Operating Experience Operating experience involving the AMP, including past 

corrective actions resulting in program enhancements or 

additional programs, should provide objective evidence to 

support a determination that the effects of aging will be 

adequately managed so that the structure and component 

intended functions will be maintained during the period of 

extended operation.

On the basis of its evaluation, if the staff determined that a program is adequate to manage 

certain aging effects for a particular structure or component without change, the “Further 

Evaluation” entry will indicate that no further evaluation is recommended for license renewal.
December 2010 7 NUREG-1801, Rev. 2

Chapter XI of the GALL Report contains the staff's evaluation of generic aging management 

programs that are relied on in the GALL Report, such as the ASME Section XI inservice 

inspection, water chemistry, or structures monitoring program.
NUREG-1801, Rev. 2 8 December 2010

APPLICATION OF THE GALL REPORT

The GALL Report is a technical basis document to the SRP-LR, which provides the staff with 

guidance in reviewing an LRA. The GALL Report should be treated in the same manner as an 

approved topical report that is generically applicable. An applicant may reference the GALL 

Report in an LRA to demonstrate that the programs at the applicant’s facility correspond to 

those reviewed and approved in the GALL Report.

If an applicant takes credit for a program in GALL, it is incumbent on the applicant to ensure that 

the plant program contains all the elements of the referenced GALL program. In addition, the 

conditions and operating experience at the plant must be bound by the conditions and operating 

experience for which the GALL program was evaluated, otherwise it is incumbent on the 

applicant to augment the GALL program as appropriate to address the additional aging effects. 

The above verifications must be documented on-site in an auditable form. The applicant must 

include a certification in the LRA that the verifications have been completed.

The GALL Report contains one acceptable way to manage aging effects for license renewal. An 

applicant may propose alternatives for staff review in its plant-specific LRA. Use of the GALL 

Report is not required, but its use should facilitate both preparation of an LRA by an applicant 

and timely, uniform review by the NRC staff.

In addition, the GALL Report does not address scoping of structures and components for 

license renewal. Scoping is plant-specific, and the results depend on the plant design and CLB. 

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 not within the scope of license renewal for 

any plants.

The GALL Report contains an evaluation of a large number of structures and components that 

may be in the scope of a typical LRA. The evaluation results documented in the GALL Report 

indicate that many existing, typical generic aging management programs are adequate to 

manage aging effects for particular structures or components for license renewal without 

change. The GALL Report also contains recommendations on specific areas for which existing 

generic programs should be augmented (require further evaluation) for license renewal and 

documents the technical basis for each such determination. In addition, the GALL Report 

identifies certain SSCs that may or may not be subject to particular aging effects, and those for 

which industry groups are developing generic aging management programs or investigating 

whether aging management is warranted. 

The Appendix of the GALL Report addresses quality assurance (QA) for aging management 

programs. Those aspects of the aging management review process that affect the quality of 

safety-related structures, systems, and components are subject to the QA requirements of 

Appendix B to 10 CFR Part 50. For nonsafety-related structures and components subject to an 

AMR, the existing 10 CFR Part 50, Appendix B, QA program may be used by an applicant to 

address the elements of the corrective actions, confirmation process, and administrative 

controls for an aging management program for license renewal.

The GALL Report provides a technical basis for crediting existing plant programs and 

recommending areas for program augmentation and further evaluation. The incorporation of the 
December 2010 9 NUREG-1801, Rev. 2

GALL Report information into the SRP-LR, as directed by the Commission, should improve the 

efficiency of the license renewal process and better focus staff resources.

December 2010 I-i NUREG-1801, Rev. 2

CHAPTER I

APPLICATION OF THE ASME CODE

December 2010 I-1 NUREG-1801, Rev. 2

The American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, 

Division 1, Sections III (design) and XI (inservice inspection requirements) 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, the Atomic Energy 

Commission (AEC), the predecessor of the NRC, incorporated the ASME Boiler and Pressure 

Vessel Code into the regulations in 10 CFR 50.55a through issuance of the Federal Register 

Notice (FRN) for the final rule (36 FR 11423 [June 12, 1971]).

The Statements of Consideration (SOCs) for the initial issuance of 10 CFR 50.55a provide the 

bases for AEC’s endorsement and use of the ASME Code:

“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[.]” 

“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.”

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

intended to insure a basic, sound quality level.”

These ASME Code sections are based on the collective engineering judgment of the code 

committees and document the conditions that must be monitored, the inspection techniques to 

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

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

considered in the code. The NRC has accepted this engineering judgment by endorsing the use 

of selected sections of the ASME Code, as incorporated in 10 CFR 50.55a.

In addition, the NRC periodically amends 10 CFR 50.55a and issues FRNs about this rule in 

order to endorse, by reference, newer editions and ASME Code Addenda subject to the 

modifications and limitations identified in 10 CFR 50.55a. At the time of this Standard Review 

Plan for License Renewal (SRP-LR) (NUREG-1800) and Generic Aging Lessons Learned 

(GALL) Report (NUREG-1801) update, the most recent editions of the ASME Code Sections III 

and XI were endorsed in 73 FR 52730-52750 (September 10, 2008). As stated in 65 FR 53050 

(August 31, 2000): 

“To ensure that the GALL report conclusions will remain valid when future 

editions of the ASME Code are incorporated into the NRC regulations by the 10 

CFR 50.55a rulemaking, the staff will perform an evaluation of these later 

editions for their adequacy for license renewal using the 10-element program 

evaluation described in the GALL Report as part of the 10 CFR 50.55a 

rulemaking.” 
NUREG-1801, Rev. 2 I-2 December 2010

The staff will document this evaluation in the SOC accompanying future 10 CFR 50.55a 

amendments, which will be published in a FRN. 

To aid applicants in the development of their license renewal applications, the staff has 

developed a list of aging management programs (AMPs) in the GALL Report that are based on 

conformance with the 10-program element criteria defined in Section A.1.2.3 of the SRP-LR. 

Some of the AMPs referenced in the GALL Report are based entirely or in part on compliance 

with the requirements of ASME Section XI, as endorsed for use through reference in 10 CFR 

50.55a., The staff has determined that the referenced ASME Section XI programs or 

requirements provide an acceptable basis for managing the effects of aging during the period of 

extended operation for these AMPs, except where noted and augmented in the GALL Report. 

For aging management purposes, consideration of the acceptability for license renewal of 

ASME Section XI editions and addenda from the 1995 edition through the 2004 Addenda are 

discussed in FRNs 67 FR 60520 (September 26, 2002); 69 FR 58804 (October 1, 2004); and 73 

FR 52730 (September 10, 2008) (via update of 10 CFR 50.55a). These FRNs provide that 

ASME Section XI editions and addenda from the 1995 edition through the 2004 edition, as 

modified and limited in the final rule, are acceptable and the conclusions in the current GALL 

Report at the time of the FRN issuance remain valid. Future FRNs that amend 10 CFR 50.55a 

will discuss the acceptability of editions and addenda more recent than the 2004 edition for their 

applicability for aging management for license renewal. Therefore, except where noted and 

augmented in the GALL Report, the following ASME Section XI editions and addenda are 

acceptable and should be treated as consistent with the GALL Report: (1) from the 1995 edition 

to the 2004 edition, as modified and limited in 10 CFR 50.55a, and (2) more recent editions, as 

evaluated for their adequacy for license renewal and discussed in the accompanying FRN for 10 

CFR 50.55a rulemaking endorsing those specific editions. Hence, applicants for renewal should 

justify any exception to use an ASME Section XI edition or addenda that is (1) earlier than the 

1995 edition, (2) not endorsed in 10 CFR 50.55a, or (3) not adequate for license renewal as 

discussed in the FRN issuing the 10 CFR 50.55a amendment.

In some cases, the staff has determined that specific requirements in ASME Section XI need to 

be augmented to ensure adequate aging management consistent with the license renewal rule. 

Thus, some of the AMPs in the GALL Report provide for additional augmented actions. For 

these situations, applicants for renewal should review the recommendations in the GALL Report 

and discuss proposed enhancements in their LRAs. 

Pursuant to 10 CFR 50.55a(g)(4), a nuclear licensee is required to amend its current licensing 

basis (CLB) by updating its ASME Section XI edition and addenda of record to the most recently 

endorsed edition and addenda referenced in 10 CFR 50.55a one year prior to entering the next 

10-year internal inservice inspection (ISI) for its unit. Pursuant to 10 CFR 54.21(b), an applicant 

for license renewal is required to periodically submit updates of its LRA to identify any changes 

in its CLB that materially affect the contents of the LRA. The rule requires an update of the LRA 

each year following the submittal of the application and an additional update 3 months prior to 

the completion of the NRC’s review of the LRA. If an applicant’s ASME Section XI edition of 

record is updated under the requirements of 10 CFR 50.55a(g)(4) during the NRC’s review of 

the LRA, the applicant should update those AMPs in the LRA that are impacted by this change 

in the CLB when the applicant submits the next update of the LRA required by 10 CFR 54.21(b). 

The current regulatory process, including 10 CFR 50.55a, continues into the period of extended 

operation. The NRC Director of the Office of Nuclear Reactor Regulation (NRR) may approve a 

licensee-proposed alternative to ASME Section XI if it is submitted as a relief request in 
December 2010 I-3 NUREG-1801, Rev. 2

accordance with 10 CFR 50.55a(a)(3). The staff’s approval of an alternative program/relief 

request typically does not extend beyond the current 10-year interval for which the alternative 

was proposed. For cases in which this interval extends beyond the initial 40-year license period 

into the renewed license period, the approved relief remains in effect until the end of that 

interval, consistent with the specific approval (60 FR 22461, 22483).

Pursuant to 10 CFR 50.55a(b)(5), licensees may apply ASME Code cases listed in NRC 

Regulatory Guide (RG) 1.147, through the most recent endorsed revision, without NRC 

approval, subject to the limitations contained in the rule. The rule permits licensees to continue 

to apply the Code case, or a most recent version that is incorporated by the RG, until the end of 

the 10-year interval. For cases in which this interval extends beyond the initial 40-year license 

period into the renewal period, the Code case, or a more recent endorsed version, remains in 

effect until the end of that interval, consistent with 10 CFR 50.55a(b)(5) and the statements of 

consideration for the final license renewal rule 60 FR 22461.

December 2010 II-i NUREG-1801, Rev. 2

CHAPTER II

CONTAINMENT STRUCTURES 

December 2010 II-iii NUREG-1801, Rev. 2

CONTAINMENT STRUCTURES

A. Pressurized Water Reactor (PWR) Containments

B. Boiling Water Reactor (BWR) Containments

 

December 2010 II A-i NUREG-1801, Rev. 2

PRESSURIZED WATER REACTOR (PWR) CONTAINMENTS

A1. Concrete Containments (Reinforced and Prestressed)

A2. Steel Containments

A3. Common Components

December 2010 II A1-1 NUREG-1801, Rev. 2

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 systems.

System Interfaces

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

containment isolation components (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. 2 II A1-2 December 2010

II CONTAINMENT STRUCTURES

A1 Concrete Containments (Reinforced and Prestressed)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program (A

II.A1.CP87II.A1-4(C03)Concrete 

(accessible 

areas): dome; 

wall; basemat; 

ring girders; 

buttresses

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Increase in porosity 

and permeability; 

cracking; loss of 

material (spalling, 

scaling) 

due to aggressive 

chemical attack

Chapter XI.S2, “ASME Section X

Subsection IWL”

II.A1.CP31II.A1-2(C01)Concrete 

(accessible 

areas): dome; 

wall; basemat; 

ring girders; 

buttresses

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freeze-thaw

Chapter XI.S2, “ASME Section X

Subsection IWL”

II.A1.CP33II.A1-3(C04)Concrete 

(accessible 

areas): dome; 

wall; basemat; 

ring girders; 

buttresses

Concrete Any environment Cracking 

due to expansion 

from reaction with 

aggregates

Chapter XI.S2, “ASME Section X

Subsection IWL”

II.A1.CP32II.A1-6(C02)Concrete 

(accessible 

areas): dome; 

wall; basemat; 

ring girders; 

buttresses

Concrete Water – flowing Increase in porosity 

and permeability; 

loss of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Chapter XI.S2, “ASME Section X

Subsection IWL”

II.A1.CP68II.A1-7(C05)Concrete 

(accessible 

areas): 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) 

due to corrosion of 

embedded steel

Chapter XI.S2, “ASME Section X

Subsection IWL”
December 2010 II A1-3 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

A1 Concrete Containments (Reinforced and Prestressed)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program (A

II.A1.CP100II.A1-4(C03)Concrete 

(inaccessible 

areas): dome; 

wall; basemat; 

ring girders; 

buttresses

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor or 

Ground 

water/soil

Increase in porosity 

and permeability; 

cracking; loss of 

material (spalling, 

scaling) 

due to aggressive 

chemical attack

Chapter XI.S2, “ASME Section X

Subsection IWL,” or 

Chapter XI.S6, " Structures Mon

II.A1.CP147II.A1-2(C01)Concrete 

(inaccessible 

areas): dome; 

wall; basemat; 

ring girders; 

buttresses

Concrete Air – outdoor or 

Ground 

water/soil

Loss of material 

(spalling, scaling) 

and cracking 

due to freeze-thaw

Further evaluation is required for 

that are located in moderate to s

weathering conditions (weatherin

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

determine if a plant-specific agin

management program is needed

plant-specific aging managemen

program is not required if docum

evidence confirms that the existi

concrete had air entrainment con

per Table CC-2231-2 of the ASM

Section III Division 2), and subse

inspections of accessible areas d

exhibit degradation related to fre

thaw. Such inspections should b

considered a part of the evaluati

this condition is not satisfied, the

plant-specific aging managemen

program is required to manage lo

material (spalling, scaling) and c

due to freeze-thaw of concrete in 

inaccessible areas. 

The weathering index for the con

US is shown in ASTM C33-90, F
NUREG-1801, Rev. 2 II A1-4 December 2010

II CONTAINMENT STRUCTURES

A1 Concrete Containments (Reinforced and Prestressed)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program (A

II.A1.CP67II.A1-3(C04)Concrete 

(inaccessible 

areas): dome; 

wall; basemat; 

ring girders; 

buttresses

Concrete Any environment Cracking 

due to expansion 

from reaction with 

aggregates

Further evaluation is required to 

determine if a plant-specific agin

management program is needed 

manage cracking and expansion 

reaction with aggregate of concr

Inaccessible Areas. A plant-spec

aging management program is n

required if (1) as described in NU

1557, investigations, tests, and 

petrographic examinations of 

aggregates performed in accorda

with ASTM C295 and other AST

reactivity tests, as required, can 

demonstrate that those aggregat

not adversely react within concre

(2) For potentially reactive aggre

aggregate concrete reaction is n

significant if it is demonstrated th

in-place concrete can perform its 

intended function.

II.A1.CP102II.A1-6(C02)Concrete 

(inaccessible 

areas): dome; 

wall; basemat; 

ring girders; 

buttresses

Concrete Water – flowing Increase in porosity 

and permeability; 

loss of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Further evaluation is required to 

determine if a plant-specific agin

management program is needed 

manage increase in porosity, and 

permeability due to leaching of c

hydroxide and carbonation of co

Inaccessible Areas. A plant-spec

aging management program is n

required if (1) There is evidence 

accessible areas that the flowing 

has not caused leaching and 

carbonation, or (2) Evaluation 

determined that the observed lea
December 2010 II A1-5 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

A1 Concrete Containments (Reinforced and Prestressed)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program (A

of calcium hydroxide and carbon

accessible areas has no impact 

intended function of the concrete 

structure.

II.A1.CP97II.A1-7(C05)Concrete 

(inaccessible 

areas): 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) 

due to corrosion of 

embedded steel

Chapter XI.S2, “ASME Section X

Subsection IWL,” or 

Chapter XI.S6, " Structures Mon

II.A1.CP34II.A1-1(C08)Concrete: 

dome; wall; 

basemat; ring 

girders; 

buttresses

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Reduction of 

strength and 

modulus 

due to elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging managemen

program 

 

The implementation of 10 CFR 5

and ASME Section XI, Subsectio

would not be able to identify the 

reduction of strength and modulu

elasticity due to elevated temper

Thus, for any portions of concret

containment that exceed specifie

temperature limits, further evalua

are warranted. Subsection CC-3

ASME Section III, Division 2, spe

the concrete temperature limits f

normal operation or any other lo

period. The temperatures shall n

exceed 150°F except for local ar

such as around penetrations, wh

not allowed to exceed 200°F. If 

significant equipment loads are 

supported by concrete at temper
NUREG-1801, Rev. 2 II A1-6 December 2010

II CONTAINMENT STRUCTURES

A1 Concrete Containments (Reinforced and Prestressed)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program (A

exceeding 150°F, an evaluation 

ability to withstand the postulated 

loads is to be made. 

 

Higher temperatures than given 

may be allowed in the concrete i

and/or calculations are provided 

evaluate the reduction in strengt

modulus of elasticity and these 

reductions are applied to the des

calculations.

II.A1.CP101II.A1-5(C37)Concrete: 

dome; wall; 

basemat; ring 

girders; 

buttresses

Concrete Soil Cracking and 

distortion 

due to increased 

stress levels from 

settlement

Chapter XI.S2, “ASME Section X

Subsection IWL,” or 

Chapter XI.S6, " Structures Mon

If a de-watering system is relied 

control of settlement, then the lic

is to ensure proper functioning o

watering system through the per

extended operation. 

II.A1.C-07 II.A1-8(C07)Concrete: 

foundation; 

subfoundation

Concrete; 

porous 

concrete

Water – flowing Reduction of 

foundation strength 

and cracking 

due to differential 

settlement and 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Monit

If a de-watering system is relied 

control of erosion of cement from 

concrete subfoundations, then th

licensee is to ensure proper func

of the de-watering system throug

period of extended operation.

II.A1.C-11 II.A1-9(C11)Prestressing 

system: 

tendons

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of prestress 

due to relaxation; 

shrinkage; creep; 

elevated 

temperature

Loss of tendon prestress is a tim

limited aging analysis (TLAA) to 

evaluated for the period of exten

operation. 

See the SRP, Section 4.5, “Conc

Containment Tendon Prestress” 
December 2010 II A1-7 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

A1 Concrete Containments (Reinforced and Prestressed)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program (A

acceptable methods for meeting 

requirements of 10 CFR 54.21(c

and (ii). See Chapter X.S1 of this 

for meeting the requirements of 

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

For periodic monitoring of prestre

Chapter XI.S2.

II.A1.C-10 II.A1-

10(C-10)

Prestressing 

system: 

tendons; 

anchorage 

components

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to corrosion

Chapter XI.S2, “ASME Section X

Subsection IWL”

II.A1.CP35II.A1-

11(C-09)

Steel elements 

(accessible 

areas): liner; 

liner anchors; 

integral 

attachments

Steel Air – indoor, 

uncontrolled

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.S1, “ASME Section X

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 50, 

Appendix J”

II.A1.CP98II.A1-

11(C-09)

Steel elements 

(inaccessible 

areas): liner; 

liner anchors; 

integral 

attachments

Steel Air – indoor, 

uncontrolled

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.S1, “ASME Section X

Subsection IWE” and 

 

Chapter XI.S4, “10 CFR Part 50, 

Appendix J” 

 

Additional plant-specific activitie

warranted if loss of material due 

corrosion is significant for inacce

areas (embedded containment s

shell or liner).

 

Loss of material due to corrosion 

significant if the following conditi

satisfied: 
NUREG-1801, Rev. 2 II A1-8 December 2010

II CONTAINMENT STRUCTURES

A1 Concrete Containments (Reinforced and Prestressed)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program (A

1. Concrete meeting the requirem

ACI 318 or 349 and the guidance 

201.2R was used for the contain

concrete in contact with the emb

containment shell or liner. 

2. The moisture barrier, at the ju

where the shell or liner becomes 

embedded, is subject to aging 

management activities in accord

with ASME Section XI, Subsectio

requirements. 

3. The concrete is monitored to e

that it is free of penetrating crack

provide a path for water seepage 

surface of the containment shell 

4. Borated water spills and wate

ponding on the concrete floor are 

common and when detected are 

up or diverted to a sump in a tim

manner. 

Operating experience has ident

significant corrosion in some pla

 

If any of the above conditions ca

satisfied, then a plant-specific ag

management program for corros

necessary.
December 2010 II A2-1 NUREG-1801, Rev. 2

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 components (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. 2 II A2-2 December 2010

II CONTAINMENT STRUCTURES

A2 Steel Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

II.A2.CP-51 II.A2-2(C28)Concrete 

(accessible 

areas): 

basemat

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Chapter XI.S2, “ASME Sectio

Subsection IWL”

II.A2.CP-58 II.A2-3(C38)Concrete 

(accessible 

areas): 

basemat

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Chapter XI.S2, “ASME Sectio

Subsection IWL”

II.A2.CP-72 II.A2-4(C25)Concrete 

(accessible 

areas): 

basemat

Concrete Ground 

water/soil

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

due to aggressive 

chemical attack

Chapter XI.S2, “ASME Sectio

Subsection IWL,” or 

Chapter XI.S6, " Structures

Monitoring"

II.A2.CP-155 II.A2-6(C30)Concrete 

(accessible 

areas): 

basemat

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Chapter XI.S2, “ASME Sectio

Subsection IWL”

II.A2.CP-74 II.A2-7(C43)Concrete 

(accessible 

areas): 

basemat; 

reinforcing 

steel

Concrete; 

steel

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S2, “ASME Sectio

Subsection IWL”
December 2010 II A2-3 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

A2 Steel Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

II.A2.CP-70 II.A2-2(C28)Concrete 

(inaccessible 

areas): 

basemat

Concrete Air – outdoor or 

Ground 

water/soil

Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Further evaluation is required 

plants that are located in mod

severe weathering conditions 

(weathering index >100 day-in

(NUREG-1557) to determine i

plant-specific aging managem

program is needed. A plant-sp

aging management program is 

required if documented eviden

confirms that the existing conc

had air entrainment content (a

Table CC-2231-2 of the ASME 

Section III Division 2), and 

subsequent inspections of acc

areas did not exhibit degradat

related to freeze-thaw. Such 

inspections should be conside

part of the evaluation. If this c

is not satisfied, then a plant-sp

aging management program is 

required to manage loss of ma

(spalling, scaling) and crackin

freeze-thaw of concrete in 

inaccessible areas. 

The weathering index for the 

continental US is shown in AS

C33-90, Fig. 1.

II.A2.CP-104 II.A2-3(C38)Concrete 

(inaccessible 

areas): 

basemat

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Further evaluation is required 

determine if a plant-specific ag

management program is need

manage cracking and expans

to reaction with aggregate of c

in Inaccessible Areas. A plant
NUREG-1801, Rev. 2 II A2-4 December 2010

II CONTAINMENT STRUCTURES

A2 Steel Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

aging management program is 

required if (1) as described in 

NUREG-1557, investigations, 

and petrographic examination

aggregates performed in acco

with ASTM C295 and other AS

reactivity tests, as required, ca

demonstrate that those aggreg

not adversely react within con

(2) For potentially reactive 

aggregates, aggregate concre

reaction is not significant if it is 

demonstrated that the in-place 

concrete can perform its inten

function.

II.A2.CP-71 II.A2-4(C25)Concrete 

(inaccessible 

areas): 

basemat

Concrete Ground 

water/soil

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

due to aggressive 

chemical attack

Chapter XI.S2, “ASME Sectio

Subsection IWL,” or 

Chapter XI.S6, " Structures

Monitoring“

II.A2.CP-53 II.A2-6(C30)Concrete 

(inaccessible 

areas): 

basemat

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Further evaluation is required 

determine if a plant-specific ag

management program is need

manage increase in porosity, a

permeability due to leaching o

calcium hydroxide and carbon

concrete in Inaccessible Areas

plant-specific aging managem

program is not required if 

(1) There is evidence in the 
December 2010 II A2-5 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

A2 Steel Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

accessible areas of adjacent 

structures that the flowing wat

not caused leaching and carb

or 

(2) Evaluation determined tha

observed leaching of calcium 

hydroxide and carbonation in 

accessible areas has no impa

intended function of the concr

structure.

II.A2.CP-75 II.A2-7(C43)Concrete 

(inaccessible 

areas): 

basemat; 

reinforcing 

steel

Concrete; 

steel

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S2, “ASME Sectio

Subsection IWL,” or 

Chapter XI.S6, " Structures

Monitoring"

II.A2.CP-69 II.A2-5(C36)Concrete: 

basemat

Concrete Soil Cracking and 

distortion 

due to increased 

stress levels from 

settlement

Chapter XI.S2, “ASME Sectio

Subsection IWL,” or 

Chapter XI.S6, " Structures

Monitoring" 

If a de-watering system is relie

for control of settlement, then 

licensee is to ensure proper 

functioning of the de-watering 

through the period of extende

operation. 

II.A2.C-07 II.A2-8(C07)Concrete: 

foundation; 

subfoundation

Concrete; 

porous 

concrete

Water – flowing Reduction of 

foundation 

strength and 

cracking 

due to differential 

settlement and 

Chapter XI.S6, “ Structures

Monitoring” 

If a de-watering system is relie

for control of erosion of cemen

porous concrete subfoundatio

the licensee is to ensure prop
NUREG-1801, Rev. 2 II A2-6 December 2010

II CONTAINMENT STRUCTURES

A2 Steel Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

erosion of porous 

concrete 

subfoundation

functioning of the de-watering 

through the period of extende

operation.

II.A2.CP-35 II.A2-9(C09)Steel 

elements 

(accessible 

areas): liner; 

liner anchors; 

integral 

attachments

Steel Air – indoor, 

uncontrolled

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S1, “ASME Sectio

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J”

II.A2.CP-98 II.A2-9(C09)Steel 

elements 

(inaccessible 

areas): liner; 

liner anchors; 

integral 

attachments

Steel Air – indoor, 

uncontrolled

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S1, “ASME Sectio

Subsection IWE” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J” 

Additional plant-specific activit

warranted if loss of material d

corrosion is significant for inac

areas (embedded containmen

shell or liner).

Loss of material due to corros

not significant if the following 

conditions are satisfied: 

1. Concrete meeting the requi

of ACI 318 or 349 and the gui

201.2R was used for the conta

concrete in contact with the 

embedded containment shell o

2. The moisture barrier, at the 

where the shell or liner becom

embedded, is subject to aging 

management activities in acco

with ASME Section XI, Subse

IWE requirements.
December 2010 II A2-7 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

A2 Steel Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

3. The concrete is monitored t

ensure that it is free of penetra

cracks that provide a path for 

seepage to the surface of the 

containment shell or liner. 

4. Borated water spills and wa

ponding on the concrete floor 

common and when detected a

cleaned up or diverted to a su

timely manner. 

Operating experience has ide

significant corrosion in some p

If any of the above conditions 

be satisfied, then a plant-spec

aging management program f

corrosion is necessary.

December 2010 II A3-1 NUREG-1801, Rev. 2

A3. COMMON COMPONENTS

Systems, Structures, and Components

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

containment structures. 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 components (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.2 II A3-2 December 2010

II CONTAINMENT STRUCTURES

A3 Common Components

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

II.A3.CP-40 II.A3-7(C18)Moisture 

barriers 

(caulking, 

flashing, and 

other 

sealants)

Elastomers, 

rubber and 

other similar 

materials

Air – indoor, 

uncontrolled

Loss of sealing 

due to wear, 

damage, 

erosion, tear, 

surface cracks, 

or other defects

Chapter XI.S1, “ASME Section 

Subsection IWE”

II.A3.CP-36 II.A3-1(C12)Penetration 

sleeves

Steel; 

dissimilar 

metal welds

Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J” 

II.A3.CP-38 II.A3-2(C15)Penetration 

sleeves; 

penetration 

bellows

Stainless 

steel; 

dissimilar 

metal welds

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to stress 

corrosion 

cracking

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J”

II.A3.CP-37 II.A3-3(C14)penetration 

sleeves; 

penetration 

bellows

Steel; 

stainless 

steel; 

dissimilar 

metal welds

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to cyclic 

loading 

(CLB fatigue 

analysis does 

not exist)

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J”

II.A3.C-13 II.A3-4(C13)Penetration 

sleeves; 

penetration 

bellows

Steel; 

stainless 

steel; 

dissimilar 

metal welds

Air – indoor, 

uncontrolled or 

Air – outdoor

Cumulative 

fatigue damage 

due to fatigue 

(Only if CLB 

fatigue analysis 

exists)

Fatigue is a time-limited aging 

(TLAA) to be evaluated for the 

of extended operation. See the 

Section 4.6, “Containment Line

and Penetration Fatigue Analy

acceptable methods for meetin

requirements of 10 CFR 54.21

II.A3.C-16 II.A3-6(C16)Personnel 

airlock, 

equipment 

hatch, CRD 

hatch

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to general,

pitting, and 

crevice 

corrosion

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J”
December 2010 II A3-3 NUREG-1801, Rev.2

II CONTAINMENT STRUCTURES

A3 Common Components

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

II.A3.CP-39 II.A3-5(C17)Personnel 

airlock, 

equipment 

hatch, CRD 

hatch: locks, 

hinges, and 

closure 

mechanisms

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of leak 

tightness 

due to 

mechanical wear 

of locks, hinges 

and closure 

mechanisms

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J”

II.A3.CP-150 Pressureretaining 

bolting

Any Any 

environment

Loss of preload 

due to selfloosening

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J”

II.A3.CP-148 Pressureretaining 

bolting

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S1, “ASME Section 

Subsection IWE”

II.A3.CP-41 II.A3-7(C18)Seals and 

gaskets

Elastomers, 

rubber and 

other similar 

materials

Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of sealing 

due to wear, 

damage, 

erosion, tear, 

surface cracks, 

or other defects

Chapter XI.S4, “10 CFR Part 5

Appendix J "

II.A3.CP-152 Service Level 

I coatings

Coatings Air – indoor, 

uncontrolled 

Loss of coating 

integrity 

due to blistering, 

cracking, flaking, 

peeling, or 

physical damage

Chapter XI.S8, "Protective Coa

Monitoring and Maintenance"

December 2010 DRAFT II B1-i NUREG-1801, Rev. 2

BOILING WATER REACTOR (BWR) CONTAINMENTS

B1. Mark I Containments

B2. Mark II Containments

B3. Mark III Containments

B4. Common Components

December 2010 II B1-1 NUREG-1801, Rev. 2

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 components (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. 2 II B1-2 December 2010

II CONTAINMENT STRUCTURES

B1.1 Mark I Steel Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

II.B1.1.CP-43 II.B1.1-

2(C-19)

Steel elements 

(accessible 

areas): drywell 

shell; drywell 

head; drywell 

shell in sand 

pocket regions;

Steel Air – indoor, 

uncontrolled

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 50

Appendix J”

II.B1.1.C-23 II.B1.1-

1(C-23)

Steel elements: 

drywell head; 

downcomers

Steel Air – indoor, 

uncontrolled

Fretting or 

lockup 

due to 

mechanical 

wear

Chapter XI.S1, “ASME Section 

Subsection IWE”

II.B1.1.CP-44 Steel elements: 

drywell support 

skirt

Steel Concrete None None 

II.B1.1.CP-109 II.B1.1-

2(C-19)

Steel elements: 

torus ring 

girders; 

downcomers;

Steel Air – indoor, 

uncontrolled or 

Treated water

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S1, “ASME Section 

Subsection IWE” 

 

Plant specific aging manageme

program is required if plant ope

experience identified significant 

corrosion of the torus ring girde

downcomers. If protective coati

credited for preventing corrosio

torus shell, the coating should b

included in scope of license ren

and subject to aging manageme

review.

II.B1.1.CP-48 II.B1.1-

2(C-19)

Steel elements: 

torus shell

Steel Air – indoor, 

uncontrolled or 

Treated water

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 50

Appendix J” 

Significant corrosion of the torus 
December 2010 II B1-3 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

B1.1 Mark I Steel Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

and degradation of its protective 

coating are identified in IN 88-8

industrywide operating indicates 

number of incidences of torus 

corrosion. License renewal app

are advised to address their pla

specific operating experience re

the torus shell corrosion. If the 

identified corrosion is significan

plant specific aging manageme

required. If protective coating is 

credited for preventing corrosio

torus shell, the coating should b

included in scope of license ren

and subject to aging manageme

review .

II.B1.1.CP-49 II.B1.1-

3(C-20)

Steel elements: 

torus; vent line; 

vent header; 

vent line 

bellows; 

downcomers

Steel; 

stainless 

steel

Air – indoor, 

uncontrolled

Cracking 

due to cyclic 

loading 

(CLB fatigue 

analysis does 

not exist)

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 50

Appendix J”

II.B1.1.C-21 II.B1.1-

4(C-21)

Steel elements: 

torus; vent line; 

vent header; 

vent line 

bellows; 

downcomers

Steel; 

stainless 

steel

Air – indoor, 

uncontrolled

Cumulative 

fatigue damage 

due to fatigue 

(Only if CLB 

fatigue analysis 

exists)

Fatigue is a time-limited aging a

(TLAA) to be evaluated for the p

extended operation. See the SR

Section 4.6, “Containment Liner 

and Penetration Fatigue Analys

acceptable methods for meeting 

requirements of 10 CFR 54.21(c

II.B1.1.CP-50 II.B1.1-

5(C-22)

Steel elements: 

vent line 

bellows

Stainless 

steel

Air – indoor, 

uncontrolled

Cracking 

due to stress 

corrosion 

cracking

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 50

Appendix J”
NUREG-1801, Rev. 2 II B1-4 December 2010

II CONTAINMENT STRUCTURES

B1.2 Mark I Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

II.B1.2.CP-79 II.B1.2-

2(C-41)

Concrete 

(accessible 

areas): 

basemat; 

reinforcing steel

Concrete; 

steel

Air – indoor, 

uncontrolled or

Air – outdoor

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S2, “ASME Sectio

Subsection IWL”

II.B1.2.CP-59 II.B1.2-

4(C-39)

Concrete 

(accessible 

areas): 

containment; 

wall; basemat

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Chapter XI.S2, “ASME Sectio

Subsection IWL”

II.B1.2.CP-54 II.B1.2-

6(C-31)

Concrete 

(accessible 

areas): 

containment; 

wall; basemat

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Chapter XI.S2, “ASME Sectio

Subsection IWL”

II.B1.2.CP-80 II.B1.2(C41)Concrete 

(inaccessible 

areas): 

basemat; 

reinforcing steel

Concrete; 

steel

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures 

Monitoring"

II.B1.2.CP-99 II.B1.2-

4(C-39)

Concrete 

(inaccessible 

areas): 

containment; 

wall; basemat

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Further evaluation is required 

determine if a plant-specific a

management program is need

manage cracking and expans

to reaction with aggregate of 

in Inaccessible Areas. A plant
December 2010 II B1-5 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

B1.2 Mark I Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

aging management program 

required if (1) as described in 

NUREG-1557, investigations, 

and petrographic examination

aggregates performed in acco

with ASTM C295 and other A

reactivity tests, as required, c

demonstrate that those aggre

do not adversely react within

concrete, or (2) For potentially 

reactive aggregates, aggrega

concrete reaction is not signif

is demonstrated that the in-pl

concrete can perform its inten

function.

II.B1.2.CP-110 II.B1.2-

6(C-31)

Concrete 

(inaccessible 

areas): 

containment; 

wall; basemat

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Further evaluation is required 

determine if a plant-specific a

management program is need

manage increase in porosity, 

permeability due to leaching o

calcium hydroxide and carbon

concrete in Inaccessible Area

plant-specific aging managem

program is not required if (1) 

evidence in the accessible are

the flowing water has not cau

leaching and carbonation, or 

Evaluation determined that th

observed leaching of calcium 

hydroxide and carbonation in 

accessible areas has no impa

the intended function of the co

structure.
NUREG-1801, Rev. 2 II B1-6 December 2010

II CONTAINMENT STRUCTURES

B1.2 Mark I Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

II.B1.2.CP-105 II.B1.2-

1(C-06)

Concrete 

elements, all

Concrete Soil Cracking and 

distortion 

due to increased 

stress levels from 

settlement

Chapter XI.S2, “ASME Sectio

Subsection IWL,” or 

Chapter XI.S6, " Structures

Monitoring" 

If a de-watering system is reli

for control of settlement, then 

licensee is to ensure proper 

functioning of the de-watering 

through the period of extende

operation. 

II.B1.2.CP-106 II.B1.2-

5(C-26)

Concrete: 

containment; 

wall; basemat

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

due to aggressive 

chemical attack

Chapter XI.S2, “ASME Sectio

Subsection IWL,” or 

Chapter XI.S6, " Structures

Monitoring"

II.B1.2.CP-57 II.B1.2-

3(C-35)

Concrete: 

containment; 

wall; basemat

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Reduction of 

strength and 

modulus 

due to elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging managem

program 

 

The implementation of 

10 CFR 50.55a and ASME Co

Section XI, Subsection IWL w

be able to identify the reductio

strength and modulus due to 

temperature. Thus, for any po

concrete containment that exc

specified temperature limits, f

evaluations are warranted. 

Subsection CC-3400 of ASME 

Section III, Division 2, specifie

concrete temperature limits fo
December 2010 II B1-7 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

B1.2 Mark I Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

operation or any other long-te

period. The temperatures sha

exceed 150°F except for loca

such as around penetrations, 

are not allowed to exceed 200

significant equipment loads a

supported by concrete at 

temperatures exceeding 150°

evaluation of the ability to with

the postulated design loads is 

made. 

 

Higher temperatures than giv

above may be allowed in the 

if tests and/or calculations are 

provided to evaluate the redu

strength and modulus of elast

and these reductions are app

the design calculations.

II.B1.2.C-07 II.B1.2-

7(C-07)

Concrete: 

foundation; 

subfoundation

Concrete; 

porous 

concrete

Water – flowing Reduction of 

foundation 

strength and 

cracking 

due to differential 

settlement and 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures 

Monitoring” 

If a de-watering system is reli

for control of erosion of ceme

porous concrete subfoundatio

the licensee is to ensure prop

functioning of the de-watering 

through the period of extende

operation.

II.B1.2.CP-46 II.B1.2-

8(C-46)

Steel elements 

(accessible 

areas): 

suppression 

chamber; 

Steel Air – indoor, 

uncontrolled or 

Treated water

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S1, “ASME Sectio

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 

Appendix J”
NUREG-1801, Rev. 2 II B1-8 December 2010

II CONTAINMENT STRUCTURES

B1.2 Mark I Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

drywell; drywell 

head; 

embedded 

shell; region 

shielded by 

diaphragm floor 

(as applicable)

II.B1.2.CP-114 Steel elements 

(inaccessible 

areas): support 

skirt

Steel Concrete None None 

II.B1.2.CP-63 II.B1.2-

8(C-46)

Steel elements 

(inaccessible 

areas): 

suppression 

chamber; 

drywell; drywell 

head; 

embedded 

shell; region 

shielded by 

diaphragm floor 

(as applicable)

Steel Air – indoor, 

uncontrolled or 

Treated water

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S1, “ASME Sectio

Subsection IWE” and 

Chapter XI.S4, “10 CFR Part 

Appendix J” 

Additional plant-specific activ

warranted if loss of material d

corrosion is significant for 

inaccessible areas (embedde

containment steel shell or line

Loss of material due to corros

not significant if the following 

conditions are satisfied: 

1. Concrete meeting the requ

of ACI 318 or 349 and the gu

of 201.2R was used for the co

in contact with the embedded 

containment shell or liner. 

2. The moisture barrier, at the 

junction where the shell or lin

becomes embedded, is subje

aging management activities 

accordance with ASME Sectio
December 2010 II B1-9 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

B1.2 Mark I Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

Subsection IWE requirements

3. The concrete is monitored 

ensure that it is free of penetr

cracks that provide a path for 

seepage to the surface of the 

containment shell or liner. 

4. Borated water spills and wa

ponding on the concrete floor 

common and when detected a

cleaned up or diverted to a su

timely manner. 

Operating experience has ide

significant corrosion in some 

 

If any of the above conditions 

be satisfied, then a plant-spec

aging management program f

corrosion is necessary.

II.B1.2.CP-117 II.B1.2-

8(C-46)

Steel elements: 

downcomer 

pipes

Steel Air – indoor, 

uncontrolled or 

Treated water

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S1, “ASME Sectio

Subsection IWE”

II.B1.2.C-23 II.B1.2-

9(C-23)

Steel elements: 

drywell head; 

downcomers

Steel Air – indoor, 

uncontrolled

Fretting or lockup 

due to mechanical 

wear

Chapter XI.S1, “ASME Sectio

Subsection IWE”

II.B1.2.C-49 II.B1.2-

10(C-49)

Steel elements: 

suppression 

chamber (torus) 

liner (interior 

surface)

Steel; 

stainless 

steel

Air – indoor, 

uncontrolled or 

Treated water

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice corrosion

Chapter XI.S1, “ASME Sectio

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 

Appendix J”

December 2010 II B2-1 NUREG-1801, Rev. 2

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 components (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. 2 II B2-2 December 2010

II CONTAINMENT STRUCTURES

B2.1 Mark II Steel Containments

Item Link 

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

II.B2.1.CP-46 II.B2.1-

1(C-46)

Steel elements 

(accessible 

areas): 

suppression 

chamber; 

drywell; drywell 

head; 

embedded 

shell; region 

shielded by 

diaphragm floor 

(as applicable)

Steel Air – indoor, 

uncontrolled or 

Treated water

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 50

Appendix J”

II.B2.1.CP-114 Steel elements 

(inaccessible 

areas): support 

skirt

Steel Concrete None None 

II.B2.1.CP-63 II.B2.1-

1(C-46)

Steel elements 

(inaccessible 

areas): 

suppression 

chamber; 

drywell; drywell 

head; 

embedded 

shell; region 

shielded by 

diaphragm floor 

(as applicable)

Steel Air – indoor, 

uncontrolled or 

Treated water

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S1, “ASME Section 

Subsection IWE” and 

 

Chapter XI.S4, “10 CFR Part 50

Appendix J” 

 

Additional plant-specific activiti

warranted if loss of material due 

corrosion is significant for inacc

areas (embedded containment 

shell or liner).

 

Loss of material due to corrosio

significant if the following condit

satisfied: 

1. Concrete meeting the require

of ACI 318 or 349 and the guida
December 2010 II B2-3 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

B2.1 Mark II Steel Containments

Item Link 

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

201.2R was used for the concre

contact with the embedded con

shell or liner. 

2. The moisture barrier, at the ju

where the shell or liner become

embedded, is subject to aging 

management activities in accord

with ASME Section XI, Subsect

requirements. 

3. The concrete is monitored to 

that it is free of penetrating crac

provide a path for water seepag

surface of the containment shel

4. Borated water spills and wate

ponding on the concrete floor a

common and when detected are 

cleaned up or diverted to a sum

timely manner. 

Operating experience has ident

significant corrosion in some pla

 

If any of the above conditions c

satisfied, then a plant-specific a

management program for corro

necessary.

II.B2.1.CP-117 II.B2.1-

1(C-46)

Steel elements: 

downcomer 

pipes

Steel Air – indoor, 

uncontrolled or 

Treated water

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S1, “ASME Section 

Subsection IWE”

II.B2.1.C-23 II.B2.1-

2(C-23)

Steel elements: 

drywell head; 

downcomers

Steel Air – indoor, 

uncontrolled

Fretting or 

lockup 

due to 

Chapter XI.S1, “ASME Section 

Subsection IWE”
NUREG-1801, Rev. 2 II B2-4 December 2010

II CONTAINMENT STRUCTURES

B2.1 Mark II Steel Containments

Item Link 

Structure 

and/or 

Component

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

mechanical 

wear

II.B2.1.CP-107 II.B2.1-

3(C-44)

Suppression 

pool shell

Steel; 

stainless 

steel; 

dissimilar 

metal 

welds

Air – indoor, 

uncontrolled or 

Treated Water

Cracking 

due to cyclic 

loading 

(CLB fatigue 

analysis does 

not exist)

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 50

Appendix J”

II.B2.1.C-45 II.B2.1-

4(C-45)

Suppression 

pool shell; 

unbraced 

downcomers

Steel; 

stainless 

steel; 

dissimilar 

metal 

welds

Air – indoor, 

uncontrolled

Cumulative 

fatigue damage 

due to fatigue 

(Only if CLB 

fatigue analysis 

exists)

Fatigue is a time-limited aging a

(TLAA) to be evaluated for the p

extended operation. See the SR

Section 4.6, “Containment Line

and Penetration Fatigue Analys

acceptable methods for meeting 

requirements of 10 CFR 54.21(

II.B2.1.CP-142 II.B2.1-

3(C-44)

Unbraced 

downcomers

Steel; 

stainless 

steel; 

dissimilar 

metal 

welds

Air – indoor, 

uncontrolled or 

Treated water 

Cracking 

due to cyclic 

loading 

(CLB fatigue 

analysis does 

not exist)

Chapter XI.S1, “ASME Section 

Subsection IWE”
December 2010 II B2-5 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

B2.2 Mark II Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

II.B2.2.CP-79 II.B2.2-

2(C-41)

Concrete 

(accessible 

areas): 

basemat; 

reinforcing steel

Concrete; 

steel

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S2, “ASME Section 

Subsection IWL”

II.B2.2.CP-59 II.B2.2-

4(C-39)

Concrete 

(accessible 

areas): 

containment; 

wall; basemat

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Chapter XI.S2, “ASME Section 

Subsection IWL”

II.B2.2.CP-54 II.B2.2-

6(C-31)

Concrete 

(accessible 

areas): 

containment; 

wall; basemat

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Chapter XI.S2, “ASME Section 

Subsection IWL”

II.B2.2.CP-80 II.B2.2-

2(C-41)

Concrete 

(inaccessible 

areas): 

basemat; 

reinforcing steel

Concrete; 

steel

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mo

II.B2.2.CP-99 II.B2.2-

4(C-39)

Concrete 

(inaccessible 

areas): 

containment; 

wall; basemat

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Further evaluation is required t

determine if a plant-specific ag

management program is need

manage cracking and expansio

to reaction with aggregate of c

in Inaccessible Areas. A plant-

aging management program is 
NUREG-1801, Rev. 2 II B2-6 December 2010

II CONTAINMENT STRUCTURES

B2.2 Mark II Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

required if (1) as described in N

1557, investigations, tests, and 

petrographic examinations of 

aggregates performed in accor

with ASTM C295 and other AS

reactivity tests, as required, ca

demonstrate that those aggreg

not adversely react within conc

(2) For potentially reactive agg

aggregate concrete reaction is 

significant if it is demonstrated 

in-place concrete can perform 

intended function.

II.B2.2.CP-110 II.B2.2-

6(C-31)

Concrete 

(inaccessible 

areas): 

containment; 

wall; basemat

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Further evaluation is required t

determine if a plant-specific ag

management program is need

manage increase in porosity, a

permeability due to leaching of 

hydroxide and carbonation of c

in Inaccessible Areas. A plant-

aging management program is 

required if (1) There is evidenc

accessible areas that the flowi

has not caused leaching and 

carbonation, or (2) Evaluation 

determined that the observed l

of calcium hydroxide and carbo

in accessible areas has no imp

the intended function of the co

structure.

II.B2.2.CP-105 II.B2.2-

1(C-06)

Concrete 

elements, all

Concrete Soil Cracking and 

distortion 

due to increased 

Chapter XI.S2, “ASME Section 

Subsection IWL,” or 

Chapter XI.S6, " Structures Mo
December 2010 II B2-7 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

B2.2 Mark II Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

stress levels from 

settlement

If a de-watering system is relie

for control of settlement, then t

licensee is to ensure proper 

functioning of the de-watering 

through the period of extended 

operation. 

II.B2.2.CP-106 II.B2.2-

5(C-26)

Concrete: 

containment; 

wall; basemat

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

due to aggressive 

chemical attack

Chapter XI.S2, “ASME Section 

Subsection IWL,” or 

Chapter XI.S6, " Structures Mo

II.B2.2.CP-57 II.B2.2-

3(C-35)

Concrete: 

containment;

wall; basemat

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Reduction of 

strength and 

modulus 

due to elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging managem

program 

 

The implementation of 10 CFR 

and ASME Section XI, Subsec

would not be able to identify th

reduction of strength and modu

to elevated temperature. Thus

portions of concrete containme

exceed specified temperature 

further evaluations are warrant

Subsection CC-3400 of ASME 

Section III, Division 2, specifies 

concrete temperature limits for 

operation or any other long-ter

period. The temperatures shal

exceed 150°F except for local 

such as around penetrations, w

are not allowed to exceed 200
NUREG-1801, Rev. 2 II B2-8 December 2010

II CONTAINMENT STRUCTURES

B2.2 Mark II Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

significant equipment loads are 

supported by concrete at temp

exceeding 150°F, an evaluatio

ability to withstand the postulat

design loads is to be made. 

 

Higher temperatures than give

may be allowed in the concrete 

and/or calculations are provide

evaluate the reduction in stren

modulus of elasticity, and thes

reductions are applied to the d

calculations.

II.B2.2.C-07 II.B2.2-

7(C-07)

Concrete: 

foundation; 

subfoundation

Concrete; 

porous 

concrete

Water – flowing Reduction of 

foundation 

strength and 

cracking 

due to differential 

settlement and 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Mo

If a de-watering system is relie

for control of erosion of cemen

porous concrete subfoundation

the licensee is to ensure prope

functioning of the de-watering 

through the period of extended 

operation.

II.B2.2.C-11 II.B2.2-

8(C-11)

Prestressing 

system: 

tendons

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of prestress 

due to relaxation; 

shrinkage; creep; 

elevated 

temperature

Loss of tendon prestress is a t

limited aging analysis (TLAA) t

evaluated for the period of exte

operation. 

See the SRP, Section 4.5, “Co

Containment Tendon Prestress

acceptable methods for meetin

requirements of 10 CFR 54.21

and (ii). See Chapter X.S1 of t

report for meeting the requirem

10 CFR 54.21(c)(1)(iii). 
December 2010 II B2-9 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

B2.2 Mark II Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

For periodic monitoring of pres

see Chapter XI.S2.

II.B2.2.C-10 II.B2.2-

9(C-10)

Prestressing 

system: 

tendons; 

anchorage 

components

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to corrosion

Chapter XI.S2, “ASME Section 

Subsection IWL”

II.B2.2.CP-46 II.B2.2-

10(C-46)

Steel elements 

(accessible 

areas): 

suppression 

chamber; 

drywell; drywell 

head; 

embedded 

shell; region 

shielded by 

diaphragm floor 

(as applicable)

Steel Air – indoor, 

uncontrolled or 

Treated water

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J”

II.B2.2.CP-114 Steel elements 

(inaccessible 

areas): support 

skirt

Steel Concrete None None 

II.B2.2.CP-63 II.B2.2-

10(C-46)

Steel elements 

(inaccessible 

areas): 

suppression 

chamber; 

drywell; drywell 

head; 

embedded 

shell; region 

Steel Air – indoor, 

uncontrolled or 

Treated water

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S1, “ASME Section 

Subsection IWE” and 

 

Chapter XI.S4, “10 CFR Part 5

Appendix J” 

 

Additional plant-specific activit

warranted if loss of material du

corrosion is significant for inac
NUREG-1801, Rev. 2 II B2-10 December 2010

II CONTAINMENT STRUCTURES

B2.2 Mark II Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

shielded by 

diaphragm floor 

(as applicable)

areas (embedded containment 

shell or liner).

 

Loss of material due to corrosi

significant if the following cond

are satisfied: 

1. Concrete meeting the requir

of ACI 318 or 349 and the guid

201.2R was used for the concr

contact with the embedded 

containment shell or liner. 

2. The moisture barrier, at the 

where the shell or liner becom

embedded, is subject to aging 

management activities in acco

with ASME Section XI, Subsec

IWE requirements. 

3. The concrete is monitored to 

that it is free of penetrating cra

provide a path for water seepa

the surface of the containment 

liner. 

4. Borated water spills and wat

ponding on the concrete floor a

common and when detected a

cleaned up or diverted to a sum

timely manner. 

Operating experience has ide

significant corrosion in some p

 

If any of the above conditions c

be satisfied, then a plant-speci

management program for corro

necessary.
December 2010 II B2-11 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

B2.2 Mark II Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

II.B2.2.CP-117 II.B2.2-

10(C-46)

Steel elements: 

downcomer 

pipes

Steel Air – indoor, 

uncontrolled or 

Treated water

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S1, “ASME Section 

Subsection IWE”

II.B2.2.C-23 II.B2.2-

11(C-23)

Steel elements: 

drywell head; 

downcomers

Steel Air – indoor, 

uncontrolled

Fretting or lockup 

due to mechanical 

wear

Chapter XI.S1, “ASME Section 

Subsection IWE”

II.B2.2.C-49 II.B2.2-

12(C-49)

Steel elements: 

suppression 

chamber (torus) 

liner (interior 

surface)

Steel; 

stainless 

steel

Air – indoor, 

uncontrolled or 

Treated water

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice corrosion

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J”

II.B2.2.CP-64 II.B2.2-

13(C-47)

Steel elements: 

vent header; 

downcomers

Steel; 

stainless 

steel

Air – indoor, 

uncontrolled or 

Treated water

Cracking 

due to cyclic 

loading 

(CLB fatigue 

analysis does not 

exist)

Chapter XI.S1, “ASME Section 

Subsection IWE”

II.B2.2.C-48 II.B2.2-

14(C-48)

Steel elements: 

vent header; 

downcomers

Steel; 

stainless 

steel

Air – indoor, 

uncontrolled or 

Treated water

Cumulative 

fatigue damage 

due to fatigue 

(Only if CLB 

fatigue analysis 

exists)

Fatigue is a time-limited aging 

(TLAA) to be evaluated for the 

of extended operation. See the 

Section 4.6, “Containment Line

and Penetration Fatigue Analy

acceptable methods for meetin

requirements of 10 CFR 54.21

December 2010 II B3-i NUREG-1801, Rev. 2

B3. MARK III CONTAINMENTS 

B3.1 Steel Containments

B3.2 Concrete Containments

December 2010 II B3-1 NUREG-1801, Rev. 2

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 components (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. 2 II B3-2 December 2010

II CONTAINMENT STRUCTURES

B3.1 Mark III Steel Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

II.B3.1.CP-72 II.B3.1-

1(C-25)

Concrete 

(accessible 

areas): 

basemat

Concrete Ground 

water/soil

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

due to aggressive 

chemical attack

Chapter XI.S2, “ASME Sectio

Subsection IWL,” or 

Chapter XI.S6, " Structures

Monitoring"

II.B3.1.CP-156 II.B3.1-

3(C-30)

Concrete 

(accessible 

areas): 

basemat

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Chapter XI.S2, “ASME Sectio

Subsection IWL”

II.B3.1.CP-66 II.B3.1-

5(C-51)

Concrete 

(accessible 

areas): 

basemat, 

concrete fill-in 

annulus

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Chapter XI.S2, “ASME Sectio

Subsection IWL”

II.B3.1.CP-74 II.B3.1-

6(C-43)

Concrete 

(accessible 

areas): 

basemat; 

reinforcing steel

Concrete; 

steel

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S2, “ASME Sectio

Subsection IWL”

II.B3.1.CP-71 II.B3.1-

1(C-25)

Concrete 

(inaccessible 

areas): 

basemat

Concrete Ground 

water/soil

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

Chapter XI.S2, “ASME Sectio

Subsection IWL,” or 

Chapter XI.S6, " Structures

Monitoring“
December 2010 II B3-3 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

B3.1 Mark III Steel Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

scaling) 

due to aggressive 

chemical attack

II.B3.1.CP-53 II.B3.1-

3(C-30)

Concrete 

(inaccessible 

areas): 

basemat

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Further evaluation is required 

determine if a plant-specific a

management program is need

manage increase in porosity, 

permeability due to leaching o

calcium hydroxide and carbon

concrete in Inaccessible Area

plant-specific aging managem

program is not required if 

(1) There is evidence in the 

accessible areas of adjacent 

structures that the flowing wa

not caused leaching and carb

or 

(2) Evaluation determined tha

observed leaching of calcium 

hydroxide and carbonation in 

accessible areas has no impa

the intended function of the co

structure.

II.B3.1.CP-83 II.B3.1-

5(C-51)

Concrete 

(inaccessible 

areas): 

basemat, 

concrete fill-in 

annulus

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Further evaluation is required 

determine if a plant-specific a

management program is need

manage cracking and expans

to reaction with aggregate of c

in Inaccessible Areas. A plant

aging management program i

required if (1) as described in 

NUREG-1557, investigations, 

and petrographic examination
NUREG-1801, Rev. 2 II B3-4 December 2010

II CONTAINMENT STRUCTURES

B3.1 Mark III Steel Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

aggregates performed in acco

with ASTM C295 and other A

reactivity tests, as required, c

demonstrate that those aggre

not adversely react within con

(2) For potentially reactive 

aggregates, aggregate concre

reaction is not significant if it i

demonstrated that the in-plac

concrete can perform its inten

function.

II.B3.1.CP-75 II.B3.1-

6(C-43)

Concrete 

(inaccessible 

areas): 

basemat; 

reinforcing steel

Concrete; 

steel

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S2, “ASME Sectio

Subsection IWL,” or 

Chapter XI.S6, " Structures

Monitoring"

II.B3.1.CP-69 II.B3.1-

2(C-36)

Concrete: 

basemat

Concrete Soil Cracking and 

distortion 

due to increased 

stress levels from 

settlement

Chapter XI.S2, “ASME Sectio

Subsection IWL,” or 

Chapter XI.S6, " Structures

Monitoring" 

If a de-watering system is reli

for control of settlement, then 

licensee is to ensure proper 

functioning of the de-watering 

through the period of extende

operation. 

II.B3.1.CP-65 II.B3.1-

4(C-50)

Concrete: 

basemat, 

concrete fill-in 

annulus

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Reduction of 

strength and 

modulus 

due to elevated 

temperature 

Plant-specific aging managem

program 

 

The implementation of 

10 CFR 50.55a and ASME Se
December 2010 II B3-5 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

B3.1 Mark III Steel Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

(>150°F general; 

>200°F local)

XI, Subsection IWL would not 

to identify the reduction of stre

and modulus of elasticity due 

elevated temperature. Thus, f

portions of concrete containm

exceed specified temperature 

further evaluations are warran

Subsection CC-3400 of ASME 

Section III, Division 2, specifie

concrete temperature limits fo

operation or any other long-te

period. The temperatures sha

exceed 150°F except for loca

such as around penetrations, 

are not allowed to exceed 200

significant equipment loads a

supported by concrete at 

temperatures exceeding 150°

evaluation of the ability to with

the postulated design loads is 

made. 

 

Higher temperatures than give

above may be allowed in the 

if tests and/or calculations are 

provided to evaluate the redu

strength and modulus of elast

these reductions are applied t

design calculations.

II.B3.1.C-07 II.B3.1-

7(C-07)

Concrete: 

foundation; 

subfoundation

Concrete; 

porous 

concrete

Water – flowing Reduction of 

foundation 

strength and 

cracking 

Chapter XI.S6, “Structures 

Monitoring” 

If a de-watering system is reli

for control of erosion of ceme
NUREG-1801, Rev. 2 II B3-6 December 2010

II CONTAINMENT STRUCTURES

B3.1 Mark III Steel Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

due to differential 

settlement and 

erosion of porous 

concrete 

subfoundation

porous concrete subfoundatio

the licensee is to ensure prop

functioning of the de-watering 

through the period of extende

operation.

II.B3.1.CP-43 II.B3.1-

8(C-19)

Steel elements 

(accessible 

areas): drywell 

shell; drywell 

head

Steel Air – indoor, 

uncontrolled

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S1, “ASME Sectio

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 

Appendix J”

II.B3.1.CP-113 II.B3.1-

8(C-19)

Steel elements 

(inaccessible 

areas): drywell 

shell; drywell 

head; and 

drywell shell

Steel Air – indoor, 

uncontrolled or 

Concrete

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S1, “ASME Sectio

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 

Appendix J”

II.B3.1.C-24 II.B3.1-

9(C-24)

Steel elements: 

suppression 

chamber shell 

(interior 

surface)

Stainless 

steel

Air – indoor, 

uncontrolled

Cracking 

due to stress 

corrosion cracking

Chapter XI.S1, “ASME Sectio

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 

Appendix J”

II.B3.1.CP-158 II.B3.1-

8(C-19)

Steel elements: 

suppression 

chamber shell 

(interior 

surface)

Steel Air – indoor, 

uncontrolled or 

Treated water

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S1, “ASME Sectio

Subsection IWE” 

Plant-specific aging managem

program is required if plant op

experience identified significa

corrosion. If protective coating 

credited for preventing corros

coating should be included in 

of license renewal and subjec

aging management review.
December 2010 II B3-7 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

B3.2 Mark III Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

II.B3.2.CP-84 II.B3.2-

5(C-27)

Concrete 

(accessible 

areas): dome; 

wall; basemat

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor or 

Ground 

water/soil

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

due to aggressive 

chemical attack

Chapter XI.S2, “ASME Sectio

Subsection IWL,” or 

Chapter XI.S6, " Structures

Monitoring"

II.B3.2.CP-52 II.B3.2-

3(C-29)

Concrete 

(accessible 

areas): dome; 

wall; basemat

Concrete Air – outdoor or 

Ground 

water/soil

Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Chapter XI.S2, “ASME Sectio

Subsection IWL”

II.B3.2.CP-60 II.B3.2-

4(C-40)

Concrete 

(accessible 

areas): dome; 

wall; basemat

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Chapter XI.S2, “ASME Sectio

Subsection IWL”

II.B3.2.CP-55 II.B3.2-

6(C-32)

Concrete 

(accessible 

areas): dome; 

wall; basemat

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Chapter XI.S2, “ASME Sectio

Subsection IWL”

II.B3.2.CP-88 II.B3.2-

7(C-42)

Concrete 

(accessible 

areas): dome; 

wall; basemat; 

reinforcing 

steel

Concrete; 

steel

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S2, “ASME Sectio

Subsection IWL”
NUREG-1801, Rev. 2 II B3-8 December 2010

II CONTAINMENT STRUCTURES

B3.2 Mark III Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

II.B3.2.CP-73 II.B3.2-

5(C-27)

Concrete 

(inaccessible 

areas): dome; 

wall; basemat

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor or 

Ground 

water/soil

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

due to aggressive 

chemical attack

Chapter XI.S2, “ASME Sectio

Subsection IWL,” or 

Chapter XI.S6, " Structures

Monitoring"

II.B3.2.CP-135 II.B3.2-

3(C-29)

Concrete 

(inaccessible 

areas): dome; 

wall; basemat

Concrete Air – outdoor or 

Ground 

water/soil

Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Further evaluation is required 

plants that are located in mod

severe weathering conditions 

(weathering index >100 day-in

(NUREG-1557) to determine i

plant-specific aging managem

program is needed. A plant-sp

aging management program is 

required if documented eviden

confirms that the existing conc

had air entrainment content (a

Table CC-2231-2 of the ASME 

Section III Division 2), and 

subsequent inspections of acc

areas did not exhibit degradat

related to freeze-thaw. Such 

inspections should be conside

part of the evaluation. If this c

is not satisfied, then a plant-sp

aging management program is 

required to manage loss of ma

(spalling, scaling) and crackin

freeze-thaw of concrete in 

inaccessible areas. 

The weathering index for the 
December 2010 II B3-9 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

B3.2 Mark III Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

continental US is shown in AS

C33-90, Fig. 1.

II.B3.2.CP-121 II.B3.2-

4(C-40)

Concrete 

(inaccessible 

areas): dome; 

wall; basemat

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Further evaluation is required 

determine if a plant-specific ag

management program is need

manage cracking and expans

to reaction with aggregate of c

in Inaccessible Areas. A plant

aging management program is 

required if (1) as described in 

NUREG-1557, investigations, 

and petrographic examination

aggregates performed in acco

with ASTM C295 and other AS

reactivity tests, as required, ca

demonstrate that those aggre

not adversely react within con

(2) For potentially reactive 

aggregates, aggregate concre

reaction is not significant if it is 

demonstrated that the in-place 

concrete can perform its inten

function.

II.B3.2.CP-122 II.B3.2-

6(C-32)

Concrete 

(inaccessible 

areas): dome; 

wall; basemat

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Further evaluation is required 

determine if a plant-specific ag

management program is need

manage increase in porosity, a

permeability due to leaching o

calcium hydroxide and carbon

concrete in Inaccessible Area

plant-specific aging managem

program is not required if (1) T
NUREG-1801, Rev. 2 II B3-10 December 2010

II CONTAINMENT STRUCTURES

B3.2 Mark III Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

evidence in the accessible are

the flowing water has not caus

leaching and carbonation, or (

Evaluation determined that the 

observed leaching of calcium 

hydroxide and carbonation in 

accessible areas has no impa

intended function of the concr

structure.

II.B3.2.CP-89 II.B3.2-

7(C-42)

Concrete 

(inaccessible 

areas): dome; 

wall; basemat; 

reinforcing 

steel

Concrete; 

steel

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S2, “ASME Sectio

Subsection IWL,” or 

Chapter XI.S6, " Structures

Monitoring"

II.B3.2.CP-105 II.B3.2-

1(C-06)

Concrete 

elements, all

Concrete Soil Cracking and 

distortion 

due to increased 

stress levels from 

settlement

Chapter XI.S2, “ASME Sectio

Subsection IWL,” or 

Chapter XI.S6, " Structures

Monitoring" 

If a de-watering system is relie

for control of settlement, then 

licensee is to ensure proper 

functioning of the de-watering 

through the period of extende

operation. 

II.B3.2.CP-108 II.B3.2-

2(C-33)

Concrete: 

dome; wall; 

basemat

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Reduction of 

strength and 

modulus 

due to elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging managem

program 

The implementation of 10 CFR 

and ASME Section XI, Subsec

IWL would not be able to iden

reduction of strength and mod

elasticity due to elevated temp
December 2010 II B3-11 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

B3.2 Mark III Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

Thus, for any portions of conc

containment that exceed spec

temperature limits, further eva

are warranted. Subsection CC

of ASME Section III, Division 2

specifies the concrete temper

limits for normal operation or a

other long-term period. The 

temperatures shall not exceed 

except for local areas, such as 

penetrations, which are not al

exceed 200°F. If significant eq

loads are supported by concre

temperatures exceeding 150°

evaluation of the ability to with

the postulated design loads is 

made. 

Higher temperatures than give

may be allowed in the concret

and/or calculations are provid

evaluate the reduction in stren

modulus of elasticity and thes

reductions are applied to the d

calculations.

II.B3.2.C-07 II.B3.2-

8(C-07)

Concrete: 

foundation; 

subfoundation

Concrete; 

porous 

concrete

Water – flowing Reduction of 

foundation 

strength and 

cracking 

due to differential 

settlement and 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Mo

If a de-watering system is relie

for control of erosion of cemen

porous concrete subfoundatio

the licensee is to ensure prop

functioning of the de-watering 

through the period of extende

operation.
NUREG-1801, Rev. 2 II B3-12 December 2010

II CONTAINMENT STRUCTURES

B3.2 Mark III Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

II.B3.2.CP-35 II.B3.2-

9(C-09)

Steel elements 

(accessible 

areas): liner; 

liner anchors; 

integral

attachments

Steel Air – indoor, 

uncontrolled

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S1, “ASME Sectio

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J”

II.B3.2.CP-98 II.B3.2-

9(C-09)

Steel elements 

(inaccessible 

areas): liner; 

liner anchors; 

integral 

attachments

Steel Air – indoor, 

uncontrolled

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S1, “ASME Sectio

Subsection IWE” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J” 

Additional plant-specific activit

warranted if loss of material d

corrosion is significant for inac

areas (embedded containmen

shell or liner).

Loss of material due to corros

not significant if the following 

conditions are satisfied: 

1. Concrete meeting the requi

of ACI 318 or 349 and the gui

201.2R was used for the conta

concrete in contact with the 

embedded containment shell 

2. The moisture barrier, at the 

where the shell or liner becom

embedded, is subject to aging 

management activities in acco

with ASME Section XI, Subse

IWE requirements. 

3. The concrete is monitored t

ensure that it is free of penetra

cracks that provide a path for 

seepage to the surface of the 
December 2010 II B3-13 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

B3.2 Mark III Concrete Containments

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

containment shell or liner.

4. Borated water spills and wa

ponding on the concrete floor 

common and when detected a

cleaned up or diverted to a su

timely manner. 

Operating experience has ide

significant corrosion in some p

If any of the above conditions 

be satisfied, then a plant-spec

aging management program f

corrosion is necessary.

II.B3.2.C-24 II.B3.2-

10(C-24)

Steel 

elements: 

suppression 

chamber shell 

(interior 

surface)

Stainless 

steel

Air – indoor, 

uncontrolled

Cracking 

due to stress 

corrosion cracking

Chapter XI.S1, “ASME Sectio

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J”

December 2010 II B4-1 NUREG-1801, Rev. 2

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 components (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. 2 II B4-2 December 2010

II CONTAINMENT STRUCTURES

B4 Common Components

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

II.B4.CP-40 II.B4-7(C18)Moisture 

barriers 

(caulking, 

flashing, and 

other 

sealants)

Elastomers, 

rubber and 

other similar 

materials

Air – indoor, 

uncontrolled

Loss of sealing 

due to wear, 

damage, 

erosion, tear, 

surface cracks, 

or other defects

Chapter XI.S1, “ASME Section 

Subsection IWE”

II.B4.CP-36 II.B4-1(C12)Penetration 

sleeves

Steel; 

dissimilar 

metal welds

Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J” 

II.B4.CP-38 II.B4-2(C15)Penetration 

sleeves; 

penetration 

bellows

Stainless 

steel; 

dissimilar 

metal welds

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to stress 

corrosion 

cracking

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J”

II.B4.CP-37 II.B4-3(C14)penetration 

sleeves; 

penetration 

bellows

Steel; 

stainless 

steel; 

dissimilar 

metal welds

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to cyclic 

loading 

(CLB fatigue 

analysis does 

not exist)

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J”

II.B4.C-13 II.B4-4(C13)Penetration 

sleeves; 

penetration 

bellows

Steel; 

stainless 

steel; 

dissimilar 

metal welds

Air – indoor, 

uncontrolled or 

Air – outdoor

Cumulative 

fatigue damage 

due to fatigue 

(Only if CLB 

fatigue analysis 

exists)

Fatigue is a time-limited aging 

(TLAA) to be evaluated for the 

extended operation. See the S

Section 4.6, “Containment Line

and Penetration Fatigue Analys

acceptable methods for meetin

requirements of 10 CFR 54.21(

II.B4.C-16 II.B4-6(C16)Personnel 

airlock, 

equipment 

hatch, CRD 

hatch

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J”
December 2010 II B4-3 NUREG-1801, Rev. 2

II CONTAINMENT STRUCTURES

B4 Common Components

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

II.B4.CP-39 II.B4-5(C17)Personnel 

airlock, 

equipment 

hatch, CRD 

hatch: locks, 

hinges, and 

closure 

mechanisms

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of leak 

tightness 

due to 

mechanical wear 

of locks, hinges 

and closure 

mechanisms

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J”

II.B4.CP-150 Pressureretaining 

bolting

Any Any 

environment

Loss of preload 

due to selfloosening

Chapter XI.S1, “ASME Section 

Subsection IWE,” and 

Chapter XI.S4, “10 CFR Part 5

Appendix J”

II.B4.CP-148 Pressureretaining 

bolting

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S1, “ASME Section 

Subsection IWE”

II.B4.CP-41 II.B4-7(C18)Seals and 

gaskets

Elastomers, 

rubber and 

other similar 

materials

Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of sealing 

due to wear, 

damage, 

erosion, tear, 

surface cracks, 

or other defects

Chapter XI.S4, “10 CFR Part 5

Appendix J "

II.B4.CP-152 Service Level 

I coatings

Coatings Air – indoor, 

uncontrolled 

Loss of coating 

integrity 

due to blistering, 

cracking, flaking, 

peeling, or 

physical damage

Chapter XI.S8, "Protective Coa

Monitoring and Maintenance"

December 2010 III-i NUREG-1801, Rev. 2

CHAPTER III

STRUCTURES AND COMPONENT SUPPORTS

December 2010 III-iii NUREG-1801, Rev. 2

STRUCTURES AND COMPONENT SUPPORTS

Chapter III A: Safety Related and Other Structures

Safety-related structures are those 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.

December 2010 III A-i NUREG-1801, Rev. 2

III.A SAFETY RELATED AND OTHER STRUCTURES

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

December 2010 III A1-1 NUREG-1801, Rev. 2

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

ROOM/BLDG.)

Systems, Structures, and Components

This section addresses the elements of the 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. 2 III A1-2 December 2010

III STRUCTURES AND COMPONENT SUPPORTS

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

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program (

III.A1.TP25III.A1-2(T03)Concrete 

(accessible 

areas): all

Concrete Any environment Cracking 

due to expansion 

from reaction with

aggregates

Chapter XI.S6, "Structures Moni

III.A1.TP27III.A1-4(T05)Concrete 

(accessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion of 

embedded steel

Chapter XI.S6, "Structures Moni

III.A1.TP23III.A1-6(T01)Concrete 

(accessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freeze-thaw

Chapter XI.S6, "Structures Moni

III.A1.TP24III.A1-7(T02)Concrete 

(accessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Chapter XI.S6, "Structures Moni

III.A1.TP26III.A1-9(T04)Concrete 

(accessible 

areas): interior 

and abovegrade exterior

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion of 

embedded steel

Chapter XI.S6, "Structures Moni

III.A1.TP204III.A1-2(T03)Concrete 

(inaccessible 

areas): all

Concrete Any environment Cracking 

due to expansion 

from reaction with 

aggregates

Further evaluation is required to 

determine if a plant-specific agin

management program is needed 

manage cracking and expansion 
December 2010 III A1-3 NUREG-1801, Rev. 2

III STRUCTURES AND COMPONENT SUPPORTS

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

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program (

reaction with aggregate of concr

Inaccessible Areas. A plant-spec

aging management program is n

required if (1) as described in NU

1557, investigations, tests, and 

petrographic examinations of 

aggregates performed in accord

with ASTM C295 and other AST

reactivity tests, as required, can 

demonstrate that those aggrega

not adversely react within concre

(2) For potentially reactive aggre

aggregate concrete reaction is n

significant if it is demonstrated th

in-place concrete can perform its 

intended function.

III.A1.TP212III.A1-4(T05)Concrete 

(inaccessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion of 

embedded steel

Chapter XI.S6, "Structures Moni

III.A1.TP29III.A1-5(T07)Concrete 

(inaccessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

due to aggressive 

chemical attack

Chapter XI.S6, "Structures Moni

III.A1.TP67III.A1-7(T02)Concrete 

(inaccessible 

areas): exterior 

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

Further evaluation is required to 

determine if a plant-specific agin

management program is needed 
NUREG-1801, Rev. 2 III A1-4 December 2010

III STRUCTURES AND COMPONENT SUPPORTS

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

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program (

above- and 

below-grade; 

foundation

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

manage increase in porosity, an

permeability due to leaching of c

hydroxide and carbonation of co

Inaccessible Areas. A plant-spec

aging management program is n

required if (1) There is evidence 

accessible areas that the flowing 

has not caused leaching and 

carbonation, or (2) Evaluation 

determined that the observed lea

of calcium hydroxide and carbon

accessible areas has no impact 

intended function of the concrete 

structure.

III.A1.TP108III.A1-6(T01)Concrete 

(inaccessible 

areas): 

foundation

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freeze-thaw

Further evaluation is required fo

that are located in moderate to s

weathering conditions (weatherin

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

determine if a plant-specific agin

management program is needed

plant-specific aging managemen

program is not required if docum

evidence confirms that the existi

concrete had air entrainment con

per Table CC-2231-2 of the ASM

Section III Division 2), and subse

inspections of accessible areas d

exhibit degradation related to fre

thaw. Such inspections should b

considered a part of the evaluati

this condition is not satisfied, the

plant-specific aging managemen

program is required to manage l
December 2010 III A1-5 NUREG-1801, Rev. 2

III STRUCTURES AND COMPONENT SUPPORTS

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

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program (

material (spalling, scaling) and c

due to freeze-thaw of concrete in 

inaccessible areas. 

The weathering index for the con

US is shown in ASTM C33-90, F

III.A1.TP114III.A1-1(T10)Concrete: all Concrete Air – indoor, 

uncontrolled

Reduction of 

strength and 

modulus 

due to elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging managemen

program 

 

Subsection CC-3400 of ASME 

Section III, Division 2, and Appe

ACI 349 specifies the concrete 

temperature limits for normal ope

or any other long-term period. Th

temperatures shall not exceed 1

except for local areas, such as a

penetrations, where the tempera

are not allowed to exceed 200°F

significant equipment loads are 

supported by concrete at temper

exceeding 150°F, an evaluation 

ability to withstand the postulate

loads is to be made. 

 

Higher temperatures than those 

above may be allowed in the con

tests and/or calculations are pro

evaluate the reduction in strengt

modulus of elasticity and these 

reductions are applied to the des

calculations.

III.A1.TP30III.A1-3(T08)Concrete: all Concrete Soil Cracking and 

distortion 

due to increased 

Chapter XI.S6, “Structures Moni

If a de-watering system is relied 

control of settlement, then the lic
NUREG-1801, Rev. 2 III A1-6 December 2010

III STRUCTURES AND COMPONENT SUPPORTS

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

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program (

stress levels from 

settlement

is to ensure proper functioning o

watering system through the per

extended operation. 

III.A1.TP31III.A1-8(T09)Concrete: 

foundation; 

subfoundation

Concrete; 

porous 

concrete

Water – flowing 

under foundation

Reduction of 

foundation strength

and cracking 

due to differential 

settlement and 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Moni

If a de-watering system is relied 

control of settlement, then the lic

is to ensure proper functioning o

watering system through the per

extended operation. 

III.A1.TP28III.A1-

10(T-06)

Concrete: 

interior; abovegrade exterior

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

due to aggressive 

chemical attack

Chapter XI.S6, "Structures Moni

III.A1.TP300High-strength 

structural 

bolting

Low-alloy 

steel, actual 

measured 

yield strength 

≥ 150 ksi 

(1,034 MPa)

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to stress 

corrosion cracking

Chapter XI.S6, "Structures Moni

Note: ASTM A 325, F 1852, and 

A 490 bolts used in civil structure

not shown to be prone to SCC. S

potential need not be evaluated 

these bolts.

III.A1.T-12 III.A1-

11(T-12)

Masonry walls: 

all

Concrete 

block

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to restraint 

shrinkage, creep, 

and aggressive 

environment

Chapter XI.S5, “Masonry Walls” 
December 2010 III A1-7 NUREG-1801, Rev. 2

III STRUCTURES AND COMPONENT SUPPORTS

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

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program (

III.A1.TP302III.A1-

12(T-11)

Steel 

components: all 

structural steel

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to corrosion

Chapter XI.S6, “Structures Moni

If protective coatings are relied u

manage the effects of aging, the 

structures monitoring program is 

include provisions to address pro

coating monitoring and maintena

III.A1.TP261Structural 

bolting

Any Any environment Loss of preload 

due to selfloosening

Chapter XI.S6, "Structures Moni

III.A1.TP248Structural 

bolting

Steel Air – indoor, 

uncontrolled 

Loss of material 

due to general, 

pitting and crevice 

corrosion

Chapter XI.S6, "Structures Moni

III.A1.TP274Structural 

bolting

Steel; 

galvanized 

steel

Air – outdoor Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.S6, "Structures Moni

December 2010 III A2-1 NUREG-1801, Rev. 2

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

Systems, Structures, and Components

This section addresses the elements of the 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. 2 III A2-2 December 2010

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 

III.A2.TP-25 III.A2-2(T03)Concrete 

(accessible 

areas): all

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Chapter XI.S6, "Structures Mon

III.A2.TP-27 III.A2-4(T05)Concrete 

(accessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mon

III.A2.TP-23 III.A2-6(T01)Concrete 

(accessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Chapter XI.S6, "Structures Mon

III.A2.TP-24 III.A2-7(T02)Concrete 

(accessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Chapter XI.S6, "Structures Mon

III.A2.TP-26 III.A2-9(T04)Concrete 

(accessible 

areas): interior 

and abovegrade exterior

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mon
December 2010 III A2-3 NUREG-1801, Rev. 2

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 

III.A2.TP-204 III.A2-2(T03)Concrete 

(inaccessible 

areas): all

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Further evaluation is required t

determine if a plant-specific ag

management program is neede

manage cracking and expansio

reaction with aggregate of conc

Inaccessible Areas. A plant-spe

aging management program is 

required if (1) as described in N

1557, investigations, tests, and 

petrographic examinations of 

aggregates performed in accor

with ASTM C295 and other AS

reactivity tests, as required, ca

demonstrate that those aggreg

not adversely react within conc

(2) For potentially reactive agg

aggregate concrete reaction is 

significant if it is demonstrated 

in-place concrete can perform 

intended function.

III.A2.TP-212 III.A2-4(T05)Concrete 

(inaccessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mon

III.A2.TP-29 III.A2-5(T07)Concrete 

(inaccessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

Chapter XI.S6, "Structures Mon
NUREG-1801, Rev. 2 III A2-4 December 2010

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 

due to aggressive 

chemical attack

III.A2.TP-67 III.A2-7(T02)Concrete 

(inaccessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Further evaluation is required t

determine if a plant-specific ag

management program is neede

manage increase in porosity, a

permeability due to leaching of 

hydroxide and carbonation of c

in Inaccessible Areas. A plant-s

aging management program is 

required if (1) There is evidenc

accessible areas that the flowin

has not caused leaching and 

carbonation, or (2) Evaluation 

determined that the observed l

of calcium hydroxide and carbo

in accessible areas has no imp

the intended function of the con

structure.

III.A2.TP-108 III.A2-6(T01)Concrete 

(inaccessible 

areas): 

foundation

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Further evaluation is required f

that are located in moderate to 

weathering conditions (weathe

index >100 day-inch/yr) (NURE

1557) to determine if a plant-sp

aging management program is 

A plant-specific aging managem

program is not required if docu

evidence confirms that the exis

concrete had air entrainment c

(as per Table CC-2231-2 of the 

Section III Division 2), and sub

inspections of accessible areas 
December 2010 III A2-5 NUREG-1801, Rev. 2

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 

exhibit degradation related to fr

thaw. Such inspections should 

considered a part of the evalua

this condition is not satisfied, th

plant-specific aging manageme

program is required to manage 

material (spalling, scaling) and 

due to freeze-thaw of concrete 

inaccessible areas. 

The weathering index for the 

continental US is shown in AST

90, Fig. 1.

III.A2.TP-114 III.A2-1(T10)Concrete: all Concrete Air – indoor, 

uncontrolled

Reduction of 

strength and 

modulus 

due to elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging manageme

program 

 

Subsection CC-3400 of ASME 

Section III, Division 2, and App

of ACI 349 specifies the concre

temperature limits for normal o

or any other long-term period. T

temperatures shall not exceed 

except for local areas, such as 

penetrations, where the tempe

are not allowed to exceed 200°

significant equipment loads are 

supported by concrete at temp

exceeding 150°F, an evaluatio

ability to withstand the postulat

design loads is to be made. 

 

Higher temperatures than thos

above may be allowed in the co

if tests and/or calculations are 
NUREG-1801, Rev. 2 III A2-6 December 2010

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 

to evaluate the reduction in stre

and modulus of elasticity and th

reductions are applied to the de

calculations.

III.A2.TP-30 III.A2-3(T08)Concrete: all Concrete Soil Cracking and 

distortion 

due to increased 

stress levels from 

settlement

Chapter XI.S6, “Structures Mon

If a de-watering system is relie

for control of settlement, then t

licensee is to ensure proper fun

of the de-watering system throu

period of extended operation. 

III.A2.TP-31 III.A2-8(T09)Concrete: 

foundation; 

subfoundation

Concrete; 

porous 

concrete

Water – flowing 

under 

foundation

Reduction of 

foundation 

strength and 

cracking 

due to differential 

settlement and 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Mon

If a de-watering system is relie

for control of settlement, then t

licensee is to ensure proper fun

of the de-watering system throu

period of extended operation. 

III.A2.TP-28 III.A2-

10(T-06)

Concrete: 

interior; abovegrade exterior

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

due to aggressive 

chemical attack

Chapter XI.S6, "Structures Mon

III.A2.TP-300 High-strength 

structural 

bolting

Low-alloy 

steel, actual 

measured 

yield 

strength ≥ 

150 ksi 

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to stress 

corrosion cracking

Chapter XI.S6, "Structures Mon

Note: ASTM A 325, F 1852, an

A 490 bolts used in civil structu

have not shown to be prone to 

SCC potential need not be eva
December 2010 III A2-7 NUREG-1801, Rev. 2

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 

(1,034 MPa) for these bolts.

III.A2.T-12 III.A2-

11(T-12)

Masonry walls: 

all

Concrete 

block

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to restraint 

shrinkage, creep, 

and aggressive 

environment

Chapter XI.S5, “Masonry Walls

III.A2.TP-302 III.A2-

12(T-11)

Steel 

components: 

all structural 

steel

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to corrosion

Chapter XI.S6, “Structures Mon

If protective coatings are relied 

manage the effects of aging, th

structures monitoring program 

include provisions to address p

coating monitoring and mainten

III.A2.TP-261 Structural 

bolting

Any Any 

environment

Loss of preload 

due to selfloosening

Chapter XI.S6, "Structures Mon

III.A2.TP-248 Structural 

bolting

Steel Air – indoor, 

uncontrolled 

Loss of material 

due to general, 

pitting and crevice 

corrosion

Chapter XI.S6, "Structures Mon

III.A2.TP-274 Structural 

bolting

Steel; 

galvanized 

steel

Air – outdoor Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S6, "Structures Mon

December 2010 III A3-1 NUREG-1801, Rev. 2

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 the 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. 2 III A3-2 December 2010

III STRUCTURES AND COMPONENT SUPPORTS

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

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

Startup Towers Circuit Breaker foundation, Electrical Enclosure)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

III.A3.TP-25 III.A3-2(T03)Concrete 

(accessible 

areas): all

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Chapter XI.S6, "Structures Mo

III.A3.TP-27 III.A3-4(T05)Concrete 

(accessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mo

III.A3.TP-23 III.A3-6(T01)Concrete 

(accessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Chapter XI.S6, "Structures Mo

III.A3.TP-24 III.A3-7(T02)Concrete 

(accessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Chapter XI.S6, "Structures Mo

III.A3.TP-26 III.A3-9(T04)Concrete 

(accessible 

areas): interior 

and abovegrade exterior

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mo
December 2010 III A3-3 NUREG-1801, Rev. 2

III STRUCTURES AND COMPONENT SUPPORTS

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

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

Startup Towers Circuit Breaker foundation, Electrical Enclosure)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

III.A3.TP-204 III.A3-2(T03)Concrete 

(inaccessible 

areas): all

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Further evaluation is required t

determine if a plant-specific ag

management program is neede

manage cracking and expansio

to reaction with aggregate of c

in Inaccessible Areas. A plant-

aging management program is 

required if (1) as described in N

1557, investigations, tests, and 

petrographic examinations of 

aggregates performed in accor

with ASTM C295 and other AS

reactivity tests, as required, ca

demonstrate that those aggreg

not adversely react within conc

(2) For potentially reactive agg

aggregate concrete reaction is 

significant if it is demonstrated 

in-place concrete can perform 

intended function.

III.A3.TP-212 III.A3-4(T05)Concrete 

(inaccessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mo

III.A3.TP-29 III.A3-5(T07)Concrete 

(inaccessible 

areas): belowgrade exterior; 

Concrete Ground 

water/soil

Increase in 

porosity and 

permeability; 

cracking; loss of 

Chapter XI.S6, "Structures Mo
NUREG-1801, Rev. 2 III A3-4 December 2010

III STRUCTURES AND COMPONENT SUPPORTS

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

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

Startup Towers Circuit Breaker foundation, Electrical Enclosure)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

foundation material (spalling, 

scaling) 

due to aggressive 

chemical attack

III.A3.TP-67 III.A3-7(T02)Concrete 

(inaccessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Further evaluation is required t

determine if a plant-specific ag

management program is neede

manage increase in porosity, a

permeability due to leaching of 

hydroxide and carbonation of c

in Inaccessible Areas. A plant-

aging management program is 

required if (1) There is evidenc

accessible areas that the flowi

has not caused leaching and 

carbonation, or (2) Evaluation 

determined that the observed l

of calcium hydroxide and carbo

in accessible areas has no imp

the intended function of the co

structure.

III.A3.TP-108 III.A3-6(T01)Concrete 

(inaccessible 

areas): 

foundation

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Further evaluation is required f

that are located in moderate to 

weathering conditions (weathe

index >100 day-inch/yr) (NURE

1557) to determine if a plant-sp

aging management program is 

needed. A plant-specific aging 

management program is not re

documented evidence confirms 

the existing concrete had air 
December 2010 III A3-5 NUREG-1801, Rev. 2

III STRUCTURES AND COMPONENT SUPPORTS

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

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

Startup Towers Circuit Breaker foundation, Electrical Enclosure)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

entrainment content (as per Ta

2231-2 of the ASME Section II

Division 2), and subsequent 

inspections of accessible areas 

exhibit degradation related to f

thaw. Such inspections should 

considered a part of the evalua

this condition is not satisfied, th

plant-specific aging manageme

program is required to manage 

material (spalling, scaling) and 

cracking due to freeze-thaw of 

concrete in inaccessible areas

The weathering index for the 

continental US is shown in AST

90, Fig. 1.

III.A3.TP-114 III.A3-1(T10)Concrete: all Concrete Air – indoor, 

uncontrolled

Reduction of 

strength and 

modulus 

due to elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging managem

program 

 

 Subsection CC-3400 of ASME 

Section III, Division 2, and App

of ACI 349 specifies the concre

temperature limits for normal o

or any other long-term period. 

temperatures shall not exceed 

except for local areas, such as 

penetrations, where the tempe

are not allowed to exceed 200

significant equipment loads are 

supported by concrete at temp

exceeding 150°F, an evaluatio
NUREG-1801, Rev. 2 III A3-6 December 2010

III STRUCTURES AND COMPONENT SUPPORTS

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

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

Startup Towers Circuit Breaker foundation, Electrical Enclosure)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

ability to withstand the postulat

design loads is to be made. 

 

Higher temperatures than thos

above may be allowed in the c

if tests and/or calculations are 

to evaluate the reduction in str

and modulus of elasticity and t

reductions are applied to the d

calculations.

III.A3.TP-30 III.A3-3(T08)Concrete: all Concrete Soil Cracking and 

distortion 

due to increased 

stress levels from 

settlement

Chapter XI.S6, “Structures Mo

If a de-watering system is relie

for control of settlement, then t

licensee is to ensure proper fu

of the de-watering system thro

period of extended operation. 

III.A3.TP-31 III.A3-8(T09)Concrete: 

foundation; 

subfoundation

Concrete; 

porous

concrete

Water – flowing 

under 

foundation

Reduction of 

foundation 

strength and 

cracking 

due to differential 

settlement and 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Mo

If a de-watering system is relie

for control of settlement, then t

licensee is to ensure proper fu

of the de-watering system thro

period of extended operation. 

III.A3.TP-28 III.A3-

10(T-06)

Concrete: 

interior; abovegrade exterior

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

Chapter XI.S6, "Structures Mo
December 2010 III A3-7 NUREG-1801, Rev. 2

III STRUCTURES AND COMPONENT SUPPORTS

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

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

Startup Towers Circuit Breaker foundation, Electrical Enclosure)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

due to aggressive 

chemical attack

III.A3.TP-300 High-strength 

structural 

bolting

Low-alloy 

steel, actual 

measured 

yield 

strength ≥ 

150 ksi 

(1,034 MPa)

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to stress 

corrosion cracking

Chapter XI.S6, "Structures Mo

Note: ASTM A 325, F 1852, an

A 490 bolts used in civil structu

have not shown to be prone to 

SCC potential need not be eva

for these bolts.

III.A3.T-12 III.A3-

11(T-12)

Masonry walls: 

all

Concrete 

block

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to restraint 

shrinkage, creep, 

and aggressive 

environment

Chapter XI.S5, “Masonry Walls

III.A3.TP-302 III.A3-

12(T-11)

Steel 

components: 

all structural 

steel

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to corrosion

Chapter XI.S6, “Structures Mo

If protective coatings are relied 

manage the effects of aging, th

structures monitoring program 

include provisions to address 

protective coating monitoring a

maintenance.

III.A3.TP-219 Steel 

components: 

piles

Steel Ground 

water/soil

Loss of material 

due to corrosion

Chapter XI.S6, "Structures Mo

III.A3.TP-261 Structural 

bolting

Any Any 

environment

Loss of preload 

due to selfloosening

Chapter XI.S6, "Structures Mo
NUREG-1801, Rev. 2 III A3-8 December 2010

III STRUCTURES AND COMPONENT SUPPORTS

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

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

Startup Towers Circuit Breaker foundation, Electrical Enclosure)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

III.A3.TP-248 Structural 

bolting

Steel Air – indoor, 

uncontrolled 

Loss of material 

due to general, 

pitting and crevice 

corrosion

Chapter XI.S6, "Structures Mo

III.A3.TP-274 Structural 

bolting

Steel; 

galvanized 

steel

Air – outdoor Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S6, "Structures Mo
December 2010 III A4-1 NUREG-1801, Rev. 2

A4. GROUP 4 STRUCTURES (CONTAINMENT INTERNAL STRUCTURES, EXCLUDING 

REFUELING CANAL)

Systems, Structures, and Components

This section addresses the elements of the 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. 2 III A4-2 December 2010

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 (

III.A4.TP-25 III.A4-2(T03)Concrete 

(accessible 

areas): all

Concrete Any 

environment

Cracking 

due to 

expansion from 

reaction with 

aggregates

Chapter XI.S6, "Structures Mon

III.A4.TP-26 III.A4-3(T04)Concrete 

(accessible 

areas): 

interior and 

above-grade 

exterior

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking; loss of 

bond; and loss 

of material 

(spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mon

III.A4.TP-204 III.A4-2(T03)Concrete 

(inaccessible 

areas): all

Concrete Any 

environment

Cracking 

due to 

expansion from 

reaction with 

aggregates

Further evaluation is required to 

determine if a plant-specific agin

management program is needed 

manage cracking and expansion 

reaction with aggregate of concr

Inaccessible Areas. A plant-spe

aging management program is n

required if (1) as described in N

1557, investigations, tests, and 

petrographic examinations of 

aggregates performed in accord

with ASTM C295 and other AST

reactivity tests, as required, can 

demonstrate that those aggrega

not adversely react within concr

(2) For potentially reactive aggre

aggregate concrete reaction is n

significant if it is demonstrated th

in-place concrete can perform it

intended function.
December 2010 III A4-3 NUREG-1801, Rev. 2

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 (

III.A4.TP-305 Concrete 

(inaccessible 

areas): 

exterior 

above- and 

below-grade; 

foundation

Concrete Water – flowing Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation

Further evaluation is required to 

determine if a plant-specific agin

management program is needed 

manage increase in porosity, an

permeability due to leaching of c

hydroxide and carbonation of co

in Inaccessible Areas. A plant-sp

aging management program is n

required if (1) There is evidence 

accessible areas that the flowing 

has not caused leaching and 

carbonation, or (2) Evaluation 

determined that the observed le

of calcium hydroxide and carbon

accessible areas has no impact 

intended function of the concrete 

structure.

III.A4.TP-114 III.A4-1(T10)Concrete: all Concrete Air – indoor, 

uncontrolled

Reduction of 

strength and 

modulus 

due to elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging manageme

program 

 

Subsection CC-3400 of ASME 

Section III, Division 2, and Appe

of ACI 349 specifies the concret

temperature limits for normal op

or any other long-term period. T

temperatures shall not exceed 1

except for local areas, such as a

penetrations, where the tempera

are not allowed to exceed 200°F

significant equipment loads are 

supported by concrete at tempe

exceeding 150°F, an evaluation 

ability to withstand the postulate
NUREG-1801, Rev. 2 III A4-4 December 2010

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 (

loads is to be made. 

 

Higher temperatures than those 

above may be allowed in the co

tests and/or calculations are pro

evaluate the reduction in strengt

modulus of elasticity and these 

reductions are applied to the de

calculations.

III.A4.TP-304 Concrete: all Concrete Soil Cracking and 

distortion 

due to increased 

stress levels 

from settlement

Chapter XI.S6, “Structures Moni

If a de-watering system is relied 

for control of settlement, then th

licensee is to ensure proper func

of the de-watering system throu

period of extended operation.

III.A4.TP-28 III.A4-4(T06)Concrete: 

interior; 

above-grade 

exterior

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Increase in 

porosity and 

permeability; 

cracking; loss of 

material 

(spalling, 

scaling) 

due to 

aggressive 

chemical attack

Chapter XI.S6, "Structures Mon

III.A4.TP-300 High-strength 

structural 

bolting

Low-alloy 

steel, actual 

measured 

yield 

strength ≥ 

150 ksi 

(1,034 MPa)

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to stress 

corrosion 

cracking

Chapter XI.S6, "Structures Mon

Note: ASTM A 325, F 1852, and 

A 490 bolts used in civil structur

not shown to be prone to SCC. S

potential need not be evaluated 

these bolts.
December 2010 III A4-5 NUREG-1801, Rev. 2

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 (

III.A4.TP-301 Service Level 

I coatings

Coatings Air – indoor, 

uncontrolled 

Loss of coating 

integrity 

due to blistering, 

cracking, flaking, 

peeling, physical 

damage

Chapter XI.S8, "Protective Coat

Monitoring and Maintenance"

III.A4.TP-35 III.A4-6(T13)Sliding 

surfaces: 

radial beam 

seats in BWR 

drywell

Lubrite; 

Fluorogold; 

Lubrofluor

Air – indoor, 

uncontrolled

Loss of 

mechanical 

function 

due to corrosion, 

distortion, dirt, 

overload, wear

Chapter XI.S6, "Structures Mon

III.A4.TP-302 III.A4-5(T11)Steel 

components: 

all structural 

steel

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to corrosion

Chapter XI.S6, “Structures Moni

If protective coatings are relied u

manage the effects of aging, the 

structures monitoring program is 

include provisions to address pr

coating monitoring and maintena

III.A4.TP-261 Structural 

bolting

Any Any 

environment

Loss of preload 

due to selfloosening

Chapter XI.S6, "Structures Mon

III.A4.TP-248 Structural 

bolting

Steel Air – indoor, 

uncontrolled 

Loss of material 

due to general, 

pitting and 

crevice corrosion

Chapter XI.S6, "Structures Mon

III.A4.TP-274 Structural 

bolting

Steel; 

galvanized 

steel

Air – outdoor Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S6, "Structures Mon

December 2010 III A5-1 NUREG-1801, Rev. 2

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. 2 III A5-2 December 2010

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 

III.A5.TP-25 III.A5-2(T03)Concrete 

(accessible 

areas): all

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Chapter XI.S6, "Structures Mon

III.A5.TP-27 III.A5-4(T05)Concrete 

(accessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mon

III.A5.TP-23 III.A5-6(T01)Concrete 

(accessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Chapter XI.S6, "Structures Mon

III.A5.TP-24 III.A5-7(T02)Concrete 

(accessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Chapter XI.S6, "Structures Mon

III.A5.TP-26 III.A5-9(T04)Concrete 

(accessible 

areas): interior 

and abovegrade exterior

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mon
December 2010 III A5-3 NUREG-1801, Rev. 2

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 

III.A5.TP-204 III.A5-2(T03)Concrete 

(inaccessible 

areas): all

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Further evaluation is required t

determine if a plant-specific ag

management program is neede

manage cracking and expansio

reaction with aggregate of conc

Inaccessible Areas. A plant-spe

aging management program is 

required if (1) as described in N

1557, investigations, tests, and 

petrographic examinations of 

aggregates performed in accor

with ASTM C295 and other AS

reactivity tests, as required, ca

demonstrate that those aggreg

not adversely react within conc

(2) For potentially reactive agg

aggregate concrete reaction is 

significant if it is demonstrated 

in-place concrete can perform 

intended function.

III.A5.TP-212 III.A5-4(T05)Concrete 

(inaccessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mon

III.A5.TP-29 III.A5-5(T07)Concrete 

(inaccessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

Chapter XI.S6, "Structures Mon
NUREG-1801, Rev. 2 III A5-4 December 2010

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 

due to aggressive 

chemical attack

III.A5.TP-67 III.A5-7(T02)Concrete 

(inaccessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Further evaluation is required t

determine if a plant-specific ag

management program is neede

manage increase in porosity, a

permeability due to leaching of 

hydroxide and carbonation of c

in Inaccessible Areas. A plant-s

aging management program is 

required if (1) There is evidenc

accessible areas that the flowin

has not caused leaching and 

carbonation, or (2) Evaluation 

determined that the observed l

of calcium hydroxide and carbo

in accessible areas has no imp

the intended function of the con

structure.

III.A5.TP-108 III.A5-6(T01)Concrete 

(inaccessible 

areas): 

foundation

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Further evaluation is required f

that are located in moderate to 

weathering conditions (weathe

index >100 day-inch/yr) (NURE

1557) to determine if a plant-sp

aging management program is 

A plant-specific aging managem

program is not required if docu

evidence confirms that the exis

concrete had air entrainment c

(as per Table CC-2231-2 of the 

Section III Division 2), and subs

inspections of accessible areas 
December 2010 III A5-5 NUREG-1801, Rev. 2

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 

exhibit degradation related to fr

thaw. Such inspections should 

considered a part of the evalua

this condition is not satisfied, th

plant-specific aging manageme

program is required to manage 

material (spalling, scaling) and 

due to freeze-thaw of concrete 

inaccessible areas. 

The weathering index for the 

continental US is shown in AST

90, Fig. 1.

III.A5.TP-114 III.A5-1(T10)Concrete: all Concrete Air – indoor, 

uncontrolled

Reduction of 

strength and 

modulus 

due to elevated 

temperature 

(>150°F general; 

>200°F local)

Plant-specific aging manageme

program 

 

Subsection CC-3400 of ASME 

Section III, Division 2, and App

of ACI 349 specifies the concre

temperature limits for normal o

or any other long-term period. T

temperatures shall not exceed 

except for local areas, such as 

penetrations, where the tempe

are not allowed to exceed 200°

significant equipment loads are 

supported by concrete at temp

exceeding 150°F, an evaluation 

ability to withstand the postulat

design loads is to be made. 

 

Higher temperatures than those 

above may be allowed in the co

if tests and/or calculations are 
NUREG-1801, Rev. 2 III A5-6 December 2010

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 

to evaluate the reduction in stre

and modulus of elasticity and th

reductions are applied to the de

calculations.

III.A5.TP-30 III.A5-3(T08)Concrete: all Concrete Soil Cracking and 

distortion 

due to increased 

stress levels from 

settlement

Chapter XI.S6, “Structures Mon

If a de-watering system is relied 

for control of settlement, then t

licensee is to ensure proper fun

of the de-watering system throu

period of extended operation. 

III.A5.TP-31 III.A5-8(T09)Concrete: 

foundation; 

subfoundation

Concrete; 

porous 

concrete

Water – flowing 

under 

foundation

Reduction of 

foundation 

strength and 

cracking 

due to differential 

settlement and 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Mon

If a de-watering system is relied 

for control of settlement, then t

licensee is to ensure proper fun

of the de-watering system throu

period of extended operation. 

III.A5.TP-28 III.A5-

10(T-06)

Concrete: 

interior; abovegrade exterior

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

due to aggressive 

chemical attack

Chapter XI.S6, "Structures Mon

III.A5.TP-300 High-strength 

structural 

bolting

Low-alloy 

steel, actual 

measured 

yield 

strength ≥ 

150 ksi 

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to stress 

corrosion cracking

Chapter XI.S6, "Structures Mon

Note: ASTM A 325, F 1852, an

A 490 bolts used in civil structu

have not shown to be prone to 

SCC potential need not be eva
December 2010 III A5-7 NUREG-1801, Rev. 2

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 

(1,034 MPa) for these bolts.

III.A5.T-12 III.A5-

11(T-12)

Masonry walls: 

all

Concrete 

block

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to restraint 

shrinkage, creep, 

and aggressive 

environment

Chapter XI.S5, “Masonry Walls

III.A5.TP-34 Masonry walls: 

all

Concrete 

block

Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Chapter XI.S5, “Masonry Walls

III.A5.TP-302 III.A5-

12(T-11)

Steel 

components: 

all structural 

steel

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to corrosion

Chapter XI.S6, “Structures Mon

If protective coatings are relied 

manage the effects of aging, th

structures monitoring program 

include provisions to address p

coating monitoring and mainten

III.A5.T-14 III.A5-

13(T-14)

Steel 

components: 

fuel pool liner

Stainless 

steel

Treated water 

or Treated 

borated water

Cracking 

due to stress 

corrosion 

cracking; 

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, "Water Chemis

monitoring of the spent fuel poo

level in accordance with techni

specifications and leakage from 

leak chase channels.

III.A5.TP-261 Structural 

bolting

Any Any 

environment

Loss of preload 

due to selfloosening

Chapter XI.S6, "Structures Mon
NUREG-1801, Rev. 2 III A5-8 December 2010

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 

III.A5.TP-248 Structural 

bolting

Steel Air – indoor, 

uncontrolled 

Loss of material 

due to general, 

pitting and crevice 

corrosion

Chapter XI.S6, "Structures Mon

III.A5.TP-274 Structural 

bolting

Steel; 

galvanized 

steel

Air – outdoor Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S6, "Structures Mon
December 2010 III A6-1 NUREG-1801, Rev. 2

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. 2 III A6-2 December 2010

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 

III.A6.TP-38 III.A6-1(T18)Concrete 

(accessible 

areas): all

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor 

or Ground 

water/soil

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S7, “Regulatory G

1.127, Inspection of Water-Co

Structures Associated with N

Power Plants” or the FERC/U

Corp of Engineers dam inspe

and maintenance programs.

III.A6.TP-36 III.A6-5(T15)Concrete 

(accessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Chapter XI.S7, “Regulatory G

1.127, Inspection of Water-Co

Structures Associated with N

Power Plants” or the FERC/U

Corp of Engineers dam inspe

and maintenance programs.

III.A6.TP-37 III.A6-6(T16)Concrete 

(accessible 

areas): exterior 

above- and 

below-grade; 

foundation; 

interior slab

Concrete Water –

flowing

Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Chapter XI.S7, “Regulatory G

1.127, Inspection of Water-Co

Structures Associated with N

Power Plants” or the FERC/U

Corp of Engineers dam inspe

and maintenance programs.

III.A6.TP-104 III.A6-1(T18)Concrete 

(inaccessible 

areas): all

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor 

or Ground 

water/soil

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures 

Monitoring"

III.A6.TP-220 III.A6-2(T17)Concrete 

(inaccessible 

areas): all

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Further evaluation is required 

determine if a plant-specific a

management program is nee

manage cracking and expans

to reaction with aggregate of 

in Inaccessible Areas. A plan
December 2010 III A6-3 NUREG-1801, Rev. 2

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 

aging management program 

required if (1) as described in 

NUREG-1557, investigations

and petrographic examination

aggregates performed in acco

with ASTM C295 and other A

reactivity tests, as required, c

demonstrate that those aggre

do not adversely react within

concrete, or (2) For potentiall

reactive aggregates, aggrega

concrete reaction is not signif

is demonstrated that the in-pl

concrete can perform its inten

function.

III.A6.TP-107 III.A6-3(T19)Concrete 

(inaccessible 

areas): all

Concrete Ground 

water/soil

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

due to aggressive 

chemical attack

Chapter XI.S6, "Structures 

Monitoring"

III.A6.TP-110 III.A6-5(T15)Concrete 

(inaccessible 

areas): exterior 

above- and 

below-grade; 

foundation; 

interior slab

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Further evaluation is required 

plants that are located in mod

severe weathering conditions 

(weathering index >100 day-i

(NUREG-1557) to determine 

plant-specific aging managem

program is needed. A plant-s

aging management program 

required if documented evide

confirms that the existing con
NUREG-1801, Rev. 2 III A6-4 December 2010

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 

had air entrainment content (

Table CC-2231-2 of the ASM

Section III Division 2), and 

subsequent inspections of ac

areas did not exhibit degrada

related to freeze-thaw. Such 

inspections should be consid

part of the evaluation. If this c

is not satisfied, then a plant-s

aging management program 

required to manage loss of m

(spalling, scaling) and crackin

freeze-thaw of concrete in 

inaccessible areas. 

The weathering index for the 

continental US is shown in AS

C33-90, Fig. 1.

III.A6.TP-109 III.A6-6(T16)Concrete 

(inaccessible 

areas): exterior 

above- and 

below-grade; 

foundation; 

interior slab

Concrete Water –

flowing

Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Further evaluation is required 

determine if a plant-specific a

management program is nee

manage increase in porosity, 

permeability due to leaching o

calcium hydroxide and carbo

concrete in Inaccessible Area

plant-specific aging managem

program is not required if (1) 

evidence in the accessible ar

the flowing water has not cau

leaching and carbonation, or 

Evaluation determined that th

observed leaching of calcium 

hydroxide and carbonation in 

accessible areas has no impa
December 2010 III A6-5 NUREG-1801, Rev. 2

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 

the intended function of the c

structure.

III.A6.TP-30 III.A6-4(T08)Concrete: all Concrete Soil Cracking and 

distortion 

due to increased 

stress levels from 

settlement

Chapter XI.S6, “Structures 

Monitoring” 

If a de-watering system is reli

for control of settlement, then 

licensee is to ensure proper 

functioning of the de-watering 

through the period of extende

operation. 

III.A6.T-20 III.A6-7(T20)Concrete: 

exterior aboveand below-grade; 

foundation; 

interior slab

Concrete Water –

flowing

Loss of material 

due to abrasion; 

cavitation

Chapter XI.S7, “Regulatory G

1.127, Inspection of Water-Co

Structures Associated with N

Power Plants” or the FERC/U

Corp of Engineers dam inspe

and maintenance programs.

III.A6.TP-31 III.A6-8(T09)Concrete: 

foundation; 

subfoundation

Concrete; 

porous 

concrete

Water –

flowing under 

foundation

Reduction of 

foundation 

strength and 

cracking 

due to differential 

settlement and 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures 

Monitoring” 

If a de-watering system is reli

for control of settlement, then 

licensee is to ensure proper 

functioning of the de-watering 

through the period of extende

operation. 

III.A6.T-22 III.A6-9(T22)Earthen watercontrol 

structures: dams; 

embankments; 

reservoirs; 

channels; canals 

and ponds

Various Water –

flowing or 

standing

Loss of material; 

loss of form 

due to erosion, 

settlement, 

sedimentation, 

frost action, 

waves, currents, 

Chapter XI.S7, “Regulatory G

1.127, Inspection of Water-Co

Structures Associated with N

Power Plants” or the FERC/U

Corp of Engineers dam inspe

and maintenance programs.
NUREG-1801, Rev. 2 III A6-6 December 2010

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 

surface runoff, 

seepage

III.A6.TP-223 Group 6: 

Wooden Piles; 

sheeting

Wood Air – outdoor 

or Water – 

flowing or 

standing or 

Ground 

water/soil

Loss of material; 

change in material 

properties 

due to 

weathering, 

chemical 

degradation, and 

insect infestation 

repeated wetting 

and drying, fungal 

decay

Chapter XI.S7, “Regulatory G

1.127, Inspection of Water-Co

Structures Associated with N

Power Plants” or the FERC/U

Corp of Engineers dam inspe

and maintenance programs.

III.A6.T-12 III.A6-

10(T-12)

Masonry walls: 

all

Concrete 

block

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to restraint 

shrinkage, creep, 

and aggressive 

environment

Chapter XI.S5, “Masonry Wa

III.A6.TP-7 III.A6-

12(TP-7)

Seals; gasket; 

moisture barriers 

(caulking, 

flashing, and 

other sealants)

Elastomers 

(such as 

EPDM 

rubber)

Various Loss of sealing 

due to 

deterioration of 

seals, gaskets, 

and moisture 

barriers (caulking, 

flashing, and 

other sealants)

Chapter XI.S6, "Structures 

Monitoring"

III.A6.TP-261 Structural bolting Any Any 

environment

Loss of preload 

due to selfloosening

Chapter XI.S6, "Structures 

Monitoring"
December 2010 III A6-7 NUREG-1801, Rev. 2

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 

III.A6.TP-248 Structural bolting Steel Air – indoor, 

uncontrolled 

Loss of material 

due to general, 

pitting and crevice 

corrosion

Chapter XI.S6, "Structures 

Monitoring"

III.A6.TP-221 Structural bolting Steel Air – indoor, 

uncontrolled or 

Air – outdoor 

or Water – 

flowing or 

standing

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S7, “Regulatory G

1.127, Inspection of Water-Co

Structures Associated with N

Power Plants” or the FERC/U

Corp of Engineers dam inspe

and maintenance programs.

December 2010 III A7-1 NUREG-1801, Rev. 2

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. 2 III A7-2 December 2010

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 

III.A7.TP-25 III.A7-1(T03)Concrete 

(accessible 

areas): all

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Chapter XI.S6, "Structures Mon

III.A7.TP-27 III.A7-3(T05)Concrete 

(accessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mon

III.A7.TP-23 III.A7-5(T01)Concrete 

(accessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Chapter XI.S6, "Structures Mon

III.A7.TP-24 III.A7-6(T02)Concrete 

(accessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Chapter XI.S6, "Structures Mon

III.A7.TP-26 III.A7-8(T04)Concrete 

(accessible 

areas): interior 

and abovegrade exterior

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mon
December 2010 III A7-3 NUREG-1801, Rev. 2

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 

III.A7.TP-204 III.A7-1(T03)Concrete 

(inaccessible

areas): all

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Further evaluation is required t

determine if a plant-specific ag

management program is neede

manage cracking and expansio

reaction with aggregate of conc

Inaccessible Areas. A plant-spe

aging management program is 

required if (1) as described in N

1557, investigations, tests, and 

petrographic examinations of 

aggregates performed in accor

with ASTM C295 and other AS

reactivity tests, as required, ca

demonstrate that those aggreg

not adversely react within conc

(2) For potentially reactive agg

aggregate concrete reaction is 

significant if it is demonstrated 

in-place concrete can perform 

intended function.

III.A7.TP-212 III.A7-3(T05)Concrete 

(inaccessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mon

III.A7.TP-29 III.A7-4(T07)Concrete 

(inaccessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

Chapter XI.S6, "Structures Mon
NUREG-1801, Rev. 2 III A7-4 December 2010

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 

due to aggressive 

chemical attack

III.A7.TP-67 III.A7-6(T02)Concrete 

(inaccessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Further evaluation is required t

determine if a plant-specific ag

management program is neede

manage increase in porosity, a

permeability due to leaching of 

hydroxide and carbonation of c

in Inaccessible Areas. A plant-s

aging management program is 

required if (1) There is evidenc

accessible areas that the flowin

has not caused leaching and 

carbonation, or (2) Evaluation 

determined that the observed l

of calcium hydroxide and carbo

in accessible areas has no imp

the intended function of the con

structure.

III.A7.TP-108 III.A7-5(T01)Concrete 

(inaccessible 

areas): 

foundation

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Further evaluation is required f

that are located in moderate to 

weathering conditions (weathe

index >100 day-inch/yr) (NURE

1557) to determine if a plant-sp

aging management program is 

A plant-specific aging managem

program is not required if docu

evidence confirms that the exis

concrete had air entrainment c

(as per Table CC-2231-2 of the 

Section III Division 2), and subs

inspections of accessible areas 
December 2010 III A7-5 NUREG-1801, Rev. 2

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 

exhibit degradation related to fr

thaw. Such inspections should 

considered a part of the evalua

this condition is not satisfied, th

plant-specific aging manageme

program is required to manage 

material (spalling, scaling) and 

due to freeze-thaw of concrete 

inaccessible areas. 

The weathering index for the 

continental US is shown in AST

90, Fig. 1.

III.A7.TP-30 III.A7-2(T08)Concrete: all Concrete Soil Cracking and 

distortion 

due to increased 

stress levels from 

settlement

Chapter XI.S6, “Structures Mon

If a de-watering system is relied 

for control of settlement, then t

licensee is to ensure proper fun

of the de-watering system throu

period of extended operation. 

III.A7.TP-31 III.A7-7(T09)Concrete: 

foundation; 

subfoundation

Concrete; 

porous 

concrete

Water – flowing 

under 

foundation

Reduction of 

foundation 

strength and 

cracking 

due to differential 

settlement and 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Mon

If a de-watering system is relied 

for control of settlement, then t

licensee is to ensure proper fun

of the de-watering system throu

period of extended operation. 

III.A7.TP-28 III.A7-9(T06)Concrete: 

interior; abovegrade exterior

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

Chapter XI.S6, "Structures Mon
NUREG-1801, Rev. 2 III A7-6 December 2010

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 

due to aggressive 

chemical attack

III.A7.TP-300 High-strength 

structural 

bolting

Low-alloy 

steel, actual 

measured 

yield 

strength ≥ 

150 ksi 

(1,034 MPa)

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to stress 

corrosion cracking

Chapter XI.S6, "Structures Mon

Note: ASTM A 325, F 1852, an

A 490 bolts used in civil structu

have not shown to be prone to 

SCC potential need not be eva

for these bolts.

III.A7.TP-302 III.A7-

10(T-11)

Steel 

components: 

all structural 

steel

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to corrosion

Chapter XI.S6, “Structures Mon

If protective coatings are relied 

manage the effects of aging, th

structures monitoring program 

include provisions to address p

coating monitoring and mainten

III.A7.T-23 III.A7-

11(T-23)

Steel 

components: 

tank liner

Stainless 

steel

Water – 

standing

Cracking 

due to stress 

corrosion 

cracking; 

Loss of material 

due to pitting and 

crevice corrosion

A plant-specific aging managem

program is to be evaluated.

III.A7.TP-261 Structural 

bolting

Any Any 

environment

Loss of preload 

due to selfloosening

Chapter XI.S6, "Structures Mon

III.A7.TP-248 Structural 

bolting

Steel Air – indoor, 

uncontrolled 

Loss of material 

due to general, 

pitting and crevice 

corrosion

Chapter XI.S6, "Structures Mon
December 2010 III A7-7 NUREG-1801, Rev. 2

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 

III.A7.TP-274 Structural 

bolting

Steel; 

galvanized 

steel

Air – outdoor Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S6, "Structures Mon

December 2010 III A8-1 NUREG-1801, Rev. 2

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. 2 III A8-2 December 2010

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 

III.A8.TP-25 III.A8-1(T03)Concrete 

(accessible 

areas): all

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Chapter XI.S6, "Structures Mon

III.A8.TP-27 III.A8-3(T05)Concrete 

(accessible 

areas): belowgrade exterior; 

foundation

Concrete Ground

water/soil

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mon

III.A8.TP-23 III.A8-5(T01)Concrete 

(accessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Chapter XI.S6, "Structures Mon

III.A8.TP-24 III.A8-6(T02)Concrete 

(accessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Chapter XI.S6, "Structures Mon

III.A8.TP-204 III.A8-1(T03)Concrete 

(inaccessible 

areas): all

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Further evaluation is required t

determine if a plant-specific ag

management program is neede

manage cracking and expansio

reaction with aggregate of conc

Inaccessible Areas. A plant-spe

aging management program is 

required if (1) as described in N
December 2010 III A8-3 NUREG-1801, Rev. 2

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 

1557, investigations, tests, and 

petrographic examinations of 

aggregates performed in accor

with ASTM C295 and other AS

reactivity tests, as required, ca

demonstrate that those aggreg

not adversely react within conc

(2) For potentially reactive agg

aggregate concrete reaction is 

significant if it is demonstrated 

in-place concrete can perform 

intended function.

III.A8.TP-212 III.A8-3(T05)Concrete 

(inaccessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mon

III.A8.TP-29 III.A8-4(T07)Concrete 

(inaccessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

due to aggressive

chemical attack

Chapter XI.S6, "Structures Mon

III.A8.TP-67 III.A8-6(T02)Concrete 

(inaccessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

Further evaluation is required t

determine if a plant-specific ag

management program is neede

manage increase in porosity, a

permeability due to leaching of 

hydroxide and carbonation of c
NUREG-1801, Rev. 2 III A8-4 December 2010

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 

and carbonation in Inaccessible Areas. A plant-s

aging management program is 

required if (1) There is evidenc

accessible areas that the flowin

has not caused leaching and 

carbonation, or (2) Evaluation 

determined that the observed l

of calcium hydroxide and carbo

in accessible areas has no imp

the intended function of the con

structure.

III.A8.TP-108 III.A8-5(T01)Concrete 

(inaccessible 

areas): 

foundation

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Further evaluation is required f

that are located in moderate to 

weathering conditions (weathe

index >100 day-inch/yr) (NURE

1557) to determine if a plant-sp

aging management program is 

A plant-specific aging managem

program is not required if docu

evidence confirms that the exis

concrete had air entrainment c

(as per Table CC-2231-2 of the 

Section III Division 2), and subs

inspections of accessible areas 

exhibit degradation related to fr

thaw. Such inspections should 

considered a part of the evalua

this condition is not satisfied, th

plant-specific aging manageme

program is required to manage 

material (spalling, scaling) and 

due to freeze-thaw of concrete 

inaccessible areas. 
December 2010 III A8-5 NUREG-1801, Rev. 2

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 

The weathering index for the 

continental US is shown in AST

90, Fig. 1.

III.A8.TP-30 III.A8-2(T08)Concrete: all Concrete Soil Cracking and 

distortion 

due to increased 

stress levels from 

settlement

Chapter XI.S6, “Structures Mon

If a de-watering system is relied 

for control of settlement, then t

licensee is to ensure proper fun

of the de-watering system throu

period of extended operation. 

III.A8.TP-31 III.A8-7(T09)Concrete: 

foundation; 

subfoundation

Concrete; 

porous 

concrete

Water – flowing 

under 

foundation

Reduction of 

foundation 

strength and 

cracking 

due to differential 

settlement and 

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Mon

If a de-watering system is relied 

for control of settlement, then t

licensee is to ensure proper fun

of the de-watering system throu

period of extended operation. 

III.A8.TP-300 High-strength 

structural

bolting

Low-alloy 

steel, actual 

measured 

yield 

strength ≥ 

150 ksi 

(1,034 MPa)

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to stress 

corrosion cracking

Chapter XI.S6, "Structures Mon

Note: ASTM A 325, F 1852, an

A 490 bolts used in civil structu

have not shown to be prone to 

SCC potential need not be eva

for these bolts.

III.A8.TP-302 III.A8-8(T11)Steel 

components: 

all structural 

steel

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to corrosion

Chapter XI.S6, “Structures Mon

If protective coatings are relied 

manage the effects of aging, th

structures monitoring program 

include provisions to address p

coating monitoring and mainten
NUREG-1801, Rev. 2 III A8-6 December 2010

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 

III.A8.T-23 III.A8-9(T23)Steel 

components: 

tank liner

Stainless 

steel

Water –

standing

Cracking 

due to stress 

corrosion 

cracking; 

Loss of material 

due to pitting and 

crevice corrosion

A plant-specific aging managem

program is to be evaluated.

III.A8.TP-261 Structural 

bolting

Any Any 

environment

Loss of preload 

due to selfloosening

Chapter XI.S6, "Structures Mon

III.A8.TP-248 Structural 

bolting

Steel Air – indoor, 

uncontrolled 

Loss of material 

due to general, 

pitting and crevice 

corrosion

Chapter XI.S6, "Structures Mon

III.A8.TP-274 Structural 

bolting

Steel; 

galvanized 

steel

Air – outdoor Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S6, "Structures Mon
December 2010 III A9-1 NUREG-1801, Rev. 2

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. 2 III A9-2 December 2010

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 

III.A9.TP-25 III.A9-1(T03)Concrete 

(accessible 

areas): all

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Chapter XI.S6, "Structures Mon

III.A9.TP-27 III.A9-3(T05)Concrete 

(accessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mon

III.A9.TP-23 III.A9-5(T01)Concrete 

(accessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Chapter XI.S6, "Structures Mon

III.A9.TP-24 III.A9-6(T02)Concrete 

(accessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Chapter XI.S6, "Structures Mon

III.A9.TP-26 III.A9-8(T04)Concrete 

(accessible 

areas): interior 

and abovegrade exterior

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mon
December 2010 III A9-3 NUREG-1801, Rev. 2

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 

III.A9.TP-204 III.A9-1(T03)Concrete 

(inaccessible 

areas): all

Concrete Any 

environment

Cracking 

due to expansion 

from reaction with 

aggregates

Further evaluation is required t

determine if a plant-specific ag

management program is neede

manage cracking and expansio

reaction with aggregate of conc

Inaccessible Areas. A plant-spe

aging management program is 

required if (1) as described in N

1557, investigations, tests, and 

petrographic examinations of 

aggregates performed in accor

with ASTM C295 and other AS

reactivity tests, as required, ca

demonstrate that those aggreg

not adversely react within conc

(2) For potentially reactive agg

aggregate concrete reaction is 

significant if it is demonstrated 

in-place concrete can perform 

intended function.

III.A9.TP-212 III.A9-3(T05)Concrete 

(inaccessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Cracking; loss of 

bond; and loss of 

material (spalling, 

scaling) 

due to corrosion 

of embedded 

steel

Chapter XI.S6, "Structures Mon

III.A9.TP-29 III.A9-4(T07)Concrete 

(inaccessible 

areas): belowgrade exterior; 

foundation

Concrete Ground 

water/soil

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

Chapter XI.S6, "Structures Mon
NUREG-1801, Rev. 2 III A9-4 December 2010

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 

due to aggressive 

chemical attack

III.A9.TP-67 III.A9-6(T02)Concrete 

(inaccessible 

areas): exterior 

above- and 

below-grade; 

foundation

Concrete Water – flowing Increase in 

porosity and 

permeability; loss 

of strength 

due to leaching of 

calcium hydroxide 

and carbonation

Further evaluation is required t

determine if a plant-specific ag

management program is neede

manage increase in porosity, a

permeability due to leaching of 

hydroxide and carbonation of c

in Inaccessible Areas. A plant-s

aging management program is 

required if (1) There is evidenc

accessible areas that the flowin

has not caused leaching and 

carbonation, or (2) Evaluation 

determined that the observed l

of calcium hydroxide and carbo

in accessible areas has no imp

the intended function of the con

structure.

III.A9.TP-108 III.A9-5(T01)Concrete 

(inaccessible 

areas): 

foundation

Concrete Air – outdoor Loss of material 

(spalling, scaling) 

and cracking 

due to freezethaw

Further evaluation is required f

that are located in moderate to 

weathering conditions (weathe

index >100 day-inch/yr) (NURE

1557) to determine if a plant-sp

aging management program is 

A plant-specific aging managem

program is not required if docu

evidence confirms that the exis

concrete had air entrainment c

(as per Table CC-2231-2 of the 

Section III Division 2), and sub

inspections of accessible areas 
December 2010 III A9-5 NUREG-1801, Rev. 2

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 

exhibit degradation related to fr

thaw. Such inspections should 

considered a part of the evalua

this condition is not satisfied, th

plant-specific aging manageme

program is required to manage 

material (spalling, scaling) and 

due to freeze-thaw of concrete 

inaccessible areas. 

The weathering index for the 

continental US is shown in AST

90, Fig. 1.

III.A9.TP-30 III.A9-2(T08)Concrete: all Concrete Soil Cracking and 

distortion 

due to increased 

stress levels from 

settlement

Chapter XI.S6, “Structures Mon

If a de-watering system is relie

for control of settlement, then t

licensee is to ensure proper fun

of the de-watering system thro

period of extended operation. 

III.A9.TP-31 III.A9-7(T09)Concrete: 

foundation; 

subfoundation

Concrete; 

porous 

concrete

Water – flowing 

under 

foundation

Reduction in 

foundation 

strength, cracking 

due to differential 

settlement,

erosion of porous 

concrete 

subfoundation

Chapter XI.S6, “Structures Mon

If a de-watering system is relie

for control of settlement, then t

licensee is to ensure proper fun

of the de-watering system thro

period of extended operation. 

III.A9.TP-28 III.A9-9(T06)Concrete: 

interior; abovegrade exterior

Concrete Air – indoor, 

uncontrolled or 

Air – outdoor

Increase in 

porosity and 

permeability; 

cracking; loss of 

material (spalling, 

scaling) 

due to aggressive 

Chapter XI.S6, "Structures Mon
NUREG-1801, Rev. 2 III A9-6 December 2010

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 

chemical attack

III.A9.TP-300 High-strength 

structural 

bolting

Low-alloy 

steel, actual 

measured 

yield 

strength ≥ 

150 ksi 

(1,034 MPa)

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to stress 

corrosion cracking

Chapter XI.S6, "Structures Mon

Note: ASTM A 325, F 1852, an

A 490 bolts used in civil structu

have not shown to be prone to 

SCC potential need not be eva

for these bolts.

III.A9.TP-261 Structural 

bolting

Any Any 

environment

Loss of preload 

due to selfloosening

Chapter XI.S6, "Structures Mon

III.A9.TP-248 Structural 

bolting

Steel Air – indoor, 

uncontrolled 

Loss of material 

due to general,

pitting and crevice 

corrosion

Chapter XI.S6, "Structures Mon

III.A9.TP-274 Structural 

bolting

Steel; 

galvanized 

steel

Air – outdoor Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S6, "Structures Mon
December 2010 III B-i NUREG-1801, Rev. 2

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

 

December 2010 III B1-i NUREG-1801, Rev. 2

B1. SUPPORTS FOR ASME PIPING AND COMPONENTS 

B1.1 Class 1

B1.2 Class 2 and 3

B1.3 Class MC (BWR Containment Supports) 

December 2010 III B1-1 NUREG-1801, Rev. 2

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. 2 III B1-2 December 201

0

III STRUCTURES AND COMPONENT SUPPORTS

B1.1 Class 1

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

III.B1.1.TP-42 III.B1.1-

1(T-29)

Building 

concrete at 

locations of 

expansion 

and grouted 

anchors; 

grout pads for 

support base 

plates

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"

III.B1.1.T-28 III.B1.1-

2(T-28)

Constant and 

variable load 

spring 

hangers; 

guides; stops

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of 

mechanical 

function 

due to corrosion, 

distortion, dirt, 

overload, fatigue 

due to vibratory 

and cyclic 

thermal loads

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.1.TP-41 III.B1.1-

3(T-27)

High-strength 

structural 

bolting

Low-alloy 

steel, actual 

measured 

yield strength 

≥ 150 ksi 

(1,034 MPa)

Air – indoor, 

uncontrolled

Cracking 

due to stress 

corrosion 

cracking

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.1.TP-45 III.B1.1-

5(T-32)

Sliding 

surfaces

Lubrite®; 

graphitic tool 

steel; 

Fluorogold; 

Lubrofluor

Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of 

mechanical 

function 

due to corrosion, 

distortion, dirt, 

debris, overload, 

wear

Chapter XI.S3, “ASME Sectio

Subsection IWF”
December 2010 III B1-3 NUREG-1801, Rev. 2

III STRUCTURES AND COMPONENT SUPPORTS

B1.1 Class 1

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

III.B1.1.TP-229 Structural 

bolting

Any Any 

environment

Loss of preload 

due to selfloosening

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.1.TP-232 Structural 

bolting

Stainless steel Treated water Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, “Water Chem

and 

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.1.TP-226 Structural 

Bolting

Steel Air – indoor, 

uncontrolled 

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.1.TP-235 Structural 

bolting

Steel; 

galvanized 

steel

Air – outdoor Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.1.TP-8 III.B1.1-

6(TP-8)

III.B1.1-

7(TP-11)

III.B1.1-

9(TP-5)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Aluminum; 

galvanized 

steel; stainless 

steel

Air – indoor, 

uncontrolled

None None 

III.B1.1.TP-3 III.B1.1-

8(TP-3)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel; 

aluminum

Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”
NUREG-1801, Rev. 2 III B1-4 December 201

0

III STRUCTURES AND COMPONENT SUPPORTS

B1.1 Class 1

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

III.B1.1.TP-4 III.B1.1-

10(TP-4)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless steel Air with borated 

water leakage

None None 

III.B1.1.T-26 III.B1.1-

12(T-26)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor, 

uncontrolled

Cumulative 

fatigue damage 

due to fatigue 

(Only if CLB 

fatigue analysis 

exists)

Fatigue is a time-limited aging 

analysis (TLAA) to be evalua

the period of extended opera

the SRP, Section 4.3 “Metal F

for acceptable methods for m

the requirements of 10 CFR 

54.21(c)(1).

III.B1.1.T-24 III.B1.1-

13(T-24)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to general 

and pitting 

corrosion

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.1.T-25 III.B1.1-

14(T-25)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”
December 2010 III B1-5 NUREG-1801, Rev. 2

III STRUCTURES AND COMPONENT SUPPORTS

B1.1 Class 1

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

III.B1.1.TP-10 III.B1.1-

11(TP-10)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel; 

stainless steel

Treated water 

<60C (<140 F)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice corrosion

Chapter XI.M2, “Water Chem

BWR water, and 

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.1.T-33 III.B1.1-

15(T-33)

Vibration 

isolation 

elements

Non-metallic 

(e.g., rubber)

Air – indoor, 

uncontrolled or 

Air – outdoor

Reduction or 

loss of isolation 

function 

due to radiation 

hardening, 

temperature, 

humidity, 

sustained 

vibratory loading

Chapter XI.S3, “ASME Sectio

Subsection IWF”
NUREG-1801, Rev. 2 III B1-6 December 201

0

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 

III.B1.2.TP-42 III.B1.2-

1(T-29) 

Building 

concrete at 

locations of 

expansion 

and grouted 

anchors; 

grout pads for 

support base 

plates

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"

III.B1.2.T-28 III.B1.2-

2(T-28)

Constant and 

variable load 

spring 

hangers; 

guides; stops

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of 

mechanical 

function 

due to corrosion, 

distortion, dirt, 

overload, fatigue 

due to vibratory 

and cyclic 

thermal loads

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.2.TP-45 III.B1.2-

3(T-32)

Sliding 

surfaces

Lubrite®; 

graphitic tool 

steel; 

Fluorogold; 

Lubrofluor

Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of 

mechanical 

function 

due to corrosion, 

distortion, dirt, 

debris, overload, 

wear

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.2.TP-229 Structural 

bolting

Any Any 

environment

Loss of preload 

due to selfloosening

Chapter XI.S3, “ASME Sectio

Subsection IWF”
December 2010 III B1-7 NUREG-1801, Rev. 2

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 

III.B1.2.TP-232 Structural 

bolting

Stainless steel Treated water Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, “Water Chem

and 

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.2.TP-226 Structural 

Bolting

Steel Air – indoor, 

uncontrolled 

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.2.TP-235 Structural 

bolting

Steel;

galvanized 

steel

Air – outdoor Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.2.TP-8 III.B1.2-

4(TP-8)

III.B1.2-

5(TP-11)

III.B1.2-

7(TP-5)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Aluminum; 

galvanized 

steel; stainless 

steel

Air – indoor, 

uncontrolled

None None 

III.B1-2.TP-3 III.B1.2-

6(TP-3)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel; 

aluminum

Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

III.B1.2.TP-4 III.B1.2-

8(TP-4)

Support 

members; 

welds; bolted 

connections; 

support 

Stainless steel Air with borated 

water leakage

None None 
NUREG-1801, Rev. 2 III B1-8 December 201

0

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 

anchorage to 

building 

structure

III.B1.2.T-26 III.B1.2-

9(T-26)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor, 

uncontrolled

Cumulative 

fatigue damage 

due to fatigue 

(Only if CLB 

fatigue analysis 

exists)

Fatigue is a time-limited aging 

analysis (TLAA) to be evalua

the period of extended opera

the SRP, Section 4.3 “Metal F

for acceptable methods for m

the requirements of 10 CFR 

54.21(c)(1).

III.B1.2.T-24 III.B1.2-

10(T-24)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to general 

and pitting 

corrosion

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.2.T-25 III.B1.2-

11(T-25)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

III.B1.2.T-33 III.B1.2-

12(T-33)

Vibration 

isolation 

elements

Non-metallic 

(e.g., rubber)

Air – indoor, 

uncontrolled or 

Air – outdoor

Reduction or 

loss of isolation 

function 

due to radiation 

hardening, 

temperature, 

Chapter XI.S3, “ASME Sectio

Subsection IWF”
December 2010 III B1-9 NUREG-1801, Rev. 2

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 

humidity, 

sustained 

vibratory loading
NUREG-1801, Rev. 2 III B1-10 December 201

0

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 

III.B1.3.TP-42 III.B1.3-

1(T-29)

Building 

concrete at 

locations of 

expansion 

and grouted 

anchors; 

grout pads for 

support base 

plates

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"

III.B1.3.T-28 III.B1.3-

2(T-28)

Constant and 

variable load 

spring 

hangers; 

guides; stops

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of 

mechanical 

function 

due to corrosion, 

distortion, dirt, 

overload, fatigue 

due to vibratory 

and cyclic 

thermal loads

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.3.TP-45 III.B1.3-

3(T-32)

Sliding 

surfaces

Lubrite®; 

graphitic tool

steel; 

Fluorogold; 

Lubrofluor

Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of 

mechanical 

function 

due to corrosion, 

distortion, dirt, 

debris, overload, 

wear

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.3.TP-229 Structural 

bolting

Any Any 

environment

Loss of preload 

due to selfloosening

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.3.TP-232 Structural 

bolting

Stainless steel Treated water Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, “Water Chem

and 

Chapter XI.S3, “ASME Sectio

Subsection IWF”
December 2010 III B1-11 NUREG-1801, Rev. 2

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 

III.B1.3.TP-226 Structural 

bolting

Steel Air – indoor, 

uncontrolled 

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.3.TP-235 Structural 

bolting

Steel; 

galvanized 

steel

Air – outdoor Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1-3.TP-8 III.B1.3-

4(TP-8)

III.B1.3-

5(TP-11)

III.B1.3-

7(TP-5)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Aluminum; 

galvanized 

steel; stainless 

steel

Air – indoor, 

uncontrolled

None None 

III.B1.3.TP-3 III.B1.3-

6(TP-3)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel; 

aluminum

Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

III.B1.3.TP-4 III.B1.3-

8(TP-4)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless steel Air with borated 

water leakage

None None 
NUREG-1801, Rev. 2 III B1-12 December 201

0

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 

III.B1.3.T-26 III.B1.3-

9(T-26)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor, 

uncontrolled

Cumulative 

fatigue damage 

due to fatigue 

(Only if CLB 

fatigue analysis 

exists)

Fatigue is a time-limited aging 

analysis (TLAA) to be evalua

the period of extended opera

the SRP, Section 4.3 “Metal F

for acceptable methods for m

the requirements of 10 CFR 

54.21(c)(1).

III.B1.3.T-24 III.B1.3-

10(T-24)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to general 

and pitting 

corrosion

Chapter XI.S3, “ASME Sectio

Subsection IWF”

III.B1.3.T-33 III.B1.3-

11(T-33)

Vibration 

isolation 

elements

Non-metallic 

(e.g., rubber)

Air – indoor, 

uncontrolled or 

Air – outdoor

Reduction or 

loss of isolation 

function 

due to radiation 

hardening, 

temperature, 

humidity, 

sustained 

vibratory loading

Chapter XI.S3, “ASME Sectio

Subsection IWF”
December 2010 III B2-1 NUREG-1801, Rev. 2

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. 2 III B2-2 December 2010

III STRUCTURES AND COMPONENT SUPPORTS

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

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

III.B2.TP-42 III.B2-1(T29)Building 

concrete at 

locations of 

expansion 

and grouted 

anchors; grout 

pads for 

support base 

plates

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"

III.B2.TP-300 High-strength 

structural 

bolting

Low-alloy 

steel, actual 

measured 

yield 

strength ≥ 

150 ksi 

(1,034 MPa)

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to stress 

corrosion 

cracking

Chapter XI.S6, "Structures 

Monitoring“ 

Note: ASTM A 325, F 1852, a

ASTM A 490 bolts used in civ

structures have not shown to 

prone to SCC. SCC potential 

be evaluated for these bolts.

III.B2.TP-46 III.B2-

2(TP-1)

Sliding 

support 

bearings; 

sliding 

support 

surfaces

Lubrite®; 

graphitic tool 

steel; 

Fluorogold; 

Lubrofluor

Air – indoor, 

uncontrolled

Loss of 

mechanical 

function 

due to corrosion, 

distortion, dirt, 

debris, overload, 

wear

Chapter XI.S6, "Structures 

Monitoring"

III.B2.TP-47 III.B2-

3(TP-2)

Sliding 

support 

bearings; 

sliding 

support 

surfaces

Lubrite®; 

graphitic tool 

steel; 

Fluorogold; 

Lubrofluor

Air – outdoor Loss of 

mechanical 

function 

due to corrosion, 

distortion, dirt, 

debris, overload,

wear

Chapter XI.S6, "Structures 

Monitoring"
December 2010 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 Compone

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

III.B2.TP-261 Structural 

bolting

Any Any 

environment

Loss of preload 

due to selfloosening

Chapter XI.S6, "Structures 

Monitoring"

III.B2.TP-248 Structural 

bolting

Steel Air – indoor, 

uncontrolled 

Loss of material 

due to general, 

pitting and 

crevice corrosion

Chapter XI.S6, "Structures 

Monitoring"

III.B2.TP-274 Structural 

bolting

Steel; 

galvanized 

steel

Air – outdoor Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S6, "Structures 

Monitoring"

III.B2.TP-8 III.B2-

4(TP-8)

III.B2-

8(TP-5)

III.B2-

5(TP-11)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Aluminum; 

galvanized 

steel; 

stainless 

steel

Air – indoor, 

uncontrolled

None None 

III.B2.TP-3 III.B2-

6(TP-3)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel; 

aluminum

Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

III.B2.TP-6 III.B2-

7(TP-6)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

Galvanized 

steel; 

aluminum; 

stainless 

steel

Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.S6, "Structures 

Monitoring"
NUREG-1801, Rev. 2 III B2-4 December 2010

III STRUCTURES AND COMPONENT SUPPORTS

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

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

building 

structure

III.B2.TP-4 III.B2-

9(TP-4)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless 

steel

Air with borated 

water leakage

None None 

III.B2.TP-43 III.B2-

10(T-30)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to general 

and pitting 

corrosion

Chapter XI.S6, "Structures 

Monitoring"

III.B2.T-25 III.B2-

11(T-25)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”
December 2010 III B3-1 NUREG-1801, Rev. 2

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. 2 III B3-2 December 2010

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 

III.B3.TP-42 III.B3-1(T29)Building 

concrete at 

locations of 

expansion 

and grouted 

anchors; grout 

pads for 

support base 

plates

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"

III.B3.TP-300 High-strength 

structural 

bolting

Low-alloy 

steel, actual 

measured 

yield 

strength ≥ 

150 ksi 

(1,034 MPa)

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to stress 

corrosion 

cracking

Chapter XI.S6, "Structures 

Monitoring“ 

Note: ASTM A 325, F 1852, a

ASTM A 490 bolts used in civ

structures have not shown to 

prone to SCC. SCC potential 

be evaluated for these bolts.

III.B3.TP-261 Structural 

bolting

Any Any 

environment

Loss of preload 

due to selfloosening

Chapter XI.S6, "Structures 

Monitoring"

III.B3.TP-248 Structural 

bolting

Steel Air – indoor, 

uncontrolled 

Loss of material 

due to general, 

pitting and 

crevice corrosion

Chapter XI.S6, "Structures 

Monitoring"

III.B3.TP-274 Structural 

bolting

Steel; 

galvanized 

steel

Air – outdoor Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S6, "Structures 

Monitoring"

III.B3.TP-8 III.B3-

2(TP-8)

III.B3-

5(TP-5)

Support 

members; 

welds; bolted 

connections; 

Aluminum; 

galvanized 

steel; 

stainless 

Air – indoor, 

uncontrolled

None None 
December 2010 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 

III.B3-

3(TP-11)

support 

anchorage to 

building 

structure

steel

III.B3.TP-3 III.B3-

4(TP-3)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel; 

aluminum

Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

III.B3.TP-4 III.B3-

6(TP-4)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless 

steel

Air with borated 

water leakage

None None 

III.B3.TP-43 III.B3-7(T30)Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to general 

and pitting 

corrosion

Chapter XI.S6, "Structures 

Monitoring"

III.B3.T-25 III.B3-8(T25)Support 

members; 

welds; bolted 

connections; 

support 

Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”
NUREG-1801, Rev. 2 III B3-4 December 2010

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 

anchorage to 

building 

structure
December 2010 III B4-1 NUREG-1801, Rev. 2

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. 2 III B4-2 December 2010

III STRUCTURES AND COMPONENT SUPPORTS

B4 Supports for Emergency Diesel Generator (EDG), HVAC System Components, and Other Miscellaneous Mechanic

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progra

(AMP)

III.B4.TP-42 III.B4-1(T29)Building 

concrete at 

locations of 

expansion 

and grouted 

anchors; 

grout pads for 

support base 

plates

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"

III.B4.TP-300 High-strength 

structural 

bolting

Low-alloy 

steel, actual 

measured 

yield strength 

≥ 150 ksi 

(1,034 MPa)

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to stress 

corrosion 

cracking

Chapter XI.S6, "Structures 

Monitoring“ 

Note: ASTM A 325, F 1852, a

ASTM A 490 bolts used in civ

structures have not shown to 

prone to SCC. SCC potential 

not be evaluated for these bo

III.B4.TP-46 III.B4-

2(TP-1)

Sliding 

support 

bearings; 

sliding 

support 

surfaces

Lubrite®; 

graphitic tool 

steel; 

Fluorogold; 

Lubrofluor

Air – indoor, 

uncontrolled

Loss of 

mechanical 

function 

due to corrosion, 

distortion, dirt, 

debris, overload, 

wear

Chapter XI.S6, "Structures 

Monitoring"

III.B4.TP-47 III.B4-

3(TP-2)

Sliding 

support 

bearings; 

sliding 

support 

surfaces

Lubrite®; 

graphitic tool 

steel; 

Fluorogold; 

Lubrofluor

Air – outdoor Loss of 

mechanical 

function 

due to corrosion, 

distortion, dirt, 

debris, overload, 

wear

Chapter XI.S6, "Structures 

Monitoring"
December 2010 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 Mechanic

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progra

(AMP)

III.B4.TP-261 Structural 

bolting

Any Any 

environment

Loss of preload 

due to selfloosening 

Chapter XI.S6, "Structures 

Monitoring"

III.B4.TP-248 Structural 

bolting

Steel Air – indoor, 

uncontrolled 

Loss of material 

due to general, 

pitting and 

crevice corrosion

Chapter XI.S6, "Structures 

Monitoring"

III.B4.TP-274 Structural 

bolting

Steel; 

galvanized 

steel

Air – outdoor Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S6, "Structures 

Monitoring"

III.B4.TP-8 III.B4-

4(TP-8)

III.B4-

8(TP-5)

III.B4-

5(TP-11)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Aluminum; 

galvanized 

steel; stainless 

steel

Air – indoor, 

uncontrolled

None None 

III.B4.TP-3 III.B4-

6(TP-3)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel; 

aluminum

Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

III.B4.TP-6 III.B4-

7(TP-6)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

Galvanized 

steel; 

aluminum; 

stainless steel

Air – outdoor Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.S6, "Structures 

Monitoring"
NUREG-1801, Rev. 2 III B4-4 December 2010

III STRUCTURES AND COMPONENT SUPPORTS

B4 Supports for Emergency Diesel Generator (EDG), HVAC System Components, and Other Miscellaneous Mechanic

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progra

(AMP)

building 

structure

III.B4.TP-4 III.B4-

9(TP-4)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless steel Air with borated 

water leakage

None None 

III.B4.TP-43 III.B4-

10(T-30)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to general 

and pitting 

corrosion

Chapter XI.S6, "Structures 

Monitoring"

III.B4.T-25 III.B4-

11(T-25)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

III.B4.TP-44 III.B4-

12(T-31)

Vibration 

isolation 

elements

Non-metallic 

(e.g., rubber)

Air – indoor, 

uncontrolled or 

Air – outdoor

Reduction or 

loss of isolation 

function 

due to radiation 

hardening, 

temperature, 

Chapter XI.S3, “ASME Sectio

Subsection IWF”
December 2010 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 Mechanic

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progra

(AMP)

humidity, 

sustained 

vibratory loading

December 2010 III B5-1 NUREG-1801, Rev. 2

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. 2 III B5-2 December 2010

III STRUCTURES AND COMPONENT SUPPORTS

B5 Supports for Platforms, Pipe Whip Restraints, Jet Impingement Shields, Masonry Walls, and Other Miscellaneous 

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

III.B5.TP-42 III.B5-1(T29)Building 

concrete at 

locations of 

expansion 

and grouted 

anchors; grout 

pads for 

support base 

plates

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"

III.B5.TP-300 High-strength 

structural 

bolting

Low-alloy 

steel, actual 

measured 

yield 

strength ≥ 

150 ksi 

(1,034 MPa)

Air – indoor, 

uncontrolled or 

Air – outdoor

Cracking 

due to stress 

corrosion 

cracking

Chapter XI.S6, "Structures 

Monitoring“ 

Note: ASTM A 325, F 1852, a

ASTM A 490 bolts used in civ

structures have not shown to 

prone to SCC. SCC potential 

be evaluated for these bolts.

III.B5.TP-261 Structural 

bolting

Any Any 

environment

Loss of preload 

due to selfloosening

Chapter XI.S6, "Structures 

Monitoring"

III.B5.TP-248 Structural 

bolting

Steel Air – indoor, 

uncontrolled 

Loss of material 

due to general, 

pitting and 

crevice corrosion

Chapter XI.S6, "Structures 

Monitoring"

III.B5.TP-274 Structural 

bolting

Steel; 

galvanized 

steel

Air – outdoor Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.S6, "Structures 

Monitoring"

III.B5.TP-8 III.B5-

2(TP-8)

III.B5-

5(TP-5)

Support 

members; 

welds; bolted 

connections; 

Aluminum; 

galvanized 

steel; 

stainless 

Air – indoor, 

uncontrolled

None None 
December 2010 III B5-3 NUREG-1801, Rev. 2

III STRUCTURES AND COMPONENT SUPPORTS

B5 Supports for Platforms, Pipe Whip Restraints, Jet Impingement Shields, Masonry Walls, and Other Miscellaneous 

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

III.B5-

3(TP-11)

support 

anchorage to 

building 

structure

steel

III.B5.TP-3 III.B5-

4(TP-3)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Galvanized 

steel; 

aluminum

Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

III.B5.TP-4 III.B5-

6(TP-4)

Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Stainless 

steel

Air with borated 

water leakage

None None 

III.B5.TP-43 III.B5-7(T30) Support 

members; 

welds; bolted 

connections; 

support 

anchorage to 

building 

structure

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to general 

and pitting 

corrosion

Chapter XI.S6, "Structures 

Monitoring"

III.B5.T-25 III.B5-8(T25)Support 

members; 

welds; bolted 

connections; 

support 

Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”
NUREG-1801, Rev. 2 III B5-4 December 2010

III STRUCTURES AND COMPONENT SUPPORTS

B5 Supports for Platforms, Pipe Whip Restraints, Jet Impingement Shields, Masonry Walls, and Other Miscellaneous 

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

anchorage to 

building 

structure
December 2010 IV-i NUREG-1801, Rev. 2

CHAPTER IV

REACTOR VESSEL, INTERNALS, AND REACTOR 

COOLANT SYSTEM 

December 2010 IV-iii NUREG-1801, Rev. 2

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

December 2010 IV A1-1 NUREG-1801, Rev. 2

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 period of extended 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 

the standby liquid control system (VII.E2).
NUREG-1801, Rev. 2 IV A1-2 December 2010

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 

IV.A1.R-68 IV.A1-1(R68)Nozzle safe ends 

and welds: highpressure 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 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M7, “BWR Stress 

Corrosion Cracking,” and 

Chapter XI.M2, “Water Chemis

IV.A1.R-66 IV.A1-2(R66)Nozzles: control 

rod drive return 

line

Steel (with 

or without 

stainless 

steel 

cladding)

Reactor coolant Cracking 

due to cyclic 

loading

Chapter XI.M6, “BWR Control 

Drive Return Line Nozzle”

IV.A1.R-65 IV.A1-3(R65)Nozzles: 

feedwater

Steel (with 

or without 

stainless 

steel 

cladding)

Reactor coolant Cracking 

due to cyclic 

loading

Chapter XI.M5, “BWR Feedwa

Nozzle”
December 2010 IV A1-3 NUREG-1801, Rev.2 

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 

IV.A1.R-67 IV.A1-4(R67)Nozzles: lowpressure coolant 

injection or RHR 

injection mode

Steel Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Neutron irradiation embrittleme

time-limited aging analysis (TL

be evaluated for the period of 

extended operation for all ferri

materials that have a neutron f

greater than 1E17 n/cm2 (E >1 

at the end of the period of exte

operation. In accordance with 

approved BWRVIP-74, the TLA

evaluate the impact of neutron 

embrittlement on: (a) the adjus

reference temperature values 

calculation of the plant’s press

temperature limits, (b) the nee

inservice inspection of circumf

welds, and (c) the Charpy upp

energy or the equivalent marg

analyses performed in accorda

with 10 CFR Part 50, Appendix 

applicant may choose to demo

that the materials of the nozzle

not controlling for the TLAA 

evaluations. See the Standard 

Plan, Section 4.2 “Reactor Ves

Neutron Embrittlement” for acc

methods for meeting the requi

of 10 CFR 54.21(c).
NUREG-1801, Rev. 2 IV A1-4 December 2010

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 

IV.A1.RP-369 IV.A1-5(R69)Penetrations: 

control rod drive 

stub tubes; in 

core monitor 

housings; jet 

pump instrument; 

standby liquid 

control; flux 

monitor

Stainless 

steel; 

nickel alloy

Reactor coolant Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, cyclic 

loading

Chapter XI.M8, “BWR Penetra

and 

Chapter XI.M2, “Water Chemis

IV.A1.RP-371 IV.A1-5(R69)Penetrations: 

drain line

Stainless 

steel; 

nickel alloy

Reactor coolant Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, cyclic 

loading

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD,” and 

Chapter XI.M2, “Water Chemis

IV.A1.R-70 IV.A1-6(R70)Pressure vessel 

support skirt and 

attachment welds

Steel Air – indoor, 

uncontrolled

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a time-limited aging 

(TLAA) to be evaluated for the 

of extended operation. See the 

Section 4.3 “Metal Fatigue,” fo

acceptable methods for meetin

requirements of 10 CFR 54.21

IV.A1.R-04 IV.A1-7(R04)Reactor vessel 

components: 

flanges; nozzles; 

penetrations; safe 

ends; thermal 

sleeves; vessel 

shells, heads and 

welds 

Steel (with 

or without 

nickel-alloy 

or 

stainless 

steel 

cladding); 

stainless 

steel; 

nickel alloy

Reactor coolant Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA evaluated fo

period of extended operation, 

Class 1 components environm

effects on fatigue are to be ad

(See SRP, Sec 4.3 “Metal Fati

acceptable methods to comply 

CFR 54.21(c)(1))
December 2010 IV A1-5 NUREG-1801, Rev.2 

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 

IV.A1.RP-157 IV.A1-

8(RP-25)

Reactor Vessel: 

flanges; nozzles; 

penetrations; safe 

ends; vessel 

shells, heads and 

welds

Steel (with 

stainless 

steel or 

nickel-alloy 

cladding); 

stainless 

steel; 

nickel alloy

Reactor coolant Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemis

and 

Chapter XI.M32, “One-Time 

Inspection”

IV.A1.RP-50 IV.A1-

11(R-59)

Top head 

enclosure 

(without

cladding): top 

head; nozzles 

(vent, top head 

spray or RCIC, 

and spare)

Steel Reactor coolant Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.M2, “Water Chemis

and 

Chapter XI.M32, “One-Time 

Inspection”

IV.A1.RP-51 IV.A1-9(R60)Top head 

enclosure: 

closure studs and 

nuts

Highstrength, 

low-alloy 

steel

Air with reactor 

coolant leakage

Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M3, “Reactor Head 

Closure Stud Bolting”

IV.A1.RP-201 Top head 

enclosure: 

closure studs and 

nuts

Highstrength, 

low-alloy 

steel

Air with reactor 

coolant leakage

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a time-limited aging 

(TLAA) to be evaluated for the 

of extended operation. See the 

Section 4.3 “Metal Fatigue,” fo

acceptable methods for meetin

requirements of 10 CFR 54.21
NUREG-1801, Rev. 2 IV A1-6 December 2010

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 

IV.A1.RP-165 Top head 

enclosure: 

closure studs and 

nuts

Highstrength, 

low-alloy 

steel

Air with reactor 

coolant leakage 

Loss of material 

due to general, 

pitting, and 

crevice corrosion, 

or wear

Chapter XI.M3, “Reactor Head 

Closure Stud Bolting”

IV.A1.R-61 IV.A1-

10(R-61)

Top head 

enclosure: vessel 

flange leak 

detection line

Stainless 

steel; 

nickel alloy

Air with reactor 

coolant leakage 

(Internal); or 

reactor coolant

Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

A plant-specific aging manage

program is to be evaluated be

existing programs may not be 

of mitigating or detecting crack 

initiation and growth due to SC

vessel flange leak detection lin

IV.A1.RP-227 IV.A1-

14(R-63)

Vessel shell 

(including 

applicable 

beltline) 

components: 

shell; shell plates 

or forgings; shell 

welds; nozzle 

plates or forgings; 

nozzle welds 

Steel (with 

or without 

cladding)

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M31, “Reactor Ves

Surveillance”

IV.A1.R-64 IV.A1-

12(R-64)

Vessel shell: 

attachment welds

Stainless 

steel; 

nickel alloy

Reactor coolant Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M4, “BWR Vessel 

Attachment Welds,” and 

Chapter XI.M2, “Water Chemis
December 2010 IV A1-7 NUREG-1801, Rev.2 

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 

IV.A1.R-62 IV.A1-

13(R-62)

Vessel shell: 

intermediate 

beltline shell; 

beltline welds

Steel (with 

or without 

stainless 

steel 

cladding)

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Neutron irradiation embrittleme

time-dependent aging mechan

evaluated for extended operat

all ferritic materials that have a 

neutron fluence >1E17 n/cm2 (

>1 MeV) at the end of the peri

extended operation. Aspects m

involve a TLAA. 

In accordance with approved 

BWRVIP-74, the TLAA evalua

impact of neutron embrittleme

(a) adjusted reference tempera

values used for calculation of t

plant’s pressure-temperature l

need for inservice inspection o

circumferential welds, and (c) 

upper shelf energy or the equi

margins analyses performed in 

accordance with 10 CFR Part 

Appendix G. Additionally, the a

is to monitor axial beltline weld 

embrittlement. One acceptable 

method is to determine that th

RTNDT of the axial beltline we

the end of the extended period 

operation is less than the valu

specified by the staff in its Mar

2000 letter (ADAMS ML03143

See the Standard Review Plan

Section 4.2 “Reactor Vessel N

Embrittlement” for acceptable 

for meeting the requirements o

CFR 54.21(c).

December 2010 IV A2-1 NUREG-1801, Rev. 2

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 period of extended 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. 2 IV A2-2 December 2010

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 

IV.A2.RP-154 IV.A2-

1(RP-13)

Bottommounted 

instrument 

guide tube 

(external to 

bottom head)

Stainless 

steel

Reactor coolant Cracking 

due to stress 

corrosion 

cracking

A plant-specific aging manage

program is to be evaluated

IV.A2.RP-52 IV.A2-2(R71)Closure head: 

stud assembly

Highstrength, 

low-alloy 

steel

Air with reactor 

coolant leakage

Cracking 

due to stress 

corrosion 

cracking

Chapter XI.M3, “Reactor Head 

Closure Stud Bolting”

IV.A2.RP-54 IV.A2-4(R73)Closure head: 

stud assembly

Highstrength, 

low-alloy 

steel

Air with reactor 

coolant leakage

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluat

the period of extended operat

the SRP, Section 4.3 “Metal F

for acceptable methods for me

the requirements of 10 CFR 

54.21(c)(1).

IV.A2.RP-53 IV.A2-3(R72)Closure head: 

stud assembly

Highstrength, 

low-alloy 

steel

Air with reactor 

coolant leakage

Loss of material 

due to general, 

pitting, and 

crevice corrosion, 

or wear

Chapter XI.M3, “Reactor Head 

Closure Stud Bolting”

IV.A2.R-74 IV.A2-5(R74)Closure head: 

vessel flange 

leak detection 

line

Stainless 

steel

Air with reactor 

coolant leakage 

(Internal); or 

reactor coolant

Cracking 

due to stress 

corrosion 

cracking

A plant-specific aging manage

program is to be evaluated be

existing programs may not be 

of mitigating or detecting crac

initiation and growth due to SC

the vessel flange leak detectio

IV.A2.R-80 IV.A2-8(R80)Control rod 

drive head 

penetration:

Flange bolting

Stainless 

steel

Air (with reactor 

coolant 

leakage)

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integ
December 2010 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 

IV.A2.R-78 IV.A2-6(R78)Control rod 

drive head 

penetration: 

flange bolting

Stainless 

steel

Air with reactor 

coolant leakage

Cracking 

due to stress 

corrosion 

cracking

Chapter XI.M18, "Bolting Integ

IV.A2.R-79 IV.A2-7(R79)Control rod 

drive head 

penetration: 

flange bolting

Stainless 

steel

Air with reactor 

coolant leakage

Loss of material 

due to wear

Chapter XI.M18, "Bolting Integ

IV.A2.RP-186 IV.A2-9(R75)Control rod 

drive head 

penetration: 

nozzle welds

Nickel alloy Reactor coolant Cracking 

due to primary 

water stress 

corrosion 

cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M11B, “Cracking o

Alloy Components and Loss o

Material Due to Boric Acid-Ind

Corrosion in RCPB Compone

(PWRs Only)"

IV.A2.R-77 IV.A2-

10(R-77)

Control rod 

drive head 

penetration: 

pressure 

housing

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C 

(>482°F)

Loss of fracture 

toughness 

due to thermal 

aging 

embrittlement

Chapter XI.M12, "Thermal Ag

Embrittlement of Cast Austeni

Stainless Steel (CASS)"

IV.A2.RP-55 IV.A2-

11(R-76)

Control rod 

drive head 

penetration: 

pressure 

housing

Stainless 

steel; nickel 

alloy

Reactor coolant Cracking 

due to stress 

corrosion 

cracking, primary 

water stress 

corrosion 

cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chemi
NUREG-1801, Rev. 2 IV A2-4 December 2010

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 

IV.A2.RP-57 IV.A2-

12(R-88)

Core support 

pads; core 

guide lugs

Nickel alloy Reactor coolant Cracking 

due to primary 

water stress 

corrosion 

cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chemi

IV.A2.R-17 IV.A2-

13(R-17)

External 

surfaces

Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

IV.A2.RP-379 IV.A2-

13(R-17)

External 

surfaces: 

reactor vessel 

top head and 

bottom head

Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, "Boric Acid 

Corrosion," and 

Chapter XI.M11B, "Cracking o

Nickel-Alloy Components and 

Material Due to Boric Acid-Ind

Corrosion in RCPB Compone

(PWRs Only)"

IV.A2.RP-28 IV.A2-

14(RP-28)

Flanges; 

nozzles; 

penetrations; 

pressure 

housings; safe 

ends; vessel 

shells, heads 

welds

Steel (with 

stainless 

steel or 

nickel-alloy 

cladding); 

stainless 

steel; nickel 

alloy

Reactor coolant Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemi
December 2010 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 

IV.A2.RP-234 IV.A2-

15(R-83)

Nozzle safe 

ends and 

welds: inlet; 

outlet; safety 

injection

Stainless 

steel; nickel 

alloy welds 

and/or 

buttering

Reactor coolant Cracking 

due to stress 

corrosion 

cracking, primary 

water stress 

corrosion 

cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M11B, “Cracking o

Alloy Components and Loss o

Material Due to Boric Acid-Ind

Corrosion in RCPB Compone

(PWRs Only)" for nickel alloy 

components

IV.A2.RP-228 IV.A2-

17(R-82)

Nozzles: inlet; 

outlet; safety 

injection

Steel (with 

or without 

cladding)

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M31, “Reactor Ves

Surveillance”
NUREG-1801, Rev. 2 IV A2-6 December 2010

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 

IV.A2.R-81 IV.A2-

16(R-81)

Nozzles: inlet; 

outlet; safety 

injection

Steel (with 

stainless 

steel or 

nickel-alloy 

cladding)

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Neutron irradiation embrittlem

TLAA evaluated for extended 

operation for all ferritic materia

a neutron fluence greater than 

1E17 n/cm2 (E >1 MeV) at the 

the period of extended operat

The TLAA is to evaluate the im

neutron embrittlement on: (a) 

RTPTS value based on the 

requirements in 10 CFR 50.61

adjusted reference temperatu

values used for calculation of 

plant’s pressure-temperature 

and (c) the Charpy upper shel

or the equivalent margins ana

performed in accordance with 

Part 50, Appendix G requirem

The applicant may choose to 

demonstrate that the materials 

inlet, outlet, and safety injectio

nozzles are not controlling for 

TLAA evaluations.

IV.A2.R-90 IV.A2-

18(R-90)

Penetrations: 

head vent pipe

(top head); 

instrument 

tubes (top 

head)

Nickel alloy Reactor coolant Cracking 

due to primary 

water stress 

corrosion 

cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M11B, “Cracking o

Alloy Components and Loss o

Material Due to Boric Acid-Ind

Corrosion in RCPB Compone

(PWRs Only)"
December 2010 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 

IV.A2.RP-59 IV.A2-

19(R-89)

Penetrations: 

instrument 

tubes (bottom 

head)

Nickel alloy Reactor coolant Cracking 

due to primary 

water stress 

corrosion 

cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M11B, “Cracking o

Alloy Components and Loss o

Material Due to Boric Acid-Ind

Corrosion in RCPB Compone

(PWRs Only)"

IV.A2.R-70 IV.A2-

20(R-70)

Pressure vessel 

support skirt 

and attachment 

welds

Steel Air – indoor, 

uncontrolled

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluat

the period of extended operat

the SRP, Section 4.3 “Metal F

for acceptable methods for me

the requirements of 10 CFR 

54.21(c)(1).

IV.A2.R-219 IV.A2-

21(R-219)

Reactor vessel 

components: 

flanges; 

nozzles; 

penetrations; 

pressure 

housings; safe 

ends; thermal 

sleeves; vessel 

shells, heads 

and welds 

Steel (with 

or without 

nickel-alloy 

or stainless 

steel 

cladding); 

stainless 

steel; nickel 

alloy

Reactor coolant Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA evaluated f

period of extended operation, 

Class 1 components environm

effects on fatigue are to be 

addressed. (See SRP, Sec 4.

Fatigue,” for acceptable metho

comply with 10 CFR 54.21(c)(
NUREG-1801, Rev. 2 IV A2-8 December 2010

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 

IV.A2.R-85 IV.A2-

22(R-85)

Vessel shell: 

upper shell; 

intermediate 

shell; lower 

shell (including 

beltline welds)

SA508-Cl 2 

forgings clad 

(with 

stainless 

steel) using 

a high-heatinput 

welding 

process

Reactor coolant Crack growth 

due to cyclic 

loading

Growth of intergranular separa

(underclad cracks) in low-alloy 

forging heat affected zone und

austenitic stainless steel cladd

time-limited aging analysis (TL

be evaluated for the period of 

extended operation for all the 

Cl 2 forgings where the claddi

deposited with a high heat inp

welding process. The method

evaluating an underclad flaw i

accordance with the current w

established flaw evaluation pr

and criterion in the ASME Sec

Code. See the Standard Revie

Section 4.7, “Other Plant-Spe

Time-Limited Aging Analysis,” 

generic guidance for meeting 

requirements of 10 CFR 54.21

IV.A2.RP-229 IV.A2-

24(R-86)

Vessel shell: 

upper shell; 

intermediate 

shell; lower 

shell (including 

beltline welds)

Steel (with 

or without 

cladding)

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M31, “Reactor Ves

Surveillance”
December 2010 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 

IV.A2.R-84 IV.A2-

23(R-84)

Vessel shell: 

upper shell; 

intermediate 

shell; lower 

shell (including 

beltline welds)

Steel (with 

stainless 

steel or 

nickel-alloy 

cladding)

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Neutron irradiation embrittlem

TLAA evaluated for extended 

operation for all ferritic materia

a neutron fluence greater than 

1E17 n/cm2 (E >1 MeV) at the 

the period of extended operat

TLAA is to evaluate the impac

neutron embrittlement on: (a) 

RTPTS value based on the 

requirements in 10 CFR 50.61

adjusted reference temperatu

values used for calculation of 

plant’s pressure-temperature 

and (c) the Charpy upper shel

or the equivalent margins ana

performed in accordance with 

Part 50, Appendix G requirem

See the Standard Review Pla

Section 4.2 “Reactor Vessel N

Embrittlement” for acceptable 

methods for meeting the requ

of 10 CFR 54.21(c).

IV.A2.R-87 IV.A2-

25(R-87)

Vessel shell: 

vessel flange

Steel Reactor coolant Loss of material 

due to wear

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components

December 2010 IV B1-1 NUREG-1801, Rev. 2

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-WasteContaining 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 period of extended 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. 2 IV B1-2 December 2010

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 

IV.B1.R-92 IV.B1-1(R92)Core shroud

(including 

repairs) and 

core plate: core 

shroud (upper, 

central, lower)

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion cracking

Chapter XI.M9, “BWR Vessel 

Internals” for core shroud, and 

Chapter XI.M2, “Water Chem

IV.B1.R-96 IV.B1-2(R96)Core shroud 

(including 

repairs) and 

core plate: 

shroud support 

structure 

(shroud support 

cylinder, shroud 

support plate, 

shroud support 

legs)

Nickel alloy Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion cracking

Chapter XI.M9, “BWR Vessel 

Internals” for shroud support, 

Chapter XI.M2, “Water Chem

IV.B1.R-95 IV.B1-4(R95)Core shroud 

and core plate: 

access hole 

cover 

(mechanical)

Nickel alloy Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsect

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chem
December 2010 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 

IV.B1.R-94 IV.B1-5(R94)Core shroud 

and core plate: 

access hole 

cover (welded)

Nickel alloy Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsect

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chem

Because cracking initiated in c

regions is not amenable to vis

inspection, for BWRs with a c

the access hole covers, an 

augmented inspection is to inc

ultrasonic testing (UT) or othe

demonstrated acceptable insp

of cover welds.

IV.B1.R-93 IV.B1-6(R93)Core shroud 

and core plate: 

core plate and 

plate bolts 

(used in early 

BWRs)

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion cracking

Chapter XI.M9, “BWR Vessel 

Internals” for core plate, and 

Chapter XI.M2, “Water Chem

IV.B1.R-97 IV.B1-3(R97)Core shroud 

and core plate: 

LPCI coupling

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion cracking

Chapter XI.M9, “BWR Vessel 

Internals” for the LPCI couplin

Chapter XI.M2, “Water Chem
NUREG-1801, Rev. 2 IV B1-4 December 2010

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 

IV.B1.R-99 IV.B1-7(R99)Core spray 

lines and 

spargers: core 

spray lines 

(headers); 

spray rings; 

spray nozzles; 

thermal sleeves

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion cracking

Chapter XI.M9, “BWR Vessel 

Internals” for core spray intern

Chapter XI.M2, “Water Chem

IV.B1.R-104 IV.B1-8(R104)Fuel supports 

and control rod 

drive

assemblies: 

control rod drive 

housing

Stainless 

steel

Reactor coolant Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M9, “BWR Vessel 

Internals” for lower plenum, a

Chapter XI.M2, “Water Chem

IV.B1.RP-220 IV.B1-9(R103)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 

due to thermal 

aging, neutron 

irradiation 

embrittlement

Chapter XI.M9, "BWR Vessel 

Internals"

IV.B1.R-105 IV.B1-

10(R-105)

Instrumentation: 

Intermediate 

range monitor 

(IRM) dry tubes; 

source range 

monitor (SRM) 

dry tubes; 

incore neutron 

flux monitor 

guide tubes

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion cracking

Chapter XI.M9, “BWR Vessel 

Internals” for lower plenum, a

Chapter XI.M2, “Water Chem
December 2010 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 

IV.B1.RP-219 IV.B1-

11(R-101)

Jet pump 

assemblies: 

castings

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C 

(>482°F) and 

neutron flux

Loss of fracture 

toughness 

due to thermal 

aging, neutron 

irradiation 

embrittlement

Chapter XI.M9, "BWR Vessel 

Internals"

IV.B1.R-100 IV.B1-

13(R-100)

Jet pump 

assemblies: 

thermal sleeve; 

inlet header; 

riser brace arm; 

holddown 

beams; inlet 

elbow; mixing 

assembly; 

diffuser 

castings

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking,

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion cracking

Chapter XI.M9, “BWR Vessel 

Internals” for jet pump assem

Chapter XI.M2, “Water Chem

IV.B1.R-53 IV.B1-

14(R-53)

Reactor vessel 

internal 

components

Stainless 

steel; nickel 

alloy

Reactor coolant Cumulative 

fatigue damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluat

the period of extended operat

the SRP, Section 4.3 “Metal F

for acceptable methods for me

the requirements of 10 CFR 

54.21(c)(1).
NUREG-1801, Rev. 2 IV B1-6 December 2010

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 

IV.B1.RP-182 Reactor vessel 

internals 

components

PH 

martensitic 

stainless 

steel (17-

4PH and 

15-5PH); 

martensitic 

stainless 

steel (SS 

403, 410, 

431, etc.)

Reactor coolant 

>250°C 

(>482°F) and 

neutron flux

Loss of fracture 

toughness 

due to thermal 

aging, neutron 

irradiation 

embrittlement

Chapter XI.M9, "BWR Vessel 

Internals"

IV.B1.RP-26 IV.B1-

15(RP-26)

Reactor vessel 

internals 

components

Stainless 

steel; nickel 

alloy

Reactor coolant Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsect

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chem

IV.B1.RP-381 Reactor vessel 

internals 

components

X-750 alloy Reactor coolant 

and neutron flux

Cracking 

due to 

intergranular 

stress corrosion 

cracking

Chapter XI.M9, “BWR Vessel 

Internals” for core plate, and 

Chapter XI.M2, “Water Chem

IV.B1.RP-200 Reactor vessel 

internals 

components

X-750 alloy Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M9, "BWR Vessel 

Internals"

IV.B1.RP-377 Reactor vessel 

internals 

components: 

Jet pump 

wedge surface

Stainless 

steel

Reactor coolant Loss of material 

due to wear

Chapter XI.M9, "BWR Vessel 

Internals"
December 2010 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 

IV.B1.RP-155 IV.B1-

16(RP-18)

Steam dryers Stainless 

steel

Reactor coolant Cracking 

due to flowinduced vibration

Chapter XI.M9, "BWR Vessel 

Internals" for steam dryer

IV.B1.R-98 IV.B1-

17(R-98)

Top guide Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion cracking

Chapter XI.M9, “BWR Vessel 

Internals” for top guide, and 

Chapter XI.M2, “Water Chem

December 2010 IV B2-1 NUREG-1801, Rev. 2

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 control rod 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 period of extended operation are included in IV.E.

System Interfaces

The systems that interface with the reactor vessel internals include the reactor pressure vessel 

(IV.A2). 

Inspection Plan

An applicant will submit an inspection plan for reactor internals to the NRC for review and 

approval with the application for license renewal in accordance with Chapter XI.M16A, “PWR 

Vessel Internals.”
NUREG-1801, Rev. 2 IV B2-2 December 2010

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 

IV.B2.RP-300 IV.B2-

33(R-108)

Alignment and 

interfacing 

components: 

internals hold 

down spring

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation; 

loss of material 

due to wear

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

no Expansion components

IV.B2.RP-301 IV.B2-

40(R-112)

Alignment and 

interfacing 

components: 

upper core 

plate alignment 

pins

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking

'Chapter XI.M2, “Water Chem

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Existing Program components 

(identified in the "Structure an

Components" column) 

no Expansion components 

IV.B2.RP-299 IV.B2-

34(R-115)

Alignment and 

interfacing 

components: 

upper core 

plate alignment 

pins

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of material 

due to wear

Chapter XI.M16A, “PWR Vess

Internals” 

Existing Program components 

(identified in the "Structure an

Components" column) 

no Expansion components

IV.B2.RP-271 IV.B2-

10(R-125)

Baffle-to-former 

assembly: 

accessible 

baffle-to-former 

bolts 

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to irradiationassisted stress 

corrosion cracking 

and fatigue

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

(for Expansion components se

Items IV.B2.RP-273 and IV.B2

286)
December 2010 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 

IV.B2.RP-272 IV.B2-6(R128)Baffle-to-former 

assembly: 

accessible 

baffle-to-former 

bolts 

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement; 

change in 

dimension 

due to void 

swelling; 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

(for Expansion components se

Items IV.B2.RP-274 and IV.B2

287)

IV.B2.RP-270 IV.B2-1(R124)Baffle-to-former 

assembly: 

baffle and 

former plates

Stainless 

steel

Reactor coolant 

and neutron flux

Change in 

dimension 

due to void 

swelling

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

no Expansion components

IV.B2.RP-275 IV.B2-6(R128)Baffle-to-former 

assembly: 

baffle-edge 

bolts (all plants 

with baffle-edge 

bolts)

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to irradiationassisted stress 

corrosion cracking 

and fatigue

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

no Expansion components
NUREG-1801, Rev. 2 IV B2-4 December 2010

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 

IV.B2.RP-354 Baffle-to-former 

assembly: 

baffle-edge 

bolts (all plants 

with baffle-edge 

bolts)

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement; 

change in 

dimension 

due to void 

swelling; 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

no Expansion components

IV.B2.RP-273 IV.B2-

10(R-125)

Baffle-to-former 

assembly: 

barrel-to-former 

bolts 

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to irradiationassisted stress 

corrosion cracking 

and fatigue

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see 

Item IV.B2.RP-271)
December 2010 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 

IV.B2.RP-274 IV.B2-6(R128)Baffle-to-former 

assembly: 

barrel-to-former 

bolts 

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement; 

change in 

dimension 

due to void 

swelling; 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (iden

the "Structure and Componen

column) 

(for Primary components see 

Item IV.B2.RP-272)

IV.B2.RP-284 IV.B2-

12(R-143)

Bottom 

mounted 

instrument 

system: flux 

thimble tubes

Stainless 

steel (with 

or without 

chrome 

plating)

Reactor coolant 

and neutron flux

Loss of material 

due to wear

Chapter XI.M16A, “PWR Vess

Internals” 

Existing Program component

(identified in the "Structure an

Components" column) 

No expansion components; an

Chapter XI.M37, "Flux Thimbl

Inspection"

IV.B2.RP-293 IV.B2-

24(R-138)

Bottommounted 

instrumentation 

system: bottommounted 

instrumentation 

(BMI) column 

bodies 

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to fatigue

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column)

(for Primary components see 

Item IV.B2.RP-298)
NUREG-1801, Rev. 2 IV B2-6 December 2010

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 

IV.B2.RP-292 IV.B2-

21(R-140)

Bottommounted 

instrumentation 

system: bottommounted 

instrumentation 

(BMI) column 

bodies 

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (iden

the "Structure and Componen

column) 

(for Primary components see 

Item IV.B2.RP-297)

IV.B2.RP-296 Control rod 

guide tube 

(CRGT) 

assemblies: 

CRGT guide 

plates (cards)

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of material 

due to wear

Chapter XI.M16A, “PWR Vess

Internals” 

Primary Components (identifie

"Structure and Components" c

(for Expansion components se

Line Item IV.B2.RP-386)

IV.B2.RP-298 IV.B2-

28(R-118)

Control rod 

guide tube 

(CRGT) 

assemblies: 

CRGT lower 

flange welds 

(accessible)

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking 

and fatigue

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

(for Expansion components se

Items IV.B2.RP-291 and IV.B2

293)

IV.B2.RP-297 Control rod 

guide tube 

(CRGT) 

assemblies: 

CRGT lower 

flange welds 

(accessible)

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to thermal 

aging and neutron 

irradiation 

embrittlement

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

(for Expansion components se

Items IV.B2.RP-290 and IV.B2

292)
December 2010 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 

IV.B2.RP-386 Control rod 

guide tube 

(CRGT) 

assemblies: Ctubes and 

sheaths

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of material 

due to wear

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) are only the compone

associated with a primary com

that exceeded the acceptance 

(for Primary components see 

Item IV.B2.RP-296)

IV.B2.RP-355 Control rod 

guide tube 

assemblies: 

guide tube 

support pins

Nickel alloy Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking 

and fatigue

A plant-specific aging manage

program is to be evaluated

IV.B2.RP-356 Control rod 

guide tube 

assemblies: 

guide tube 

support pins

Nickel alloy Reactor coolant 

and neutron flux

Loss of material 

due to wear

A plant-specific aging manage

program is to be evaluated

IV.B2.RP-387 Core barrel 

assembly: core 

barrel axial 

welds

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, and 

irradiationassisted stress

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see 

Item IV.B2.RP-276)
NUREG-1801, Rev. 2 IV B2-8 December 2010

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 

IV.B2.RP-388 Core barrel

assembly: core 

barrel axial 

welds

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see 

Item IV.B2.RP-276)

IV.B2.RP-282 IV.B2-8(R120)Core barrel 

assembly: core 

barrel flange

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking 

and fatigue

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see 

Item IV.B2.RP-276)

IV.B2.RP-345 Core barrel 

assembly: core 

barrel flange

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of material 

due to wear

Chapter XI.M16A, “PWR Vess

Internals” 

Existing Program component

(identified in the "Structure an

Components" column)

no Expansion components

IV.B2.RP-278 IV.B2-8(R120)Core barrel 

assembly: core 

barrel outlet 

nozzle welds

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking 

and fatigue

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion component (identif

the "Structure and Componen

column) 

(for Primary components see 

Item IV.B2.RP-276)
December 2010 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 

IV.B2.RP-280 IV.B2-8(R120)Core barrel 

assembly: 

lower core 

barrel flange 

weld

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking 

and irradiationassisted stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion component (identif

the "Structure and Componen

column) 

(for Primary components see 

Item IV.B2.RP-276)

IV.B2.RP-281 IV.B2-9(R122)Core barrel 

assembly: 

lower core 

barrel flange 

weld

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion Components (iden

the "Structure and Componen

column) 

(for Primary components see 

Item IV.B2.RP-276)

IV.B2.RP-276 IV.B2-8(R120)Core barrel 

assembly: 

upper core 

barrel flange 

weld

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking 

and irradiationassisted stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

(for Expansion components se

Items IV.B2.RP-278, IV.B2.RP

IV.B2.RP-282, IV.B2.RP-294,

IV.B2.RP-295,IV.B2.RP-281, 

IV.B2.RP-387, and IV.B2.RP-

IV.B2.RP-285 IV.B2-

14(R-137)

Lower internals 

assembly: 

clevis insert 

bolts

Nickel alloy Reactor coolant 

and neutron flux

Loss of material 

due to wear

Chapter XI.M16A, “PWR Vess

Internals” 

Existing Program component

(identified in the "Structure an

Components" column) 

no Expansion components
NUREG-1801, Rev. 2 IV B2-10 December 2010

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 

IV.B2.RP-289 IV.B2-

20(R-130)

Lower internals 

assembly: 

lower core plate 

and extra-long 

(XL) lower core 

plate

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to irradiationassisted stress 

corrosion 

cracking, and 

fatigue

'Chapter XI.M2, “Water Chem

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Existing Program components 

(identified in the "Structure an

Components" column) 

no Expansion components 

IV.B2.RP-288 IV.B2-

18(R-132)

Lower internals 

assembly: 

lower core plate 

and extra-long 

(XL) lower core 

plate

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement; 

loss of material 

due to wear

Chapter XI.M16A, “PWR Vess

Internals” 

Existing Program component

(identified in the "Structure an

Components" column) 

no Expansion components

IV.B2.RP-291 IV.B2-

24(R-138)

Lower support 

assembly: 

lower support 

column bodies 

(cast) 

Cast 

austenitic 

stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to irradiationassisted stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column)

(for Primary components see 

Item IV.B2.RP-298)

IV.B2.RP-290 IV.B2-

21(R-140)

Lower support 

assembly: 

lower support 

column bodies 

(cast) 

Cast 

austenitic 

stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to thermal 

aging and neutron 

irradiation 

embrittlement

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (iden

the "Structure and Componen

column)

(for Primary components see 

Item IV.B2.RP-297)
December 2010 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 

IV.B2.RP-294 IV.B2-

24(R-138)

Lower support 

assembly: 

lower support 

column bodies 

(non-cast)

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to irradiationassisted stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see 

Item IV.B2.RP-276)

IV.B2.RP-295 IV.B2-

22(R-141)

Lower support 

assembly: 

lower support 

column bodies 

(non-cast)

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion Components (iden

the "Structure and Componen

column) 

(for Primary components see 

Item IV.B2.RP-276)

IV.B2.RP-286 IV.B2-

16(R-133)

Lower support 

assembly: 

lower support 

column bolts

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Cracking 

due to irradiationassisted stress 

corrosion cracking 

and fatigue

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see 

Item IV.B2.RP-271)
NUREG-1801, Rev. 2 IV B2-12 December 2010

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 

IV.B2.RP-287 IV.B2-

17(R-135)

Lower support 

assembly: 

lower support 

column bolts

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement; 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion component (identi

the "Structure and Componen

column) 

(for Primary components see 

Item IV.B2.RP-272) 

IV.B2.RP-303 IV.B2-

31(R-53)

Reactor vessel 

internal 

components

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluat

the period of extended operat

the SRP, Section 4.3 “Metal F

for acceptable methods for me

the requirements of 10 CFR 

54.21(c)(1).

IV.B2.RP-24 IV.B2-

32(RP-24)

Reactor vessel 

internal 

components

Stainless 

steel; nickel 

alloy

Reactor coolant

and neutron flux

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemi

IV.B2.RP-268 Reactor vessel 

internal 

components

(inaccessible 

locations)

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, and 

irradiationassisted stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 
December 2010 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 

IV.B2.RP-269 Reactor vessel 

internal 

components 

(inaccessible 

locations)

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement; 

change in 

dimension 

due to void 

swelling; 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation; 

loss of material 

due to wear

Chapter XI.M16A, “PWR Vess

Internals” 

IV.B2.RP-265 Reactor vessel 

internal 

components 

with no 

additional 

measures

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, and 

irradiationassisted stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Note: Components with no ad

measures are not uniquely ide

in GALL tables - Components 

additional measures are defin

Section 3.3.1 of MRP-227, "M

Reliability Program: Pressuriz

Water Reactor Internals Inspe

and Evaluation Guidelines"
NUREG-1801, Rev. 2 IV B2-14 December 2010

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 

IV.B2.RP-267 Reactor vessel 

internal 

components 

with no 

additional 

measures 

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement; 

change in 

dimension 

due to void 

swelling; 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation; 

loss of material 

due to wear

Chapter XI.M16A, “PWR Vess

Internals” 

Note: Components with no ad

measures are not uniquely ide

in GALL tables - Components 

additional measures are defin

Section 3.3.1 of MRP-227, "M

Reliability Program: Pressuriz

Water Reactor Internals Inspe

and Evaluation Guidelines"

IV.B2.RP-382 IV.B2-

26(R-142)

Reactor vessel 

internals: core 

support 

structure

Stainless 

steel; nickel 

alloy; cast 

austenitic 

stainless 

steel

Reactor coolant 

and neutron flux

Cracking, or 

Loss of material 

due to wear

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsect

IWB, IWC, and IWD”

IV.B2.RP-302 Thermal shield 

assembly: 

thermal shield 

flexures 

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to fatigue; 

loss of material 

due to wear

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

no Expansion components
December 2010 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 

IV.B2.RP-346 Upper internals 

assembly: 

upper support 

ring or skirt

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking 

and fatigue

'Chapter XI.M2, “Water Chem

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Existing Program components 

(identified in the "Structure an

Components" column) 

no Expansion components 

December 2010 IV B3-1 NUREG-1801, Rev. 2

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) 

shrouds, 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 period of extended operation are included in IV.E.

System Interfaces

The systems that interface with the reactor vessel internals include the reactor pressure vessel 

(IV.A2). 

Inspection Plan

An applicant will submit an inspection plan for reactor internals to the NRC for review and 

approval with the application for license renewal in accordance with Chapter XI.M16A, “PWR 

Vessel Internals.”
NUREG-1801, Rev. 2 IV B3-2 December 2010

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 

IV.B3.RP-312 IV.B3-2(R149)Control 

Element 

Assembly 

(CEA): shroud 

assemblies: 

instrument 

guide tubes in 

peripheral CEA 

assemblies

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking 

and fatigue

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

(for Expansion components se

Item IV.B3.RP-313)

IV.B3.RP-313 Control 

Element 

Assembly 

(CEA): shroud 

assemblies: 

remaining 

instrument 

guide tubes in 

CEA 

assemblies

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking 

and fatigue

Chapter XI.M2, "Water Chemi

and 

Chapter XI.M16A, "PWR Vess

Internals" 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item IV.B3.RP-312)

IV.B3.RP-320 IV.B3-9(R162)Core shroud 

assemblies (all 

plants): guide 

lugs and guide 

lug insert bolts

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to fatigue

'Chapter XI.M2, “Water Chem

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Existing Program components 

(identified in the "Structure an

Components" column) 

no Expansion components
December 2010 IV B3-3 NUREG-1801, Rev. 2

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 

IV.B3.RP-319 IV.B3-9(R162)Core shroud 

assemblies (all 

plants): guide 

lugs and guide 

lug insert bolts

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of material 

due to wear; 

Loss of preload 

due to thermal and 

irradiation 

enhanced stress 

relaxation

Chapter XI.M16A, "PWR Vess

Internals" 

Existing Program components 

(identified in the "Structure an

Components" column) 

no Expansion components 

IV.B3.RP-358 Core shroud 

assemblies (for 

bolted core 

shroud 

assemblies): 

(a) shroud 

plates and (b) 

former plates

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to irradiationassisted stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary component see A

Item IV.B3.RP-314)

IV.B3.RP-318 IV.B3-8(R163)Core shroud 

assemblies (for 

bolted core 

shroud 

assemblies): 

(a) shroud 

plates and (b) 

former plates

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement; 

change in 

dimension 

due to void 

swelling

Chapter XI.M16A, "PWR Vess

Internals" 

Primary components (identifie

"Structure and Components" c

no Expansion components 
NUREG-1801, Rev. 2 IV B3-4 December 2010

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 

IV.B3.RP-316 IV.B3-9(R162)Core shroud 

assemblies (for 

bolted core 

shroud 

assemblies):

barrel-shroud 

bolts with 

neutron 

exposures 

greater than 3 

dpa

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to irradiationassisted stress 

corrosion cracking

Chapter XI.M2, "Water Chemi

and 

Chapter XI.M16A, "PWR Vess

Internals" 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item IV.B3.RP-314)

IV.B3.RP-317 IV.B3-7(R165)Core shroud 

assemblies (for 

bolted core 

shroud 

assemblies): 

barrel-shroud 

bolts with 

neutron 

exposures 

greater than 3 

dpa

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of preload 

due to thermal and 

irradiation 

enhanced stress 

relaxation; 

loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M16A, "PWR Vess

Internals" 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item IV.B3.RP-315)

IV.B3.RP-314 IV.B3-9(R162)Core shroud 

assemblies (for 

bolted core 

shroud 

assemblies): 

core shroud 

bolts 

(accessible)

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to irradiationassisted stress 

corrosion cracking 

and fatigue

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

(for Expansion components se

Items IV.B3.RP-316, IV.B3.RP

and IV.B3.RP-358)
December 2010 IV B3-5 NUREG-1801, Rev. 2

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 

IV.B3.RP-315 IV.B3-7(R165)Core shroud 

assemblies (for 

bolted core 

shroud 

assemblies): 

core shroud 

bolts 

(accessible)

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of preload 

due to thermal and 

irradiation 

enhanced stress 

relaxation; 

loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement; 

change in 

dimension 

due to void 

swelling

Chapter XI.M16A, “PWR Vess

Internals,” Primary component

(identified in the "Structure an

Components" column) 

(for Expansion components s

Items IV.B3.RP-317, and IV.B

331)

IV.B3.RP-359 Core shroud 

assemblies 

(welded): 

(shroud plates 

and (b) former 

plates

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement; 

change in 

dimension 

due to void 

swelling

Chapter XI.M16A, “PWR Vess

Internals,” Primary component

(identified in the "Structure an

Components" column) 

no Expansion components
NUREG-1801, Rev. 2 IV B3-6 December 2010

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 

IV.B3.RP-322 Core shroud 

assembly (for 

welded core 

shrouds in two 

vertical 

sections): Core 

shroud plateformer plate 

weld (a) The 

axial and 

horizontal weld 

seams at the 

core shroud reentrant corners 

as visible from 

the core side of 

the shroud, 

within six 

inches of the 

central flange 

and horizontal 

stiffeners, and 

(b) the 

horizontal 

stiffeners in 

shroud plateto-former plate 

weld

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to irradiationassisted stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

(for Expansion components se

Item IV.B3.RP-323)
December 2010 IV B3-7 NUREG-1801, Rev. 2

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 

IV.B3.RP-326 Core shroud 

assembly (for 

welded core 

shrouds in two 

vertical 

sections): gap 

between the 

upper and 

lower plates

Stainless 

steel

Reactor coolant 

and neutron flux

Change in 

dimension 

due to void 

swelling

Chapter XI.M16A, "PWR Vess

Internals" 

Primary components (identifie

"Structure and Components" c

no Expansion components 

IV.B3.RP-323 Core shroud 

assembly (for 

welded core 

shrouds in two 

vertical 

sections): 

remaining axial 

welds in 

shroud plateto-former plate

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to irradiationassisted stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item IV.B3.RP-322)
NUREG-1801, Rev. 2 IV B3-8 December 2010

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 

IV.B3.RP-324 Core shroud 

assembly (for 

welded core 

shrouds with 

full-height 

shroud plates): 

axial weld 

seams at the 

core shroud reentrant 

corners, at the 

core mid-plane 

(+3 feet in 

height) as 

visible from the 

core side of the 

shroud 

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to irradiationassisted stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

(for Expansion components se

Item IV.B3.RP-325)
December 2010 IV B3-9 NUREG-1801, Rev. 2

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 

IV.B3.RP-360 Core shroud 

assembly (for 

welded core 

shrouds with 

full-height 

shroud plates): 

axial weld 

seams at the 

core shroud reentrant 

corners, at the 

core mid-plane 

(+3 feet in 

height) as 

visible from the 

core side of the 

shroud 

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M16A, "PWR Vess

Internals" 

Primary components (identifie

"Structure and Components" c

(for Expansion components se

Item IV.B3.RP-361)

IV.B3.RP-325 Core shroud 

assembly (for 

welded core 

shrouds with 

full-height 

shroud plates): 

remaining axial 

welds, ribs, 

and rings

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to irradiationassisted stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item IV.B3.RP-324)
NUREG-1801, Rev. 2 IV B3-10 December 2010

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 

IV.B3.RP-361 Core shroud 

assembly (for 

welded core 

shrouds with 

full-height 

shroud plates): 

remaining axial 

welds, ribs, 

and rings

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M16A, "PWR Vess

Internals" 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item IV.B3.RP-360)

IV.B3.RP-362 Core support 

barrel 

assembly:

lower cylinder 

welds

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M16A, "PWR Vess

Internals" 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item IV.B3.RP-327) 

IV.B3.RP-329 IV.B3-

15(R-155)

Core support 

barrel 

assembly: 

lower cylinder 

welds and 

remaining core 

barrel 

assembly 

welds

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item IV.B3.RP-327)

IV.B3.RP-333 Core support 

barrel 

assembly: 

lower flange 

weld, if fatigue 

life cannot be 

demonstrated 

by TLAA

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to fatigue

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

no Expansion components
December 2010 IV B3-11 NUREG-1801, Rev. 2

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 

IV.B3.RP-389 Core support 

barrel 

assembly: 

lower flange 

weld (if fatigue 

analysis exists)

Stainless 

steel

Reactor coolant 

and neutron flux

Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluate

the period of extended operati

the SRP, Section 4.3 “Metal F

for acceptable methods for me

the requirements of 10 CFR 

54.21(c)(1).

IV.B3.RP-328 IV.B3-

15(R-155)

Core support 

barrel 

assembly: 

surfaces of the 

lower core 

barrel flange 

weld 

(accessible 

surfaces)

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking 

and fatigue

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

no Expansion components

IV.B3.RP-332 IV.B3-

17(R-156)

Core support 

barrel 

assembly: 

upper core 

barrel flange

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of material 

due to wear

Chapter XI.M16A, “PWR Vess

Internals” 

Existing Program components 

(identified in the "Structure an

Components" column) 

no Expansion components

IV.B3.RP-327 IV.B3-

15(R-155)

Core support 

barrel 

assembly: 

upper core 

support barrel 

flange weld 

(accessible 

surfaces)

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

(for Expansion components se

Items IV.B3.RP-329, IV.B3.RP

IV.B3.RP-362, IV.B3.RP-363,

IV.B3.RP-364)
NUREG-1801, Rev. 2 IV B3-12 December 2010

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 

IV.B3.RP-357 Incore 

instrumentation 

(ICI): ICI 

thimble tubes - 

lower

Zircaloy-4 Reactor coolant 

and neutron flux

Loss of material 

due to wear

A plant-specific aging manage

program is to be evaluated

IV.B3.RP-336 IV.B3-

22(R-170)

Lower support 

structure: A286 

fuel alignment 

pins (all plants 

with core 

shroud 

assembled in 

two vertical 

sections)

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of material 

due to wear; 

loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement; 

loss of preload 

due to thermal and 

irradiation 

enhanced stress 

relaxation

Chapter XI.M16A, “PWR Vess

Internals” 

Existing Program components 

(identified in the "Structure an

Components" column) 

no Expansion components

IV.B3.RP-334 IV.B3-

23(R-167)

Lower support 

structure: A286 

fuel alignment 

pins (all plants 

with core 

shroud 

assembled 

with full-height 

shroud plates)

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to irradiationassisted stress 

corrosion cracking 

and fatigue

'Chapter XI.M2, “Water Chem

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Existing Program components 

(identified in the "Structure an

Components" column) 

no Expansion components

IV.B3.RP-364 Lower support 

structure: core 

support column

Cast 

austenitic 

stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation and 

thermal 

embrittlement

Chapter XI.M16A, "PWR Vess

Internals" 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item IV.B3RP-327) 
December 2010 IV B3-13 NUREG-1801, Rev. 2

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 

IV.B3.RP-363 Lower support 

structure: core 

support column

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M16A, "PWR Vess

Internals" 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item IV.B3RP-327) 

IV.B3.RP-330 IV.B3-

23(R-167)

Lower support 

structure: core 

support column 

bolts

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to irradiationassisted stress 

corrosion cracking 

and fatigue

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item 'IV.B3.RP-314)

IV.B3.RP-331 Lower support 

structure: core 

support column 

bolts

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item 'IV.B3.RP-315)

IV.B3.RP-335 IV.B3-

23(R-167)

Lower support 

structure: core 

support column 

welds, 

applicable to 

all plants 

except those 

assembled 

with full-height 

shroud plates

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, and 

fatigue

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item IV.B3.RP-327)
NUREG-1801, Rev. 2 IV B3-14 December 2010

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 

IV.B3.RP-365 Lower support 

structure: core 

support plate

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M16A, "PWR Vess

Internals" 

Primary component (identified 

"Structure and Components" c

no Expansion components

IV.B3.RP-343 Lower support 

structure: core 

support plate 

(applicable to 

plants with a 

core support 

plate), if fatigue 

life cannot be 

demonstrated 

by TLAA

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to fatigue

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

no Expansion components

IV.B3.RP-390 Lower support 

structure: core 

support plate 

(applicable to 

plants with a 

core support 

plate), if fatigue 

analysis exists

Stainless 

steel

Reactor coolant 

and neutron flux

Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluate

the period of extended operati

the SRP, Section 4.3 “Metal F

for acceptable methods for me

the requirements of 10 CFR 

54.21(c)(1).

IV.B3.RP-342 Lower support 

structure: deep 

beams 

(applicable 

assemblies 

with full height 

shroud plates)

Stainless 

steel 

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, and 

fatigue

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

no Expansion components
December 2010 IV B3-15 NUREG-1801, Rev. 2

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 

IV.B3.RP-366 Lower support 

structure: deep 

beams 

(applicable 

assemblies 

with full height 

shroud plates)

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

no Expansion components

IV.B3.RP-339 IV.B3-

24(R-53)

Reactor vessel 

internal 

components

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluate

the period of extended operati

the SRP, Section 4.3 “Metal F

for acceptable methods for me

the requirements of 10 CFR 

54.21(c)(1).

IV.B3.RP-24 IV.B3-

25(RP-24)

Reactor vessel 

internal 

components

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemi

IV.B3.RP-309 Reactor vessel 

internal 

components 

(inaccessible 

locations)

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, and 

irradiationassisted stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 
NUREG-1801, Rev. 2 IV B3-16 December 2010

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 

IV.B3.RP-311 Reactor vessel 

internal 

components 

(inaccessible 

locations)

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement; 

change in 

dimension 

due to void 

swelling; 

loss of preload 

due to thermal and 

irradiation 

enhanced stress 

relaxation; 

loss of material 

due to wear

Chapter XI.M16A, “PWR Vess

Internals” 

IV.B3.RP-306 Reactor vessel 

internal 

components 

with no 

additional 

measures

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, and 

irradiationassisted stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Note: Components with no ad

measures are not uniquely ide

in GALL tables - Components 

additional measures are define

Section 3.3.1 of MRP-227, "M

Reliability Program: Pressurize

Water Reactor Internals Inspe

and Evaluation Guidelines"
December 2010 IV B3-17 NUREG-1801, Rev. 2

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 

IV.B3.RP-307 Reactor vessel 

internal 

components 

with no 

additional 

measures

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement; 

change in 

dimension 

due to void 

swelling; 

loss of preload 

due to thermal and 

irradiation 

enhanced stress 

relaxation; 

loss of material 

due to wear

Chapter XI.M16A, “PWR Vess

Internals” 

Note: Components with no ad

measures are not uniquely ide

in GALL tables - Components 

additional measures are define

Section 3.3.1 of MRP-227, "M

Reliability Program: Pressurize

Water Reactor Internals Inspe

and Evaluation Guidelines"

IV.B3.RP-382 IV.B3-

22(R-170)

Reactor vessel 

internals: core 

support 

structure

Stainless 

steel; nickel 

alloy; cast 

austenitic 

stainless 

steel

Reactor coolant 

and neutron flux

Cracking, or 

Loss of material 

due to wear

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD”
NUREG-1801, Rev. 2 IV B3-18 December 2010

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 

IV.B3.RP-338 Upper internals 

assembly: fuel 

alignment plate 

(applicable to 

plants with 

core shrouds 

assembled 

with full height 

shroud plates), 

if fatigue life 

cannot be 

demonstrated 

by TLAA

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to fatigue

'Chapter XI.M2, “Water Chem

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

no Expansion components

IV.B3.RP-391 Upper internals 

assembly: fuel 

alignment plate 

(applicable to 

plants with 

core shrouds 

assembled 

with full height 

shroud plates), 

if fatigue 

analysis exists 

Stainless 

steel

Reactor coolant 

and neutron flux

Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluate

the period of extended operati

the SRP, Section 4.3 “Metal F

for acceptable methods for me

the requirements of 10 CFR 

54.21(c)(1).
December 2010 IV B4-1 NUREG-1801, Rev. 2

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 period of extended operation are included in IV.E.

System Interfaces

The systems that interface with the reactor vessel internals include the reactor pressure vessel 

(IV.A2). 

Inspection Plan

An applicant will submit an inspection plan for reactor internals to the NRC for review and 

approval with the application for license renewal in accordance with Chapter XI.M16A, “PWR 

Vessel Internals.”
NUREG-1801, Rev. 2 IV B4-2 December 2010

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 

IV.B4.RP-242 IV.B4-4(R183)Control rod 

guide tube 

(CRGT) 

assembly: 

accessible 

surfaces at four 

screw locations 

(every 90 

degrees) for 

CRGT spacer 

castings

Cast 

austenitic 

stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to thermal 

aging 

embrittlement

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see 

Items IV.B4.RP-253 and IV.B4

258)

IV.B4.RP-245 IV.B4-

13(R-194)

Core barrel 

assembly: (a) 

upper thermal 

shield bolts; (b) 

surveillance 

specimen 

holder tube 

bolts (DavisBesse, only); 

(c) surveillance 

specimen tube 

holder studs, 

and nuts 

(Crystal River 

Unit 3, only)

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Items IV.B4.RP-247 and IV.B4

248)
December 2010 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 

IV.B4.RP-247 IV.B4-

13(R-194)

Core barrel 

assembly: 

accessible 

lower core 

barrel (LCB) 

bolts and 

locking devices

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and Chapter XI.M16A, “PWR V

Internals” 

Primary components (identifie

"Structure and Components" c

(for Expansion components se

Items IV.B4.RP-245, IV.B4.RP

IV.B4.RP-254, and IV.B4.RP-2

IV.B4.RP-249 IV.B4-

12(R-196)

Core barrel 

assembly: 

baffle plate 

accessible 

surfaces within 

one inch 

around each 

baffle plate flow 

and bolt hole

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

(for Expansion components se

Item IV.B4.RP-250)

IV.B4.RP-241 IV.B4-7(R125)Core barrel 

assembly: 

baffle/former 

assembly: (a) 

accessible 

baffle-to-former 

bolts and 

screws; (b) 

accessible 

locking devices 

(including 

welds) of 

baffle-to-former 

bolts

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, 

irradiationassisted stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Primary Components (identifie

"Structure and Components" c

(for Expansion components se

Items IV.B4.RP-244 and IV.B4

375)
NUREG-1801, Rev. 2 IV B4-4 December 2010

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 

IV.B4.RP-240 IV.B4-1(R128)Core barrel 

assembly: 

baffle/former 

assembly: (a) 

accessible 

baffle-to-former 

bolts and 

screws; (b) 

accessible 

locking devices 

(including 

welds) of 

baffle-to-former 

bolts

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement; 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation; 

loss of material 

due to wear

Chapter XI.M16A, “PWR Vess

Internals.” 

Primary components (identifie

"Structure and Components" c

(for Expansion components s

Item IV.B4.RP-243.)

IV.B4.RP-250 IV.B4-

12(R-196)

Core barrel 

assembly: core 

barrel cylinder 

(including 

vertical and 

circumferential 

seam welds); 

former plates

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item IV.B4.RP-249)

IV.B4.RP-375 Core barrel 

assembly: 

internal baffleto-baffle bolts

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to fatigue

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item IV.B4.RP-241)
December 2010 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 

IV.B4.RP-244 IV.B4-7(R125)Core barrel 

assembly; (a) 

external baffleto-baffle bolts; 

(b) core barrelto-former bolts; 

(c) locking 

devices 

(including 

welds) of 

external baffleto-baffle bolts 

and core 

barrel-to-former 

bolts

Stainless 

steel

Reactor coolant 

and neutron flux

Cracking 

due to irradiationassisted stress 

corrosion cracking

Chapter XI.M2, "Water Chemi

and 

Chapter XI.M16A, "PWR Vess

Internals" 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item IV.B4.RP-241)

IV.B4.RP-243 IV.B4-1(R128)Core barrel 

assembly; (a) 

external baffleto-baffle bolts; 

(b) core barrelto-former bolts; 

(c) locking 

devices 

(including 

welds) of 

external baffleto-baffle bolts 

and core 

barrel-to-former 

bolts; (d) 

internal baffleto-baffle bolts

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement; 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation; 

loss of material 

due to wear

Chapter XI.M16A, "PWR Vess

Internals" 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item IV.B4.RP-240)
NUREG-1801, Rev. 2 IV B4-6 December 2010

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 

IV.B4.RP-248 IV.B4-

12(R-196)

Core support 

shield (CSS) 

assembly: 

accessible 

upper core 

barrel (UCB) 

bolts and 

locking devices

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and Chapter XI.M16A, “PWR V

Internals” 

Primary components (identifie

"Structure and Components" c

(for Expansion components se

Items IV.B4.RP-245, IV.B4.RP

IV.B4.RP-254, IV.B4.RP-247, 

IV.B4.RP-256)

IV.B4.RP-253 IV.B4-

21(R-191)

Core support 

shield (CSS) 

assembly: (a) 

CSS cast outlet 

nozzles 

(Oconee Unit 3 

and DavisBesse, only); 

(b) CSS vent 

valve discs

Cast 

austenitic 

stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to thermal 

aging 

embrittlement

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

(for Expansion components se

Item IV.B4.RP-242)

IV.B4.RP-252 IV.B4-

16(R-188)

Core support 

shield (CSS) 

assembly: (a) 

CSS vent valve 

disc shaft or 

hinge pin (b) 

CSS vent valve 

top retaining 

ring (c) CSS 

vent valve 

bottom 

retaining ring

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to thermal 

aging 

embrittlement

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

No Expansion components
December 2010 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 

IV.B4.RP-251 IV.B4-

15(R-190)

Core support 

shield (CSS) 

assembly: CSS 

top flange; 

plenum cover 

assembly: 

plenum cover 

weldment rib 

pads and 

plenum cover 

support flange

Stainless 

steel

Reactor coolant 

and neutron flux

Loss of material 

due to wear

Chapter XI.M16A, “PWR Vess

Internals” 

Primary component (identified 

"Structure and Components" c

No Expansion components

IV.B4.RP-256 IV.B4-

25(R-210)

Flow distributor 

assembly: flow 

distributor bolts 

and locking 

devices 

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals,” Expansion compon

(identified in the "Structure an

Components" column) 

(for Primary components see A

Items IV.B4.RP-247 and IV.B4

248)

IV.B4.RP-259 IV.B4-

31(R-205)

Incore 

Monitoring 

Instrumentation 

(IMI) guide 

tube assembly: 

accessible top 

surfaces of IMI 

guide tube 

spider-to-lower 

grid rib 

sections welds 

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to thermal 

aging, neutron 

irradiation 

embrittlement

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

(for Expansion components se

IV.B4.RP-260)
NUREG-1801, Rev. 2 IV B4-8 December 2010

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 

IV.B4.RP-258 IV.B4-4(R183)Incore 

Monitoring 

Instrumentation 

(IMI) guide 

tube assembly: 

accessible top 

surfaces of IMI 

Incore guide 

tube spider 

castings 

Cast 

austenitic 

stainless 

steel

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to thermal 

aging, neutron 

irradiation 

embrittlement

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

(for Expansion components se

IV.B4.RP-242)

IV.B4.RP-254 IV.B4-

25(R-210)

Lower grid 

assembly: 

alloy X-750 

lower grid 

shock pad bolts 

and locking 

devices (TMI-1, 

only)

Nickel alloy Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals,” Expansion compon

(identified in the "Structure an

Components" column) 

(for Primary components see A

Items IV.B4.RP-247 and IV.B4

248)

IV.B4.RP-246 IV.B4-

12(R-196)

Lower grid 

assembly: 

lower thermal 

shield (LTS) 

bolts 

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking

'Chapter XI.M2, “Water Chem

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Items IV.B4.RP-247 and IV.B4

248)
December 2010 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 

IV.B4.RP-260 IV.B4-

31(R-205)

Lower grid 

assembly: (a) 

accessible 

pads; (b) 

accessible padto-rib section 

welds; (c) 

accessible 

alloy X-750 

dowels, cap 

screws and 

locking devices

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement

Chapter XI.M16A, “PWR Vess

Internals" 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item IV.B4.RP-259)

IV.B4.RP-262 IV.B4-

32(R-203)

Lower grid 

assembly: 

accessible 

alloy X-750 

dowel-to-lower 

fuel assembly 

support pad 

welds

Nickel alloy Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item IV.B4.RP-261)

IV.B4.RP-261 IV.B4-

32(R-203)

Lower grid 

assembly: alloy 

X-750 dowelto-guide block 

welds

Nickel alloy Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Primary components (identifie

"Structure and Components" c

(for Expansion components se

Items IV.B4.RP-262 and IV.B4

352)
NUREG-1801, Rev. 2 IV B4-10 December 2010

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 

IV.B4.R-53 IV.B4-

37(R-53)

Reactor vessel 

internal 

components

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluate

the period of extended operati

the SRP, Section 4.3 “Metal F

for acceptable methods for me

the requirements of 10 CFR 

54.21(c)(1).

IV.B4.RP-24 IV.B4-

38(RP-24)

Reactor vessel 

internal 

components

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemi

IV.B4.RP-376 Reactor vessel 

internal 

components

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Reduction in 

ductility and 

fracture 

toughness 

due to neutron 

irradiation

Ductility - Reduction in Fractur

Toughness is a TLAA (BAW-2

to be evaluated for the period 

extended operation. See the S

Section 4.7, "Other Plant-Spec

TLAAs," for acceptable metho

meeting the requirements of 1

54.21(c)(1).

IV.B4.RP-238 Reactor vessel 

internal 

components 

(inaccessible 

locations)

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, and 

irradiationassisted stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals”
December 2010 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 

IV.B4.RP-239 Reactor vessel 

internal 

components 

(inaccessible 

locations)

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement; 

change in 

dimension 

due to void 

swelling; 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation; 

loss of material 

due to wear

Chapter XI.M16A, “PWR Vess

Internals”

IV.B4.RP-236 Reactor vessel 

internal 

components 

with no 

additional 

measures 

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion 

cracking, and 

irradiationassisted stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Note: Components with no ad

measures are not uniquely ide

in GALL tables - Components 

additional measures are define

Section 3.3.1 of MRP-227, "M

Reliability Program: Pressurize

Water Reactor Internals Inspe

and Evaluation Guidelines"
NUREG-1801, Rev. 2 IV B4-12 December 2010

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 

IV.B4.RP-237 Reactor vessel 

internal 

components 

with no 

additional 

measures

Stainless 

steel; nickel 

alloy

Reactor coolant 

and neutron flux

Loss of fracture 

toughness 

due to neutron 

irradiation 

embrittlement; 

change in 

dimension 

due to void 

swelling; 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation; 

loss of material 

due to wear

Chapter XI.M16A, “PWR Vess

Internals” 

Note: Components with no ad

measures are not uniquely ide

in GALL tables - Components 

additional measures are define

Section 3.3.1 of MRP-227, "M

Reliability Program: Pressurize

Water Reactor Internals Inspe

and Evaluation Guidelines"

IV.B4.RP-382 IV.B4-

42(R-179)

Reactor vessel 

internals: core 

support 

structure

Stainless 

steel; nickel 

alloy; cast 

austenitic 

stainless 

steel

Reactor coolant 

and neutron flux

Cracking, or 

Loss of material 

due to wear

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD”

IV.B4.RP-352 Upper grid 

assembly: alloy 

X-750 dowelto-upper fuel 

assembly 

support pad 

welds (all 

plants except 

Davis-Besse)

Nickel alloy Reactor coolant 

and neutron flux

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M16A, “PWR Vess

Internals” 

Expansion components (ident

the "Structure and Componen

column) 

(for Primary components see A

Item IV.B4.RP-261)
December 2010 IV C1-1 NUREG-1801, Rev. 2

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 period of extended 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. 2 IV C1-2 December 2010

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 

IV.C1.RP-230 IV.C1-1(R03)Class 1 

piping, fittings 

and branch 

connections < 

NPS 4

Steel; 

stainless 

steel

Reactor coolant Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking (for 

stainless steel 

only), and 

thermal, 

mechanical, and 

vibratory loading

Chapter XI.M1, “ASME Section 

Inservice Inspection, Subsectio

IWB, IWC, and IWD” for Class 

components, 

Chapter XI.M2, “Water Chemis

and 

XI.M35, "One-Time Inspection 

ASME Code Class 1 Small-bo

Piping"

IV.C1.R-52 IV.C1-2(R52)Class 1 

piping, piping 

components, 

and piping 

elements

Cast 

austenitic 

stainless 

steel

Reactor coolant

>250°C 

(>482°F)

Loss of fracture 

toughness 

due to thermal 

aging 

embrittlement

Chapter XI.M12, "Thermal Agi

Embrittlement of Cast Austenit

Stainless Steel (CASS)"

IV.C1.R-08 IV.C1-3(R08)Class 1 pump 

casings; valve 

bodies and 

bonnets

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C 

(>482°F)

Loss of fracture 

toughness 

due to thermal 

aging 

embrittlement

Chapter XI.M1, “ASME Section 

Inservice Inspection, Subsectio

IWB, IWC, and IWD” for Class 

components 

For pump casings and valve b

screening for susceptibility to t

aging is not necessary. The AS

Section XI inspection requirem

sufficient for managing the effe

loss of fracture toughness due 

thermal aging embrittlement of 

pump casings and valve bodie
December 2010 IV C1-3 NUREG-1801, Rev. 2

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 

IV.C1.RP-43 IV.C1-

10(R-27)

Closure 

bolting

Steel; 

stainless 

steel

Air Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integ

IV.C1.RP-42 IV.C1-

12(R-26)

Closure 

bolting

Steel; 

stainless 

steel

Air with reactor 

coolant leakage

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice corrosion 

or wear

Chapter XI.M18, "Bolting Integ

IV.C1.R-15 IV.C1-4(R15)Isolation 

condenser 

components

Stainless 

steel

Reactor coolant Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M1, “ASME Section 

Inservice Inspection, Subsectio

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chemis

The AMP in Chapter XI.M1 is t

augmented to detect cracking 

stress corrosion cracking and 

verification of the program's 

effectiveness is necessary to e

that significant degradation is n

occurring and the component i

function will be maintained dur

extended period of operation. A

acceptable verification program 

includes temperature and radio

monitoring of the shell side wa

eddy current testing of tubes.
NUREG-1801, Rev. 2 IV C1-4 December 2010

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 

IV.C1.R-225 IV.C1-5(R225)Isolation 

condenser 

components

Steel; 

stainless 

steel

Reactor coolant Cracking 

due to cyclic 

loading

Chapter XI.M1, “ASME Section 

Inservice Inspection, Subsectio

IWB, IWC, and IWD” for Class 

components 

The AMP in Chapter XI.M1 is t

augmented to detect cracking 

cyclic loading and verification o

program's effectiveness is nec

to ensure that significant degra

is not occurring and the compo

intended function will be maint

during the extended period of 

operation. An acceptable verifi

program includes temperature 

radioactivity monitoring of the s

side water, and eddy current te

tubes.

IV.C1.RP-39 IV.C1-6(R16)Isolation 

condenser 

components

Steel; 

stainless 

steel

Reactor coolant Loss of material 

due to general 

(steel only), 

pitting, and 

crevice corrosion

Chapter XI.M1, “ASME Section 

Inservice Inspection, Subsectio

IWB, IWC, and IWD,” and 

Chapter XI.M2, “Water Chemis

IV.C1.R-23 IV.C1-7(R23)Piping, piping 

components, 

and piping 

elements

Steel Reactor coolant Wall thinning 

due to flowaccelerated 

corrosion

Chapter XI.M17, “Flow-Accele

Corrosion”

IV.C1.R-21 IV.C1-8(R21)Piping, piping 

components, 

and piping 

elements 

greater than 

or equal to 4 

NPS

Nickel alloy Reactor coolant Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M7, “BWR Stress 

Corrosion Cracking,” and 

Chapter XI.M2, “Water Chemis
December 2010 IV C1-5 NUREG-1801, Rev. 2

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 

IV.C1.R-20 IV.C1-9(R20)Piping, piping 

components, 

and piping 

elements 

greater than 

or equal to 4 

NPS

Stainless 

steel

Reactor coolant Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M7, “BWR Stress 

Corrosion Cracking,” and 

Chapter XI.M2, “Water Chemis

IV.C1.RP-44 IV.C1-

11(R-28)

Pump and 

valve closure 

bolting

Steel; 

stainless 

steel

System 

temperature up 

to 288°C 

(550°F)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA evaluated fo

period of extended operation; c

ASME Code limits for allowabl

(less than 7000 cycles) of ther

stress range. (SRP Sec 4.3 “M

Fatigue,” for acceptable metho

comply with 10 CFR 54.21(c)(1

IV.C1.RP-158 IV.C1-

14(RP-27)

Reactor 

coolant 

pressure 

boundary 

components

Steel (with 

stainless 

steel or 

nickel-alloy 

cladding); 

stainless 

steel; nickel 

alloy

Reactor coolant Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemis

and 

Chapter XI.M32, “One-Time 

Inspection”

IV.C1.R-220 IV.C1-

15(R-220)

Reactor 

coolant 

pressure 

boundary 

components: 

piping, piping 

components, 

and piping 

elements

Steel (with 

or without 

nickel-alloy 

or stainless 

steel 

cladding); 

stainless 

steel; nickel 

alloy

Reactor coolant Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA evaluated fo

period of extended operation, a

Class 1 components environm

effects on fatigue are to be add

(See SRP, Sec 4.3 “Metal Fati

acceptable methods to comply 

CFR 54.21(c)(1))

December 2010 IV C2-1 NUREG-1801, Rev. 2

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 period of extended 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. 2 IV C2-2 December 2010

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 

IV.C2.RP-235 IV.C2-1(R02)Class 1 piping, 

fittings and 

branch 

connections 

< NPS 4

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Reactor coolant Cracking 

due to stress 

corrosion 

cracking, 

intergranular 

stress corrosion 

cracking (for 

stainless steel 

only), and 

thermal, 

mechanical, and 

vibratory loading

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components, 

Chapter XI.M2, “Water Chemi

and 

XI.M35, "One-Time Inspection 

ASME Code Class 1 Small-bo

Piping"

IV.C2.R-05 IV.C2-3(R05)Class 1 piping, 

piping 

components, 

and piping

elements

Cast 

austenitic 

stainless 

steel

Reactor coolant Cracking 

due to stress 

corrosion cracking

Monitoring and control of prim

water chemistry in accordance 

EPRI 1014986 minimize the p

for SCC. Material selection ac

to NUREG-0313, Rev. 2, guid

≤0.035% C and ≥7.5% ferrite 

susceptibility to SCC. 

For CASS components that do 

meet either one of the above, 

specific aging management pr

is evaluated 

The program is to include 

(a) adequate inspection metho

ensure detection of cracks, an

(b) flaw evaluation methodolo

CASS components that are 

susceptible to thermal aging 

embrittlement.
December 2010 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 

IV.C2.R-52 IV.C2-4(R52)Class 1 piping, 

piping 

components, 

and piping 

elements

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C 

(>482°F)

Loss of fracture 

toughness 

due to thermal 

aging 

embrittlement

Chapter XI.M12, "Thermal Ag

Embrittlement of Cast Austeni

Stainless Steel (CASS)"

IV.C2.RP-344 IV.C2-2(R07)Class 1 piping, 

piping 

components, 

and piping 

elements

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Reactor coolant Cracking 

due to stress 

corrosion cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chemi

IV.C2.R-09 IV.C2-5(R09)Class 1 pump 

casings; valve 

bodies

Steel (with 

stainless 

steel 

cladding); 

stainless 

steel

Reactor coolant Cracking 

due to stress 

corrosion cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chemi

IV.C2.R-08 IV.C2-6(R08)Class 1 pump 

casings; valve 

bodies and 

bonnets

Cast 

austenitic 

stainless 

steel

Reactor coolant 

>250°C 

(>482°F)

Loss of fracture 

toughness 

due to thermal 

aging 

embrittlement

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components 

For pump casings and valve b

screening for susceptibility to 

aging is not necessary. The A

Section XI inspection requirem

are sufficient for managing the 

of loss of fracture toughness d

thermal aging embrittlement o

pump casings and valve bodie
NUREG-1801, Rev. 2 IV C2-4 December 2010

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 

IV.C2.R-11 IV.C2-7(R11)Closure bolting Highstrength, 

low-alloy 

steel; 

stainless 

steel

Air with reactor 

coolant leakage

Cracking 

due to stress 

corrosion cracking

Chapter XI.M18, "Bolting Integ

IV.C2.R-12 IV.C2-8(R12)Closure bolting Low-alloy 

steel, 

stainless 

steel

Air (with reactor 

coolant 

leakage)

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integ

IV.C2.RP-166 Closure bolting Steel Air – indoor, 

uncontrolled

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.M18, "Bolting Integ

IV.C2.RP-167 Closure bolting Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

IV.C2.R-17 IV.C2-9(R17)External 

surfaces

Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

IV.C2.RP-380 IV.C2-9(R17)External 

surfaces: 

reactor coolant 

pressure 

boundary piping 

or components 

adjacent to 

dissimilar metal 

(Alloy 82/182) 

welds

Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, "Boric Acid 

Corrosion," and 

Chapter XI.M11B, "Cracking o

Nickel-Alloy Components and 

Material Due to Boric Acid-Ind

Corrosion in RCPB Compone

(PWRs Only)"
December 2010 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 

IV.C2.R-18 IV.C2-

10(R-18)

Piping and 

components 

(External 

surfaces); 

bolting

Steel; 

stainless 

steel

System 

temperature up 

to 340°C 

(644°F)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluat

the period of extended operat

the SRP, Section 4.3 “Metal F

for acceptable methods for me

the requirements of 10 CFR 

54.21(c)(1).

IV.C2.RP-222 IV.C2-

11(RP-11)

Piping, piping 

components, 

and piping 

elements

Copper 

alloy

Closed-cycle 

cooling water

Loss of material 

due to pitting, 

crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed Tre

Water Systems"

IV.C2.RP-12 IV.C2-

12(RP-12)

Piping, piping 

components, 

and piping 

elements

Copper 

alloy (>15% 

Zn or >8% 

Al)

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective Le

IV.C2.RP-159 IV.C2-

13(RP-31)

Piping, piping 

components, 

and piping 

elements

Nickel alloy Reactor coolant 

or steam

Cracking 

due to primary 

water stress 

corrosion cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M11B, “Cracking o

Nickel-Alloy Components and 

Material Due to Boric Acid-Ind

Corrosion in RCPB Compone

(PWRs Only)"

IV.C2.RP-221 IV.C2-

14(RP-10)

Piping, piping 

components, 

and piping 

elements

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.M21A, "Closed Tre

Water Systems"
NUREG-1801, Rev. 2 IV C2-6 December 2010

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 

IV.C2.RP-23 IV.C2-

15(RP-23)

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 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemi

IV.C2.R-58 IV.C2-

18(R-58)

Pressurizer 

components

Steel (with 

stainless 

steel or 

nickel-alloy 

cladding); 

stainless 

steel

Reactor coolant Cracking 

due to cyclic 

loading

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chemi

Cracks in the pressurizer clad

could propagate from cyclic lo

into the ferrite base metal and 

metal. However, because the 

metal between the surge nozz

the vessel lower head is subje

the maximum stress cycles an

area is periodically inspected 

of the ISI program, the existin

is adequate for managing the 

pressurizer clad cracking.
December 2010 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 

IV.C2.R-25 IV.C2-

19(R-25)

Pressurizer 

components

Steel (with 

stainless 

steel or 

nickel-alloy 

cladding); 

stainless 

steel

Reactor coolant Cracking 

due to stress 

corrosion

cracking, primary 

water stress 

corrosion cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chemi

IV.C2.R-217 IV.C2-

20(R-217)

Pressurizer 

heater sheaths

and sleeves; 

heater bundle 

diaphragm plate

Stainless 

steel

Reactor coolant Cracking 

due to stress 

corrosion cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chemi

IV.C2.RP-37 IV.C2-

21(R-06)

Pressurizer 

instrumentation 

penetrations; 

heater sheaths 

and sleeves; 

heater bundle 

diaphragm

plate; manways 

and flanges

Nickel alloy; 

nickel-alloy 

cladding

Reactor coolant Cracking 

due to primary 

water stress 

corrosion cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M11B, “Cracking o

Nickel-Alloy Components and 

Material Due to Boric Acid-Ind

Corrosion in RCPB Compone

(PWRs Only)"

IV.C2.RP-231 IV.C2-

22(R-14)

Pressurizer 

relief tank: tank 

shell and 

heads; flanges; 

nozzles

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Treated borated 

water >60°C 

(>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for ASM

components, and 

Chapter XI.M2, “Water Chemi
NUREG-1801, Rev. 2 IV C2-8 December 2010

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 

IV.C2.R-13 IV.C2-

23(R-13)

Pressurizer 

relief tank: tank 

shell and 

heads; flanges; 

nozzles

Steel (with 

stainless 

steel or 

nickel-alloy 

cladding)

Treated borated 

water

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluat

the period of extended operat

the SRP, Section 4.3 “Metal F

for acceptable methods for me

the requirements of 10 CFR 

54.21(c)(1).

IV.C2.RP-383 Pressurizer 

relief tank: tank 

shell and 

heads; flanges; 

nozzles (nonASME Section 

XI components)

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Treated borated 

water >60°C 

(>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”

IV.C2.RP-156 IV.C2-

24(RP-22)

Pressurizer 

surge and 

steam space 

nozzles; welds

Nickel alloy Reactor coolant 

or steam

Cracking 

due to primary 

water stress 

corrosion cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M11B, “Cracking o

Nickel-Alloy Components and 

Material Due to Boric Acid-Ind

Corrosion in RCPB Compone

(PWRs Only)"

IV.C2.R-19 IV.C2-

16(R-19)

Pressurizer: 

integral support

Steel; 

stainless 

steel

Air with metal 

temperature up 

to 288°C 

(550°F)

Cracking 

due to cyclic 

loading

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components
December 2010 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 

IV.C2.RP-40 IV.C2-

17(R-24)

Pressurizer: 

spray head

Nickel alloy Reactor coolant Cracking 

due to stress 

corrosion 

cracking, primary 

water stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”

IV.C2.RP-41 IV.C2-

17(R-24)

Pressurizer: 

spray head

Stainless 

steel

Reactor coolant Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”

IV.C2.R-223 IV.C2-

25(R-223)

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; 

thermal sleeves

Steel (with 

or without 

nickel-alloy 

or stainless 

steel 

cladding); 

stainless 

steel; nickel 

alloy

Reactor coolant Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA evaluated f

period of extended operation, 

Class 1 components environm

effects on fatigue are to be 

addressed. (See SRP, Sec 4.

Fatigue,” for acceptable metho

comply with 10 CFR 54.21(c)(
NUREG-1801, Rev. 2 IV C2-10 December 2010

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 

IV.C2.R-56 IV.C2-

26(R-56)

Reactor coolant 

system piping 

and fittings: cold 

leg; hot leg; 

surge line; 

spray line

Steel (with 

stainless 

steel 

cladding); 

stainless 

steel

Reactor coolant Cracking 

due to cyclic 

loading

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components

IV.C2.R-30 IV.C2-

27(R-30)

Reactor coolant 

system piping 

and fittings: cold 

leg; hot leg; 

surge line; 

spray line

Steel (with 

stainless 

steel 

cladding); 

stainless 

steel

Reactor coolant Cracking 

due to stress 

corrosion cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsecti

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chemi
December 2010 IV D1-1 NUREG-1801, Rev. 2

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 period of extended 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. 2 IV D1-2 December 2010

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 

IV.D1.R-10 IV.D1-2(R10)Closure bolting Steel Air with reactor 

coolant leakage

Cracking 

due to stress 

corrosion 

cracking

Chapter XI.M18, "Bolting Integ

IV.D1.RP-46 IV.D1-

10(R-32)

Closure bolting Steel; 

stainless 

steel

Air – indoor, 

uncontrolled 

(External)

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integ

IV.D1.R-17 IV.D1-3(R17)External 

surfaces

Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

IV.D1.RP-36 IV.D1-4(R01)Instrument 

penetrations 

and primary 

side nozzles; 

safe ends; 

welds

Steel (with 

nickel-alloy 

cladding); 

nickel alloy

Reactor coolant Cracking 

due to primary 

water stress 

corrosion 

cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsect

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chem

and 

Chapter XI.M11B, “Cracking o

Nickel-Alloy Components and 

Material Due to Boric Acid-Ind

Corrosion in RCPB Compone

(PWRs Only)"

IV.D1.R-37 IV.D1-5(R37)Pressure 

boundary and 

structural: 

steam nozzle 

and safe end; 

feedwater 

nozzle and safe 

end

Steel Secondary

feedwater or 

steam

Wall thinning 

due to flowaccelerated 

corrosion

Chapter XI.M17, “Flow-Accele

Corrosion”
December 2010 IV D1-3 NUREG-1801, Rev. 2

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 

IV.D1.RP-17 IV.D1-

7(RP-17)

Primary side 

components: 

divider plate

Stainless 

steel

Reactor coolant Cracking 

due to stress 

corrosion 

cracking

Chapter XI.M2, “Water Chem

IV.D1.RP-367 IV.D1-

6(RP-21)

Primary side 

components: 

divider plate

Steel (with 

nickel-alloy 

cladding); 

nickel alloy

Reactor coolant Cracking 

due to primary 

water stress 

corrosion 

cracking

Chapter XI.M2, “Water Chem

For nickel alloy divider plate 

assemblies and associated w

made of Alloy 600, effectivene

the chemistry control program 

be verified to ensure that crac

due to PWSCC is not occurrin

IV.D1.R-221 IV.D1-8(R221)Recirculating 

steam 

generator 

components: 

flanges; 

penetrations; 

nozzles; safe 

ends; lower 

heads and 

welds

Steel (with 

or without 

nickel-alloy 

or stainless 

steel 

cladding); 

stainless 

steel; nickel 

alloy

Reactor coolant Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA evaluated f

period of extended operation, 

Class 1 components environm

effects on fatigue are to be 

addressed. (See SRP, Sec 4.

Fatigue,” for acceptable meth

comply with 10 CFR 54.21(c)(

IV.D1.RP-372 Steam 

generator 

components: 

shell assembly

Steel Secondary 

feedwater or 

steam

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.M2, “Water Chem

and 

Chapter XI.M32, “One-Time 

Inspection”
NUREG-1801, Rev. 2 IV D1-4 December 2010

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 

IV.D1.R-33 IV.D1-

11(R-33)

Steam 

generator 

components: 

top head; 

steam nozzle 

and safe end; 

upper and 

lower shell; 

feedwater (FW) 

and auxiliary 

FW nozzle and 

safe end; FW 

impingement 

plate and 

support

Steel Secondary 

feedwater or 

steam

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluat

the period of extended operat

the SRP, Section 4.3 “Metal F

for acceptable methods for me

the requirements of 10 CFR 

54.21(c)(1).
December 2010 IV D1-5 NUREG-1801, Rev. 2

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 

IV.D1.RP-368 IV.D1-

12(R-34)

Steam 

generator 

components: 

upper and 

lower shell; 

transition cone; 

new transition 

cone closure 

weld

Steel Secondary 

feedwater or 

steam

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsect

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chem

As noted in NRC IN 90-04, if g

and pitting corrosion of the sh

exists, Chapter XI.M1 method

not be sufficient to detect gen

pitting corrosion (and the resu

corrosion-fatigue cracking), an

additional inspection procedu

to be developed. This issue is 

to Westinghouse Model 44 an

Steam Generators where a hi

stress region exists at the she

transition cone weld. The new 

transition is only applicable to 

replacement recirculating stea

generators.

IV.D1.R-39 IV.D1-

13(R-39)

Steam 

generator 

feedwater 

impingement 

plate and 

support

Steel Secondary 

feedwater

Loss of material 

due to erosion

A plant-specific aging manage

program is to be evaluated

IV.D1.RP-48 IV.D1-

16(R-41)

Steam 

generator 

structural: tube 

support lattice 

bars

Steel Secondary 

feedwater or 

steam

Wall thinning 

due to flowaccelerated 

corrosion and 

general corrosion

Chapter XI.M19, “Steam Gene

and 

Chapter XI.M2, “Water Chem
NUREG-1801, Rev. 2 IV D1-6 December 2010

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 

IV.D1.R-42 IV.D1-

17(R-42)

Steam 

generator 

structural: tube 

support plates

Steel Secondary 

feedwater or 

steam

Ligament 

cracking 

due to corrosion

Chapter XI.M19, “Steam Gene

and 

Chapter XI.M2, “Water Chem

IV.D1.RP-384 IV.D1-

14(RP-14)

Steam 

generator 

structural: Ubend supports 

including antivibration bars

Steel; 

chrome 

plated steel; 

stainless 

steel; nickel 

alloy

Secondary 

feedwater or 

steam

Cracking 

due to stress 

corrosion 

cracking or other 

mechanism(s)

Chapter XI.M19, “Steam Gene

and 

Chapter XI.M2, “Water Chem

IV.D1.RP-225 IV.D1-

15(RP-15)

Steam 

generator 

structural: Ubend supports 

including antivibration bars

Steel; 

chrome 

plated steel; 

stainless 

steel; nickel 

alloy

Secondary 

feedwater or 

steam

Loss of material 

due to fretting

Chapter XI.M19, “Steam Gene

IV.D1.RP-226 IV.D1-

15(RP-15)

Steam 

generator 

structural: Ubend supports 

including antivibration bars

Steel; 

chrome 

plated steel; 

stainless 

steel; nickel 

alloy

Secondary 

feedwater or 

steam

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice corrosion

Chapter XI.M19, “Steam Gene

and 

Chapter XI.M2, “Water Chem

IV.D1.RP-232 IV.D1-1(R07)Steam 

generator: 

primary 

nozzles; nozzle 

to safe end 

welds; 

manways; 

flanges

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Reactor coolant Cracking 

due to stress 

corrosion 

cracking

Chapter XI.M1, “ASME Sectio

Inservice Inspection, Subsect

IWB, IWC, and IWD” for Class 

components, and 

Chapter XI.M2, “Water Chem
December 2010 IV D1-7 NUREG-1801, Rev. 2

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 

IV.D1.RP-161 IV.D1-

9(RP-16)

Steam 

generator: 

Tube bundle 

wrapper and 

associated 

supports and 

mounting 

hardware

Steel Secondary 

feedwater or 

steam

Loss of material 

due to erosion, 

general, pitting, 

and crevice 

corrosion

Chapter XI.M19, “Steam Gene

and 

Chapter XI.M2, “Water Chem

IV.D1.R-40 IV.D1-

18(R-40)

Tube plugs Nickel alloy Reactor coolant Cracking

due to primary 

water stress 

corrosion 

cracking

Chapter XI.M19, “Steam Gene

and 

Chapter XI.M2, “Water Chem

IV.D1.R-43 IV.D1-

19(R-43)

Tubes Nickel alloy Secondary 

feedwater or 

steam

Changes in 

dimension 

("denting") 

due to corrosion 

of carbon steel 

tube support 

plate

Chapter XI.M19, “Steam Gene

and 

Chapter XI.M2, “Water Chem

IV.D1.R-44 IV.D1-

20(R-44)

Tubes and 

sleeves

Nickel alloy Reactor coolant Cracking 

due to primary 

water stress 

corrosion 

cracking

Chapter XI.M19, “Steam Gene

and 

Chapter XI.M2, “Water Chem

IV.D1.R-46 IV.D1-

21(R-46)

Tubes and 

sleeves

Nickel alloy Reactor coolant 

and secondary 

feedwater/steam

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluat

the period of extended operat

the SRP, Section 4.3 “Metal F

for acceptable methods for me

the requirements of 10 CFR 

54.21(c)(1).
NUREG-1801, Rev. 2 IV D1-8 December 2010

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 

IV.D1.R-48 IV.D1-

22(R-48)

Tubes and 

sleeves

Nickel alloy Secondary 

feedwater or 

steam

Cracking 

due to 

intergranular 

attack

Chapter XI.M19, “Steam Gene

and 

Chapter XI.M2, “Water Chem

IV.D1.R-47 IV.D1-

23(R-47)

Tubes and 

sleeves

Nickel alloy Secondary 

feedwater or 

steam

Cracking 

due to outer 

diameter stress 

corrosion 

cracking

Chapter XI.M19, “Steam Gene

and 

Chapter XI.M2, “Water Chem

IV.D1.RP-233 IV.D1-

24(R-49)

Tubes and 

sleeves

Nickel alloy Secondary 

feedwater or 

steam

Loss of material 

due to fretting 

and wear

Chapter XI.M19, “Steam Gene

IV.D1.R-50 IV.D1-

25(R-50)

Tubes and 

sleeves 

(exposed to 

phosphate 

chemistry)

Nickel alloy Secondary 

feedwater or 

steam

Loss of material 

due to wastage 

and pitting 

corrosion

Chapter XI.M19, “Steam Gene

and 

Chapter XI.M2, “Water Chem

IV.D1.RP-385 Tube-to-tube 

sheet welds

Nickel alloy Reactor coolant Cracking 

due to primary 

water stress 

corrosion 

cracking

Chapter XI.M2, “Water Chem

A plant-specific program is to 

evaluated; the effectiveness o

water chemistry program shou

verified to ensure cracking is 

occurring.

IV.D1.RP-49 IV.D1-

26(R-51)

Upper 

assembly and 

separators 

including: 

feedwater inlet 

ring and 

support

Steel Secondary 

feedwater or 

steam

Wall thinning 

due to flowaccelerated 

corrosion

Chapter XI.M19, “Steam Gene

and 

Chapter XI.M2, “Water Chem
December 2010 IV D2-1 NUREG-1801, Rev. 2

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 period of extended 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. 2 IV D2-2 December 2010

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 Progra

(AMP)

IV.D2.RP-46 IV.D2-

6(R-32)

Closure bolting Steel; 

stainless 

steel

Air – indoor, 

uncontrolled 

(External)

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Inte

IV.D2.R-17 IV.D2-

1(R-17)

External surfaces Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

IV.D2.RP-36 IV.D2-

2(R-01)

Instrument 

penetrations and 

primary side 

nozzles; safe 

ends; welds

Steel (with 

nickel-alloy 

cladding); 

nickel alloy

Reactor coolant Cracking 

due to primary 

water stress 

corrosion 

cracking

Chapter XI.M1, “ASME Sect

Inservice Inspection, Subsec

IWB, IWC, and IWD” for Clas

components, and 

Chapter XI.M2, “Water Chem

and 

Chapter XI.M11B, “Cracking 

Nickel-Alloy Components an

of Material Due to Boric Acid

Induced Corrosion in RCPB 

Components (PWRs Only)"

IV.D2.R-222 IV.D2-

3(R-222)

Once-through 

steam generator 

components: 

primary side 

nozzles, safe 

ends, and welds

Steel (with 

or without 

nickel-alloy 

or stainless 

steel 

cladding); 

stainless 

steel; nickel 

alloy

Reactor coolant Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA evaluated 

period of extended operation

Class 1 components environ

effects on fatigue are to be 

addressed. (See SRP, Sec 4

“Metal Fatigue,” for acceptab

methods to comply with 10 C

54.21(c)(1))
December 2010 IV D2-3 NUREG-1801, Rev. 2

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 Progra

(AMP)

IV.D2.RP-47 IV.D2-

4(R-35)

Primary side 

components: 

upper and lower 

heads, and tube 

sheet welds 

exposed to 

reactor coolant

Steel (with 

stainless 

steel or 

nickel-alloy 

cladding)

Reactor coolant Cracking 

due to stress 

corrosion 

cracking, primary 

water stress 

corrosion 

cracking

Chapter XI.M1, “ASME Sect

Inservice Inspection, Subsec

IWB, IWC, and IWD” for Clas

components, and 

Chapter XI.M2, “Water Chem

IV.D2.R-31 IV.D2-

5(R-31)

Secondary 

manway covers; 

handhole covers

Steel Air with leaking 

secondary-side 

water and/or 

steam

Loss of material 

due to erosion

Chapter XI.M1, “ASME Sect

Inservice Inspection, Subsec

IWB, IWC, and IWD” for Clas

components

IV.D2.R-36 IV.D2-

9(R-36)

Steam generator 

components:

secondary side 

nozzles (vent, 

drain, and 

instrumentation)

Nickel alloy Secondary 

feedwater or 

steam

Cracking 

due to stress 

corrosion 

cracking

Chapter XI.M2, "Water Chem

and 

Chapter XI.M32, "One-Time 

Inspection," or 

Chapter XI.M1, “ASME Sect

Inservice Inspection, Subsec

IWB, IWC, and IWD.” 

IV.D2.R-38 IV.D2-

7(R-38)

Steam generator 

components: 

feedwater (FW) 

and auxiliary FW 

nozzles and safe 

ends; steam 

nozzles and safe 

ends

Steel Secondary 

feedwater or 

steam

Wall thinning 

due to flowaccelerated 

corrosion

Chapter XI.M17, “Flow-Acce

Corrosion”

IV.D2.RP-153 IV.D2-

8(R-224)

Steam generator 

components: shell 

assembly

Steel Secondary 

feedwater or 

steam

Loss of material 

due to general,

pitting, and 

crevice corrosion

Chapter XI.M2, “Water Chem

and 

Chapter XI.M32, “One-Time 

Inspection”
NUREG-1801, Rev. 2 IV D2-4 December 2010

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 Progra

(AMP)

IV.D2.R-33 IV.D2-

10(R-33)

Steam generator 

components: top 

head; steam 

nozzle and safe 

end; upper and 

lower shell; 

feedwater (FW) 

and auxiliary FW 

nozzle and safe 

end; FW 

impingement plate 

and support

Steel Secondary 

feedwater or 

steam

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a time-limited agin

analysis (TLAA) to be evalua

the period of extended opera

See the SRP, Section 4.3 “M

Fatigue,” for acceptable met

meeting the requirements of 

54.21(c)(1).

IV.D2.R-42 IV.D2-

11(R-42)

Steam generator 

structural: tube 

support plates

Steel Secondary 

feedwater or 

steam

Ligament 

cracking 

due to corrosion

Chapter XI.M19, “Steam 

Generators,” and 

Chapter XI.M2, “Water Chem

IV.D2.RP-162 Steam generator: 

tube bundle 

wrapper and 

associated 

supports and 

mounting 

hardware

Steel Secondary 

feedwater or 

steam

Loss of material 

due to erosion, 

general, pitting, 

and crevice 

corrosion

Chapter XI.M19, “Steam 

Generators,” and 

Chapter XI.M2, “Water Chem

IV.D2.R-40 IV.D2-

12(R-40)

Tube plugs Nickel alloy Reactor coolant Cracking 

due to primary 

water stress 

corrosion 

cracking

Chapter XI.M19, “Steam 

Generators,” and 

Chapter XI.M2, “Water Chem
December 2010 IV D2-5 NUREG-1801, Rev. 2

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 Progra

(AMP)

IV.D2.R-226 IV.D2-

13(R-226)

Tubes Nickel alloy Secondary 

feedwater or 

steam

Changes in 

dimension 

("denting") 

due to corrosion 

of carbon steel 

tube support 

plate

Chapter XI.M19, “Steam 

Generators,” and 

Chapter XI.M2, “Water Chem

IV.D2.R-44 IV.D2-

14(R-44)

Tubes and 

sleeves

Nickel alloy Reactor coolant Cracking 

due to primary 

water stress 

corrosion 

cracking

Chapter XI.M19, “Steam 

Generators,” and 

Chapter XI.M2, “Water Chem

IV.D2.R-46 IV.D2-

15(R-46)

Tubes and 

sleeves

Nickel alloy Reactor coolant 

and secondary 

feedwater/steam

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a time-limited agin

analysis (TLAA) to be evalua

the period of extended opera

See the SRP, Section 4.3 “M

Fatigue,” for acceptable met

meeting the requirements of 

54.21(c)(1).

IV.D2.R-48 IV.D2-

16(R-48)

Tubes and 

sleeves

Nickel alloy Secondary 

feedwater or 

steam

Cracking 

due to 

intergranular 

attack

Chapter XI.M19, “Steam 

Generators,” and 

Chapter XI.M2, “Water Chem

IV.D2.R-47 IV.D2-

17(R-47)

Tubes and 

sleeves

Nickel alloy Secondary 

feedwater or 

steam

Cracking 

due to outer 

diameter stress 

corrosion 

cracking

Chapter XI.M19, “Steam 

Generators,” and 

Chapter XI.M2, “Water Chem

IV.D2.RP-233 IV.D2-

18(R-49)

Tubes and 

sleeves

Nickel alloy Secondary 

feedwater or 

steam

Loss of material 

due to fretting 

and wear

Chapter XI.M19, “Steam Gen
NUREG-1801, Rev. 2 IV D2-6 December 2010

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 Progra

(AMP)

IV.D2.RP-185 IV.D2-

4(R-35)

Tube-to-tube 

sheet welds

Nickel alloy Reactor coolant Cracking due to 

primary water 

stress corrosion 

cracking

Chapter XI.M2, “Water Chem

A plant-specific program is to 

evaluated; the effectiveness 

water chemistry program sho

verified to ensure cracking is 

occurring
December 2010 IV E-1 NUREG-1801, Rev. 2

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 period of extended 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. 2 IV E-2 December 2010

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 

IV.E.RP-03 IV.E-1(RP03)Piping, piping 

components, 

and piping 

elements

Nickel alloy Air – indoor, 

uncontrolled 

(External)

None None 

IV.E.RP-378 Piping, piping 

components, 

and piping 

elements

Nickel alloy Air with borated 

water leakage

None None 

IV.E.RP-04 IV.E-2(RP04)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Air – indoor, 

uncontrolled 

(External)

None None 

IV.E.RP-05 IV.E-3(RP05)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Air with borated 

water leakage

None None 

IV.E.RP-06 IV.E-4(RP06)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Concrete None None 

IV.E.RP-07 IV.E-5(RP07)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Gas None None 

IV.E.RP-353 IV.E-6(RP01)Piping, piping 

components, 

and piping 

elements

Steel Concrete None None, provided:

1) attributes of the concrete are 

consistent with ACI 318 or ACI 

water-to-cement ratio, low perm

and adequate air entrainment) a

in NUREG-1557, and 

2) plant OE indicates no degrad

the concrete
December 2010 V-i NUREG-1801, Rev. 2

CHAPTER V

ENGINEERED SAFETY FEATURES

December 2010 V-iii NUREG-1801, Rev. 2

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

December 2010 V A-1 NUREG-1801, Rev. 2

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 period of extended 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. 2 V A-2 December 2010

V ENGINEERED SAFETY FEATURES

A Containment Spray System (PWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism

Aging Manageme

Program (AMP)

V.A.E-26 V.A-1(E26)Ducting, piping, and 

components (External 

surfaces)

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general corrosion

Chapter XI.M36, "

Surfaces Monitorin

Mechanical Comp

V.A.EP-42 V.A2(EP42)Encapsulation 

components

Steel Air – indoor, 

uncontrolled 

(Internal)

Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.M38, 

"Inspection of Inte

Surfaces in Misce

Piping and Ductin

Components"

V.A.EP-43 V.A3(EP43)

Encapsulation 

components

Steel Air with 

borated water 

leakage 

(Internal)

Loss of material 

due to general, pitting, 

crevice, and boric acid 

corrosion

Chapter XI.M38, 

"Inspection of Inte

Surfaces in Misce

Piping and Ductin

Components"

V.A.E-28 V.A-4(E28)External surfaces Steel Air with 

borated water 

leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “

Acid Corrosion”

V.A.EP-94 V.A5(EP13)Heat exchanger 

components

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to pitting, crevice, 

and galvanic corrosion

Chapter XI.M21A, 

Treated Water Sys

V.A.EP-37 V.A6(EP37)Heat exchanger 

components

Copper alloy 

(>15% Zn or 

>8% Al)

Closed-cycle 

cooling water

Loss of material 

due to selective leaching

Chapter XI.M33, “

Leaching”

V.A.EP-93 V.A-7(E19)Heat exchanger 

components

Stainless 

steel

Closed-cycle 

cooling water

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M21A, 

Treated Water Sys

V.A.EP-91 V.A-8(E20)Heat exchanger 

components

Stainless 

steel

Raw water Loss of material 

due to pitting, crevice, 

and microbiologicallyinfluenced corrosion; 

fouling that leads to 

corrosion

Chapter XI.M20, "

Cycle Cooling Wa

System"
December 2010 V A-3 NUREG-1801, Rev. 2

V ENGINEERED SAFETY FEATURES

A Containment Spray System (PWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism

Aging Manageme

Program (AMP)

V.A.EP-92 V.A-9(E17)Heat exchanger 

components

Steel Closed-cycle 

cooling water

Loss of material 

due to general, pitting, 

crevice, and galvanic 

corrosion

Chapter XI.M21A, 

Treated Water Sys

V.A.EP-90 V.A10(E-18)Heat exchanger 

components

Steel Raw water Loss of material 

due to general, pitting, 

crevice, and 

microbiologicallyinfluenced corrosion; 

fouling that leads to 

corrosion

Chapter XI.M20, "

Cycle Cooling Wa

System"

V.A.EP-100 V.A11(EP39)Heat exchanger tubes Copper alloy Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, 

Treated Water Sys

V.A.EP-78 V.A12(EP47)Heat exchanger tubes Copper alloy Lubricating oil Reduction of heat 

transfer 

due to fouling

Chapter XI.M39, 

"Lubricating Oil An

and 

Chapter XI.M32, “

Time Inspection”

V.A.EP-96 V.A13(EP35)Heat exchanger tubes Stainless 

steel

Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, 

Treated Water Sys

V.A.EP-79 V.A14(EP50)Heat exchanger tubes Stainless 

steel

Lubricating oil Reduction of heat 

transfer 

due to fouling

Chapter XI.M39, 

"Lubricating Oil An

and 

Chapter XI.M32, “

Time Inspection”

V.A.E-21 V.A15(E-21)Heat exchanger tubes Stainless 

steel

Raw water Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "

Cycle Cooling Wa

System"
NUREG-1801, Rev. 2 V A-4 December 2010

V ENGINEERED SAFETY FEATURES

A Containment Spray System (PWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism

Aging Manageme

Program (AMP)

V.A.EP-74 V.A16(EP34)Heat exchanger tubes Stainless 

steel

Treated water Reduction of heat 

transfer 

due to fouling

Chapter XI.M2, “W

Chemistry,” and 

Chapter XI.M32, “

Time Inspection”

V.A.EP-75 V.A17(EP40)Heat exchanger tubes Steel Lubricating oil Reduction of heat 

transfer 

due to fouling

Chapter XI.M39, 

"Lubricating Oil An

and 

Chapter XI.M32, “

Time Inspection”

V.A.E-43 V.A18(E-43)Motor cooler Gray cast iron Treated water Loss of material 

due to selective leaching

Chapter XI.M33, “

Leaching”

V.A.E-29 V.A19(E-29)Piping and components 

(Internal surfaces)

Steel Air – indoor, 

uncontrolled 

(Internal)

Loss of material 

due to general corrosion

Chapter XI.M38, 

"Inspection of Inte

Surfaces in Misce

Piping and Ductin

Components"

V.A.EP-97 V.A20(EP36)Piping, piping 

components, and piping 

elements

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to pitting, crevice, 

and galvanic corrosion

Chapter XI.M21A, 

Treated Water Sys

V.A.EP-76 V.A21(EP45)Piping, piping 

components, and piping 

elements

Copper alloy Lubricating oil Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M39, 

"Lubricating Oil An

and 

Chapter XI.M32, “

Time Inspection”

V.A.EP-27 V.A22(EP27)Piping, piping 

components, and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Closed-cycle 

cooling water

Loss of material 

due to selective leaching

Chapter XI.M33, “

Leaching”

V.A.EP-95 V.A23(EP33)

Piping, piping 

components, and piping 

elements

Stainless 

steel

Closed-cycle 

cooling water

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M21A, 

Treated Water Sys
December 2010 V A-5 NUREG-1801, Rev. 2

V ENGINEERED SAFETY FEATURES

A Containment Spray System (PWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism

Aging Manageme

Program (AMP)

V.A.EP-98 V.A24(EP44)Piping, piping 

components, and piping 

elements

Stainless 

steel

Closed-cycle 

cooling water 

>60°C 

(>140°F)

Cracking 

due to stress corrosion 

cracking

Chapter XI.M21A, 

Treated Water Sys

V.A.EP-77 V.A25(EP46)Piping, piping 

components, and piping 

elements

Steel Lubricating oil Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.M39, 

"Lubricating Oil An

and 

Chapter XI.M32, “

Time Inspection”

V.A.EP-81 V.A26(EP53)Piping, piping 

components, and piping 

elements (Internal 

surfaces); tanks

Stainless 

steel

Condensation 

(Internal)

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M38, 

"Inspection of Inte

Surfaces in Misce

Piping and Ductin

Components"

V.A.EP-41 V.A27(EP41)Piping, piping 

components, and piping 

elements; tanks

Stainless 

steel

Treated water 

(borated)

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M2, “W

Chemistry”

V.A.E-12 V.A28(E-12)Piping, piping 

components, and piping 

elements; tanks

Stainless 

steel

Treated water 

(borated) 

>60°C 

(>140°F)

Cracking 

due to stress corrosion 

cracking

Chapter XI.M2, “W

Chemistry”

December 2010 V B-1 NUREG-1801, Rev. 2

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 period of extended 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. 2 V B-2 December 2010

V ENGINEERED SAFETY FEATURES

B Standby Gas Treatment System (BWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progra

(AMP)

V.B.E-25 V.B-1(E25)Ducting and 

components 

(Internal 

surfaces)

Steel Air – indoor, 

uncontrolled 

(Internal)

Loss of material 

due to general 

corrosion

Chapter XI.M38, "Inspection 

Internal Surfaces in Miscella

Piping and Ducting Compon

V.B.E-40 V.B-2(E40)Ducting, closure 

bolting

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

V.B.E-26 V.B-3(E26)Ducting, piping, 

and components 

(External 

surfaces)

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

V.B.EP-59 V.B-4(E06)Elastomer seals 

and components

Elastomers Air – indoor, 

uncontrolled 

(External)

Hardening and 

loss of strength 

due to elastomer 

degradation

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

V.B.EP-58 V.B-4(E06)Elastomer seals 

and components

Elastomers Air – indoor, 

uncontrolled 

(Internal)

Hardening and 

loss of strength 

due to elastomer 

degradation

Chapter XI.M38, "Inspection 

Internal Surfaces in Miscella

Piping and Ducting Compon

V.B.EP-37 V.B-5(EP37)Heat exchanger 

components

Copper alloy 

(>15% Zn or 

>8% Al)

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

V.B.EP-97 V.B-6(EP36)Piping, piping 

components, 

and piping 

elements

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to pitting, 

crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed T

Water Systems"

V.B.EP-27 V.B-7(EP27)Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”
December 2010 V B-3 NUREG-1801, Rev. 2

V ENGINEERED SAFETY FEATURES

B Standby Gas Treatment System (BWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progra

(AMP)

V.B.EP-54 V.B-8(EP54)Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Soil Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

V.B.EP-111 V.B-9(E42)Piping, piping 

components, 

and piping 

elements

Steel (with 

coating or 

wrapping)

Soil or concrete Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M41, "Buried and 

Underground Piping and Ta

V.B.EP-103 Piping, piping 

components, 

and piping 

elements; tanks

Stainless 

steel

Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

V.B.EP-107 Piping, piping 

components, 

and piping 

elements; tanks

Stainless 

steel

Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

December 2010 V C-1 NUREG-1801, Rev. 2

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 period of extended 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. 2 V C-2 December 2010

V ENGINEERED SAFETY FEATURES

C Containment Isolation Components

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progra

(AMP)

V.C.E-35 V.C-1(E35)Containment 

isolation piping 

and components 

(External 

surfaces)

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

V.C.E-30 V.C-2(E30)Containment 

isolation piping 

and components 

(External 

surfaces)

Steel Condensation 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

V.C.E-34 V.C-3(E34)Containment 

isolation piping 

and components 

(Internal 

surfaces)

Stainless 

steel

Raw water Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

corrosion

Chapter XI.M20, "Open-Cyc

Cooling Water System"

V.C.EP-63 V.C-4(E33)Containment 

isolation piping 

and components 

(Internal 

surfaces)

Stainless 

steel

Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chem

and 

Chapter XI.M32, “One-Time 

Inspection”

V.C.E-22 V.C-5(E22)Containment 

isolation piping 

and components 

(Internal 

surfaces)

Steel Raw water Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

corrosion

Chapter XI.M20, "Open-Cyc

Cooling Water System"
December 2010 V C-3 NUREG-1801, Rev. 2

V ENGINEERED SAFETY FEATURES

C Containment Isolation Components

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progra

(AMP)

V.C.EP-62 V.C-6(E31)Containment 

isolation piping 

and components 

(Internal 

surfaces)

Steel Treated water Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M2, “Water Chem

and 

Chapter XI.M32, “One-Time 

Inspection”

V.C.EP-95 V.C7(EP-33)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed-cycle 

cooling water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M21A, "Closed T

Water Systems"

V.C.EP-98 V.C8(EP-44)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed-cycle 

cooling water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M21A, "Closed T

Water Systems"

V.C.EP-99 V.C9(EP-48)Piping, piping 

components, 

and piping 

elements

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M21A, "Closed T

Water Systems"

V.C.EP-103 Piping, piping 

components, 

and piping 

elements; tanks

Stainless 

steel

Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

V.C.EP-107 Piping, piping 

components, 

and piping 

elements; tanks

Stainless 

steel

Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

December 2010 V D1-1 NUREG-1801, Rev. 2

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. The core cooling systems consist of the core flood system (CFS), residual heat 

removal (RHR) (or shutdown cooling (SDC)), high-pressure safety injection (HPSI), lowpressure 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 period of extended 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. 2 V D1-2 December 2010

V ENGINEERED SAFETY FEATURES

D1 Emergency Core Cooling System (PWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism

Aging Managem

Program (AMP)

V.D1.E-28 V.D1-

1(E-28)

External surfaces Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, 

Acid Corrosion”

V.D1.EP94V.D1-

2(EP13)

Heat exchanger 

components

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to pitting, crevice, 

and galvanic corrosion

Chapter XI.M21A

"Closed Treated 

Systems"

V.D1.EP37V.D1-

3(EP37)

Heat exchanger 

components

Copper alloy 

(>15% Zn or >8% 

Al)

Closed-cycle 

cooling water

Loss of material 

due to selective leaching

Chapter XI.M33, 

“Selective Leach

V.D1.EP93V.D1-

4(E-19)

Heat exchanger 

components

Stainless steel Closed-cycle 

cooling water

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M21A

"Closed Treated 

Systems"

V.D1.EP91V.D1-

5(E-20)

Heat exchanger 

components

Stainless steel Raw water Loss of material 

due to pitting, crevice, 

and microbiologicallyinfluenced corrosion; 

fouling that leads to 

corrosion

Chapter XI.M20, 

Cycle Cooling W

System"

V.D1.EP92V.D1-

6(E-17)

Heat exchanger 

components

Steel Closed-cycle 

cooling water

Loss of material 

due to general, pitting, 

crevice, and galvanic 

corrosion

Chapter XI.M21A

"Closed Treated 

Systems"

V.D1.EP90V.D1-

7(E-18)

Heat exchanger 

components

Steel Raw water Loss of material 

due to general, pitting, 

crevice, and 

microbiologicallyinfluenced corrosion; 

fouling that leads to 

corrosion

Chapter XI.M20, 

Cycle Cooling W

System"
December 2010 V D1-3 NUREG-1801, Rev. 2

V ENGINEERED SAFETY FEATURES

D1 Emergency Core Cooling System (PWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism

Aging Managem

Program (AMP)

V.D1.EP78V.D1-

8(EP47)

Heat exchanger 

tubes

Copper alloy Lubricating oil Reduction of heat 

transfer 

due to fouling

Chapter XI.M39, 

"Lubricating Oil 

Analysis," and 

Chapter XI.M32, 

Time Inspection”

V.D1.EP96V.D1-

19(EP35)

Heat exchanger 

tubes

Stainless steel Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A

"Closed Treated 

Systems"

V.D1.EP79V.D1-

10(EP50)

Heat exchanger 

tubes

Stainless steel Lubricating oil Reduction of heat 

transfer 

due to fouling

Chapter XI.M39, 

"Lubricating Oil 

Analysis," and 

Chapter XI.M32, 

Time Inspection”

V.D1.E-21 V.D1-

11(E21)

Heat exchanger 

tubes

Stainless steel Raw water Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, 

Cycle Cooling W

System"

V.D1.EP75V.D1-

12(EP40)

Heat exchanger 

tubes

Steel Lubricating oil Reduction of heat 

transfer 

due to fouling

Chapter XI.M39, 

"Lubricating Oil 

Analysis," and 

Chapter XI.M32, 

Time Inspection”

V.D1.E-43 V.D1-

13(E43)

Motor cooler Gray cast iron Treated water Loss of material 

due to selective leaching

Chapter XI.M33, 

“Selective Leach
NUREG-1801, Rev. 2 V D1-4 December 2010

V ENGINEERED SAFETY FEATURES

D1 Emergency Core Cooling System (PWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism

Aging Managem

Program (AMP)

V.D1.E-24 V.D1-

14(E24)

Orifice (miniflow 

recirculation)

Stainless steel Treated water 

(borated)

Loss of material 

due to erosion

A plant-specific a

management pro

to be evaluated f

erosion of the or

to extended use 

centrifugal HPSI 

for normal charg

LER 50-275/94-0

evidence of eros

V.D1.E-01 V.D1-

15(E01)

Partially-encased 

tanks with breached 

moisture barrier

Stainless steel Raw water Loss of material 

due to pitting and crevice 

corrosion

A plant-specific a

management pro

to be evaluated f

and crevice corro

tank bottom beca

moisture and wa

egress under the 

due to cracking o

perimeter seal fr

weathering.

V.D1.EP101V.D2-

18(EP2)

Piping, piping 

components, and 

piping elements

Aluminum Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, 

Acid Corrosion”

V.D1.E-47 V.D1-

16(E47)

Piping, piping 

components, and 

piping elements

Cast austenitic 

stainless steel

Treated water 

(borated) 

>250°C 

(>482°F)

Loss of fracture 

toughness 

due to thermal aging 

embrittlement

Chapter XI.M12, 

"Thermal Aging 

Embrittlement of 

Austenitic Stainle

(CASS)"

V.D1.EP97V.D1-

17(EP36)

Piping, piping 

components, and 

piping elements

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to pitting, crevice, 

and galvanic corrosion

Chapter XI.M21A

"Closed Treated 

Systems"
December 2010 V D1-5 NUREG-1801, Rev. 2

V ENGINEERED SAFETY FEATURES

D1 Emergency Core Cooling System (PWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism

Aging Managem

Program (AMP)

V.D1.EP76V.D1-

19(EP45)

Piping, piping 

components, and 

piping elements

Copper alloy Lubricating oil Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M39, 

"Lubricating Oil 

Analysis," and 

Chapter XI.M32, 

Time Inspection”

V.D1.EP27V.D1-

19(EP27)

Piping, piping 

components, and 

piping elements

Copper alloy 

(>15% Zn or >8% 

Al)

Closed-cycle 

cooling water

Loss of material 

due to selective leaching

Chapter XI.M33, 

“Selective Leach

V.D1.EP52V.D1-

20(EP52)

Piping, piping 

components, and 

piping elements

Gray cast iron Closed-cycle 

cooling water

Loss of material 

due to selective leaching

Chapter XI.M33, 

“Selective Leach

V.D1.EP54V.D1-

21(EP54)

Piping, piping 

components, and 

piping elements

Gray cast iron Soil Loss of material 

due to selective leaching

Chapter XI.M33, 

“Selective Leach

V.D1.EP95V.D1-

22(EP33)

Piping, piping 

components, and 

piping elements

Stainless steel Closed-cycle 

cooling water

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M21A

"Closed Treated 

Systems"

V.D1.EP98V.D1-

23(EP44)

Piping, piping 

components, and 

piping elements

Stainless steel Closed-cycle 

cooling water 

>60°C (>140°F)

Cracking 

due to stress corrosion 

cracking

Chapter XI.M21A

"Closed Treated 

Systems"

V.D1.EP80V.D1-

24(EP51)

Piping, piping 

components, and 

piping elements

Stainless steel Lubricating oil Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M39, 

"Lubricating Oil 

Analysis," and 

Chapter XI.M32, 

Time Inspection”

V.D1.EP55V.D1-

25(EP55)

Piping, piping 

components, and 

piping elements

Stainless steel Raw water Loss of material 

due to pitting, crevice, 

and microbiologicallyinfluenced corrosion

Chapter XI.M20, 

Cycle Cooling W

System"
NUREG-1801, Rev. 2 V D1-6 December 2010

V ENGINEERED SAFETY FEATURES

D1 Emergency Core Cooling System (PWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism

Aging Managem

Program (AMP)

V.D1.EP72V.D1-

26(EP31)

Piping, piping 

components, and 

piping elements

Stainless steel Soil or concrete Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M41, 

and Undergroun

and Tanks"

V.D1.E-13 V.D1-

27(E13)

Piping, piping 

components, and 

piping elements

Stainless steel Treated water 

(borated)

Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time

aging analysis (T

be evaluated for 

period of extende

operation. See th

Section 4.3 “Met

Fatigue,” for acc

methods for mee

requirements of 

54.21(c)(1).

V.D1.EP77V.D1-

28(EP46)

Piping, piping 

components, and 

piping elements

Steel Lubricating oil Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.M39, 

"Lubricating Oil 

Analysis," and 

Chapter XI.M32, 

Time Inspection”

V.D1.EP81V.D1-

29(EP53)

Piping, piping 

components, and 

piping elements 

(Internal surfaces); 

tanks

Stainless steel Condensation 

(Internal)

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M38, 

"Inspection of Int

Surfaces in 

Miscellaneous P

and Ducting 

Components"

V.D1.EP103Piping, piping 

components, and 

piping elements; 

tanks

Stainless steel Air – outdoor Cracking 

due to stress corrosion 

cracking

Chapter XI.M36, 

"External Surfac

Monitoring of Me

Components"
December 2010 V D1-7 NUREG-1801, Rev. 2

V ENGINEERED SAFETY FEATURES

D1 Emergency Core Cooling System (PWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism

Aging Managem

Program (AMP)

V.D1.EP107Piping, piping 

components, and 

piping elements; 

tanks

Stainless steel Air – outdoor Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M36, 

"External Surfac

Monitoring of Me

Components"

V.D1.EP41V.D1-

30(EP41)

Piping, piping 

components, and 

piping elements; 

tanks

Stainless steel Treated water 

(borated)

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M2, “

Chemistry”

V.D1.E-12 V.D1-

31(E12)

Piping, piping 

components, and 

piping elements; 

tanks

Stainless steel Treated water 

(borated) >60°C 

(>140°F)

Cracking 

due to stress corrosion 

cracking

Chapter XI.M2, “

Chemistry”

V.D1.EP49V.D1-

32(EP49)

Pump casings Steel (with 

stainless steel 

cladding)

Treated water 

(borated)

Loss of material 

due to cladding breach

A plant-specific a

management pro

to be evaluated 

Reference NRC 

Information Notic

“Boric Acid Corro

Charging Pump 

Caused by Cladd

Cracks."

V.D1.E-38 V.D1-

33(E38)

Safety injection tank 

(accumulator)

Steel (with 

stainless steel or 

nickel-alloy 

cladding)

Treated water 

(borated) >60°C 

(>140°F)

Cracking 

due to stress corrosion 

cracking

Chapter XI.M2, “

Chemistry”

December 2010 V D2-1 NUREG-1801, Rev. 2

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.

The cooling systems consist of the high-pressure coolant injection (HPCI), reactor core isolation 

cooling (RCIC), high-pressure core spray (HPCS), automatic depressurization (ADS), lowpressure 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 period of extended 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. 2 V D2-2 December 2010

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)

V.D2.EP-113 V.D2-

1(E-04)

Drywell and 

suppression 

chamber spray 

system (internal 

surfaces): flow 

orifice; spray 

nozzles

Steel Air – indoor, 

uncontrolled 

(Internal)

Loss of material 

due to general 

corrosion; fouling that 

leads to corrosion

A plant-specific aging 

management program 

evaluated

V.D2.E-26 V.D2-

2(E-26)

Ducting, piping, 

and components 

(External 

surfaces)

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "Exte

Surfaces Monitoring o

Mechanical Compone

V.D2.EP-94 V.D2-

3(EP-13)

Heat exchanger 

components

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to pitting, 

crevice, and galvanic 

corrosion

Chapter XI.M21A, "Cl

Treated Water System

V.D2.EP-37 V.D2-

4(EP-37)

Heat exchanger 

components

Copper alloy

(>15% Zn or 

>8% Al)

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Sele

Leaching”

V.D2.EP-93 V.D2-

5(E-19)

Heat exchanger 

components

Stainless steel Closed-cycle 

cooling water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M21A, "Cl

Treated Water System

V.D2.EP-91 V.D2-

6(E-20)

Heat exchanger 

components

Stainless steel Raw water Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced corrosion; 

fouling that leads to 

corrosion

Chapter XI.M20, "Ope

Cooling Water System

V.D2.EP-92 V.D2-

7(E-17)

Heat exchanger 

components

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Cl

Treated Water System
December 2010 V D2-3 NUREG-1801, Rev. 2

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)

V.D2.EP-90 V.D2-

8(E-18)

Heat exchanger 

components

Steel Raw water Loss of material 

due to general, 

pitting, crevice, and 

microbiologicallyinfluenced corrosion; 

fouling that leads to 

corrosion

Chapter XI.M20, "Ope

Cooling Water System

V.D2.EP-78 V.D2-

9(EP-47)

Heat exchanger 

tubes

Copper alloy Lubricating oil Reduction of heat 

transfer 

due to fouling

Chapter XI.M39, "Lub

Oil Analysis," and 

Chapter XI.M32, “One

Inspection”

V.D2.EP-96 V.D2-

10(EP35)

Heat exchanger 

tubes

Stainless steel Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Cl

Treated Water System

V.D2.EP-79 V.D2-

11(EP50)

Heat exchanger 

tubes

Stainless steel Lubricating oil Reduction of heat 

transfer 

due to fouling

Chapter XI.M39, "Lub

Oil Analysis," and 

Chapter XI.M32, “One

Inspection”

V.D2.E-21 V.D2-

12(E-21)

Heat exchanger 

tubes

Stainless steel Raw water Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "Ope

Cooling Water System

V.D2.EP-74 V.D2-

13(EP34)

Heat exchanger 

tubes

Stainless steel Treated water Reduction of heat 

transfer 

due to fouling

Chapter XI.M2, “Wate

Chemistry,” and 

Chapter XI.M32, “One

Inspection”

V.D2.EP-75 V.D2-

14(EP40)

Heat exchanger 

tubes

Steel Lubricating oil Reduction of heat 

transfer 

due to fouling

Chapter XI.M39, "Lub

Oil Analysis," and 

Chapter XI.M32, “One

Inspection”

V.D2.E-23 V.D2-

15(E-23)

Heat exchanger 

tubes

Steel Raw water Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "Ope

Cooling Water System
NUREG-1801, Rev. 2 V D2-4 December 2010

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)

V.D2.E-29 V.D2-

16(E-29)

Piping and 

components 

(Internal 

surfaces)

Steel Air – indoor, 

uncontrolled 

(Internal)

Loss of material 

due to general 

corrosion

Chapter XI.M38, "Insp

Internal Surfaces in 

Miscellaneous Piping 

Ducting Components"

V.D2.E-27 V.D2-

17(E-27)

Piping and 

components 

(Internal 

surfaces)

Steel Condensation 

(Internal)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M38, "Insp

Internal Surfaces in 

Miscellaneous Piping 

Ducting Components"

V.D2.EP-71 V.D2-

19(EP26)

Piping, piping 

components, 

and piping 

elements

Aluminum Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Wate

Chemistry,” and 

Chapter XI.M32, “One

Inspection”

V.D2.E-11 V.D2-

20(E-11)

Piping, piping 

components, 

and piping 

elements

Cast austenitic 

stainless steel

Treated water 

>250°C (>482°F)

Loss of fracture 

toughness 

due to thermal aging 

embrittlement

Chapter XI.M12, "The

Aging Embrittlement o

Austenitic Stainless S

(CASS)"

V.D2.EP-97 V.D2-

21(EP36)

Piping, piping 

components, 

and piping 

elements

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to pitting, 

crevice, and galvanic 

corrosion

Chapter XI.M21A, "Cl

Treated Water System

V.D2.EP-76 V.D2-

22(EP45)

Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M39, "Lub

Oil Analysis," and 

Chapter XI.M32, “One

Inspection”

V.D2.EP-27 V.D2-

23(EP27)

Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Sele

Leaching”

V.D2.EP-54 V.D2-

24(EP54)

Piping, piping 

components, 

and piping 

elements

Gray cast iron Soil Loss of material 

due to selective 

leaching

Chapter XI.M33, “Sele

Leaching”
December 2010 V D2-5 NUREG-1801, Rev. 2

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)

V.D2.EP-95 V.D2-

25(EP33)

Piping, piping 

components, 

and piping 

elements

Stainless steel Closed-cycle 

cooling water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M21A, "Cl

Treated Water System

V.D2.EP-98 V.D2-

26(EP44)

Piping, piping 

components, 

and piping 

elements

Stainless steel Closed-cycle 

cooling water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M21A, "Cl

Treated Water System

V.D2.EP-72 V.D2-

27(EP31)

Piping, piping 

components, 

and piping 

elements

Stainless steel Soil or concrete Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M41, "Buri

Underground Piping a

Tanks"

V.D2.EP-73 V.D2-

28(EP32)

Piping, piping 

components, 

and piping 

elements

Stainless steel Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Wate

Chemistry,” and 

Chapter XI.M32, “One

Inspection”

V.D2.E-37 V.D2-

29(E-37)

Piping, piping 

components, 

and piping 

elements

Stainless steel Treated water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking, 

intergranular stress 

corrosion cracking

Chapter XI.M7, “BWR 

Corrosion Cracking,” a

Chapter XI.M2, “Wate

Chemistry”

V.D2.EP-77 V.D2-

30(EP46)

Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M39, "Lub

Oil Analysis," and 

Chapter XI.M32, “One

Inspection”

V.D2.E-07 V.D2-

31(E-07)

Piping, piping 

components, 

and piping 

elements

Steel Steam Wall thinning 

due to flowaccelerated corrosion

Chapter XI.M17, “Flow

Accelerated Corrosion
NUREG-1801, Rev. 2 V D2-6 December 2010

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)

V.D2.E-10 V.D2-

32(E-10)

Piping, piping 

components, 

and piping 

elements

Steel Treated water Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time-limite

analysis (TLAA) to be 

evaluated for the perio

extended operation. S

SRP, Section 4.3 “Me

Fatigue,” for acceptab

methods for meeting t

requirements of 10 CF

54.21(c)(1).

V.D2.EP-60 V.D2-

33(E-08)

Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M2, “Wate

Chemistry,” and 

Chapter XI.M32, “One

Inspection”

V.D2.E-09 V.D2-

34(E-09)

Piping, piping 

components, 

and piping 

elements

Steel Treated water Wall thinning 

due to flowaccelerated corrosion

Chapter XI.M17, “Flow

Accelerated Corrosion

V.D2.EP-61 V.D2-

35(E-14)

Piping, piping 

components, 

and piping 

elements 

(Internal 

surfaces)

Stainless steel Condensation 

(Internal)

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M38, "Insp

Internal Surfaces in 

Miscellaneous Piping 

Ducting Components"

V.D2.EP-103 Piping, piping 

components, 

and piping 

elements; tanks

Stainless steel Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "Exte

Surfaces Monitoring o

Mechanical Compone

V.D2.EP-107 Piping, piping 

components, 

and piping 

elements; tanks

Stainless steel Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "Exte

Surfaces Monitoring o

Mechanical Compone
December 2010 V E-1 NUREG-1801, Rev. 2

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. 2 V E-2 December 2010

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 

V.E.EP-116 Bolting Copper 

alloy

Any 

environment

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integ

V.E.EP-117 Bolting Nickel alloy Any 

environment

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integ

V.E.EP-120 Bolting Stainless 

steel

Treated borated 

water

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integ

V.E.E-41 V.E-2(E41)Bolting Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

V.E.EP-64 V.E-1(EP1)Bolting Steel; 

stainless 

steel

Air – outdoor 

(External)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice corrosion

Chapter XI.M18, "Bolting Integ

V.E.EP-118 Bolting Steel; 

stainless 

steel

Air – outdoor 

(External)

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integ
December 2010 V E-3 NUREG-1801, Rev. 2 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 

V.E.EP-121 Bolting Steel; 

stainless 

steel

Fuel oil Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integ

V.E.EP-119 Bolting Steel; 

stainless 

steel

Raw water Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integ

V.E.EP-122 Bolting Steel; 

stainless 

steel

Treated water Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integ

V.E.E-02 V.E-6(E02)Closure 

bolting

Steel Air with steam 

or water 

leakage

Loss of material 

due to general 

corrosion

Chapter XI.M18, "Bolting Integ

V.E.E-03 V.E-3(E03)Closure 

bolting

Steel, highstrengthAir with steam 

or water 

leakage

Cracking 

due to cyclic 

loading, stress 

corrosion 

cracking

Chapter XI.M18, "Bolting Integ

V.E.EP-70 V.E-4(EP25)Closure 

bolting

Steel; 

stainless 

steel

Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice corrosion

Chapter XI.M18, "Bolting Integ
NUREG-1801, Rev. 2 V E-4 December 2010

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 

V.E.EP-69 V.E-5(EP24)Closure 

bolting

Steel; 

stainless 

steel

Air – indoor, 

uncontrolled 

(External)

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integ

V.E.E-44 V.E-7(E44)External 

surfaces

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External Sur

Monitoring of Mechanical 

Components"

V.E.E-45 V.E-8(E45)External 

surfaces

Steel Air – outdoor 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External Sur

Monitoring of Mechanical 

Components"

V.E.E-28 V.E-9(E28)External 

surfaces

Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

V.E.E-46 V.E-10(E46)External 

surfaces

Steel Condensation 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External Sur

Monitoring of Mechanical 

Components"

V.E.EP-114 Piping, piping 

components, 

and piping 

elements

Aluminum Air - outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External Sur

Monitoring of Mechanical 

Components"

V.E.EP-38 V.E11(EP-38)Piping, piping 

components, 

and piping 

elements

Copper 

alloy (>15% 

Zn or >8% 

Al)

Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

V.E.EP-123 Underground 

piping, piping 

components, 

and piping 

elements

Steel; 

stainless 

steel

Air-indoor, 

uncontrolled 

(External) or 

condensation 

(External)

Loss of material 

due to general 

(steel only), 

pitting and 

crevice corrosion

Chapter XI.M41, “Buried and 

Underground Piping and Tank
December 2010 V F-1 NUREG-1801, Rev. 2

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 period of extended 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. 2 V F-2 December 2010

V ENGINEERED SAFETY FEATURES

F Common Miscellaneous Material/Environment Combinations

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Prog

(AMP)

V.F.EP-14 V.F-1(EP14)Ducting, 

piping, and 

components

Galvanized 

steel

Air – indoor, 

controlled 

(External)

None None 

V.F.EP-15 V.F-6(EP15)Piping 

elements

Glass Air – indoor, 

uncontrolled 

(External)

None None 

V.F.EP-87 Piping 

elements

Glass Air – outdoor None None 

V.F.EP-65 Piping 

elements

Glass Air with borated 

water leakage

None None 

V.F.EP-68 Piping 

elements

Glass Closed-cycle 

cooling water

None None 

V.F.EP-66 Piping 

elements

Glass Condensation 

(Internal/External)

None None 

V.F.EP-67 Piping 

elements

Glass Gas None None 

V.F.EP-16 V.F-7(EP16)Piping 

elements

Glass Lubricating oil None None 

V.F.EP-28 V.F-8(EP28)Piping 

elements

Glass Raw water None None 
December 2010 V F-3 NUREG-1801, Rev. 2

V ENGINEERED SAFETY FEATURES

F Common Miscellaneous Material/Environment Combinations

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Prog

(AMP)

V.F.EP-29 V.F10(EP-29)Piping 

elements

Glass Treated water None None 

V.F.EP-30 V.F-9(EP30)Piping 

elements

Glass Treated water 

(borated)

None None 

V.F.EP-3 V.F-2(EP3)Piping, piping 

components, 

and piping 

elements

Aluminum Air – indoor, 

uncontrolled 

(Internal/External)

None None 

V.F.EP-10 V.F-3(EP10)Piping, piping 

components, 

and piping 

elements

Copper alloy Air – indoor, 

uncontrolled 

(External)

None None 

V.F.EP-9 V.F-4(EP9)Piping, piping 

components, 

and piping 

elements

Copper alloy Gas None None 

V.F.EP-12 V.F-5(EP12)Piping, piping 

components, 

and piping 

elements

Copper alloy 

(≤15% Zn and 

≤8% Al)

Air with borated 

water leakage

None None 

V.F.EP-17 V.F11(EP-17)Piping, piping 

components, 

and piping 

elements

Nickel alloy Air – indoor, 

uncontrolled 

(External)

None None 

V.F.EP-115 Piping, piping 

components, 

and piping 

elements

Nickel alloy Air with borated 

water leakage

None None 
NUREG-1801, Rev. 2 V F-4 December 2010

V ENGINEERED SAFETY FEATURES

F Common Miscellaneous Material/Environment Combinations

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Prog

(AMP)

V.F.EP-18 V.F12(EP-18)Piping, piping 

components, 

and piping 

elements

Stainless steel Air – indoor, 

uncontrolled 

(External)

None None 

V.F.EP-82 Piping, piping 

components, 

and piping 

elements

Stainless steel Air – indoor, 

uncontrolled 

(Internal)

None None 

V.F.EP-19 V.F13(EP-19)Piping, piping 

components, 

and piping 

elements

Stainless steel Air with borated 

water leakage

None None 

V.F.EP-20 V.F14(EP-20)Piping, piping 

components, 

and piping 

elements

Stainless steel Concrete None None 

V.F.EP-22 V.F15(EP-22)Piping, piping 

components, 

and piping 

elements

Stainless steel Gas None None 

V.F.EP-4 V.F16(EP-4)Piping, piping 

components, 

and piping 

elements

Steel Air – indoor, 

controlled 

(External)

None None 

V.F.EP-112 V.F17(EP-5)Piping, piping 

components, 

and piping 

elements

Steel Concrete None None, provided 

1) attributes of the concrete 

consistent with ACI 318 or 

(low water-to-cement ratio, 

permeability, and adequate 

entrainment) as cited in NU

1557, and 

2) plant OE indicates no 

degradation of the concrete
December 2010 V F-5 NUREG-1801, Rev. 2

V ENGINEERED SAFETY FEATURES

F Common Miscellaneous Material/Environment Combinations

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Prog

(AMP)

V.F.EP-7 V.F18(EP-7)Piping, piping 

components, 

and piping 

elements

Steel Gas None None 

December 2010 VI-i NUREG-1801, Rev. 2

CHAPTER VI 

ELECTRICAL COMPONENTS 

December 2010 VI-iii NUREG-1801, Rev. 2

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

 

 

December 2010 VI A-1 NUREG-1801, Rev. 2

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 (<1000 volts) and medium-voltage (2 kilovolts [kV] to 35 kV). High voltage (> 35 

kV) power cables and connections have unique, specialized constructions and must be 

evaluated on a plant-specific basis.

This section also addresses components that are relied upon to meet the station blackout (SBO) 

requirements for restoration of offsite power. The offsite power system relied upon in the plantspecific current licensing basis for compliance with 10 CFR 50.63, that is used to connect the 

plant to the offsite power source, is included in the SBO restoration equipment scope. The 

electrical distribution equipment out to the first circuit breaker with the offsite distribution system 

(i.e., equipment in the switchyard) should be included within the SBO restoration equipment 

scope. This path typically includes the 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, and associated control circuits and structures. However, the staff's 

review is based on the plant-specific current licensing basis, regulatory requirements, and offsite 

power design configurations.

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 

Systems, Structures, and Components section.
NUREG-1801, Rev. 2 VI A-2 December 2010

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 Managemen

Program (AMP)

VI.A.LP30VI.A1(LP-12)Cable connections 

(metallic parts)

Various 

metals used 

for electrical 

contacts

Air – indoor, 

controlled or 

uncontrolled or 

Air – outdoor

Increased resistance of 

connection 

due to thermal cycling, 

ohmic heating, electrical 

transients, vibration, 

chemical contamination, 

corrosion, and oxidation

Chapter XI.E6, "Elec

Cable Connections 

Subject to 10 CFR 5

Environmental Qual

Requirements"

VI.A.LP35VI.A-4(L03)Conductor insulation 

for inaccessible 

power cables greater 

than or equal to 400 

volts (e.g., installed in 

conduit or direct 

buried)

Various 

organic 

polymers 

(e.g., EPR, 

SR, EPDM, 

XLPE)

Adverse localized 

environment 

caused by 

significant 

moisture

Reduced insulation 

resistance 

due to moisture

Chapter XI.E3, "Inac

Power Cables Not S

10 CFR 50.49 Envir

Qualification Requir

VI.A.LP36VI.A-5(L04)Connector contacts 

for electrical 

connectors exposed 

to borated water 

leakage

Various 

metals used 

for electrical 

contacts

Air with borated 

water leakage

Increased resistance of 

connection 

due to corrosion of 

connector contact 

surfaces caused by 

intrusion of borated water

Chapter XI.M10, “Bo

Corrosion”

VI.A.LP24VI.A7(LP-02)Fuse holders (not 

part of active 

equipment): 

insulation material

Insulation 

material: 

bakelite; 

phenolic 

melamine or 

ceramic; 

molded 

polycarbonate; 

other

Air – indoor, 

controlled or 

uncontrolled

None None 
December 2010 VI A-3 NUREG-1801, Rev. 2

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 Managemen

Program (AMP)

VI.A.LP31VI.A8(LP-01)Fuse holders (not 

part of active 

equipment): metallic 

clamps

Various 

metals used 

for electrical 

connections

Air – indoor, 

controlled or 

uncontrolled

Increased resistance of 

connection 

due to fatigue caused by 

frequent manipulation or 

vibration

Chapter XI.E5, "Fus

Holders" 

No aging managem

program is required 

applicants who can 

demonstrate these f

holders are located 

environment that do

subject them to env

aging mechanisms o

caused by frequent 

manipulation or vibr

VI.A.LP23VI.A8(LP-01)Fuse holders (not 

part of active 

equipment): metallic 

clamps

Various 

metals used 

for electrical 

connections

Air – indoor, 

uncontrolled

Increased resistance of 

connection 

due to chemical 

contamination, corrosion, 

and oxidation (in an air, 

indoor controlled 

environment, increased 

resistance of connection 

due to chemical 

contamination, corrosion 

and oxidation do not 

apply); 

fatigue 

due to ohmic heating, 

thermal cycling, electrical 

transients

Chapter XI.E5, "Fus

Holders"

VI.A.LP32VI.A10(LP11)High-voltage 

insulators

Porcelain; 

malleable iron; 

aluminum; 

galvanized 

steel; cement

Air – outdoor Loss of material 

due to mechanical wear 

caused by wind blowing 

on transmission 

conductors

A plant-specific agin

management progra

evaluated
NUREG-1801, Rev. 2 VI A-4 December 2010

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 Managemen

Program (AMP)

VI.A.LP28VI.A9(LP-07)High-voltage 

insulators

Porcelain; 

malleable iron; 

aluminum; 

galvanized 

steel; cement

Air – outdoor Reduced insulation 

resistance 

due to presence of salt 

deposits or surface 

contamination

A plant-specific agin

management progra

evaluated for plants 

such that the potent

for salt deposits or s

contamination (e.g., 

vicinity of salt water 

industrial pollution)

VI.A.LP33VI.A-2(L01)Insulation material for 

electrical cables and 

connections 

(including terminal 

blocks, fuse holders, 

etc.)

Various 

organic 

polymers 

(e.g., EPR, 

SR, EPDM, 

XLPE)

Adverse localized 

environment 

caused by heat, 

radiation, or 

moisture

Reduced insulation 

resistance 

due to 

thermal/thermoxidative 

degradation of organics, 

radiolysis, and photolysis 

(UV sensitive materials 

only) of organics; 

radiation-induced 

oxidation; 

moisture intrusion

Chapter XI.E1, "Insu

Material for Electrica

and Connections No

to 10 CFR 50.49 

Environmental Qual

Requirements"

VI.A.LP34VI.A-3(L02)Insulation material 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

Reduced insulation 

resistance 

due to 

thermal/thermoxidative 

degradation of organics, 

radiolysis, and photolysis 

(UV sensitive materials 

only) of organics; 

radiation-induced 

oxidation; 

moisture intrusion

Chapter XI.E2, "Insu

Material for Electrica

and Connections No

to 10 CFR 50.49 

Environmental Qual

Requirements Used 

Instrumentation Circ
December 2010 VI A-5 NUREG-1801, Rev. 2

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 Managemen

Program (AMP)

VI.A.LP25VI.A11(LP04)Metal enclosed bus: 

bus/connections

Various 

metals used 

for electrical 

bus and 

connections

Air – indoor, 

controlled or 

uncontrolled or 

Air – outdoor

Increased resistance of 

connection 

due to the loosening of 

bolts caused by thermal 

cycling and ohmic heating

Chapter XI.E4, "Met

Enclosed Bus"

VI.A.LP29VI.A12(LP10)Metal enclosed bus: 

enclosure assemblies

Elastomers Air – indoor, 

controlled or 

uncontrolled or 

Air – outdoor

Surface cracking, crazing, 

scuffing, dimensional 

change (e.g. “ballooning” 

and “necking”), shrinkage,

discoloration, hardening 

and loss of strength

 

due to elastomer 

degradation

Chapter XI.E4, "Met

Enclosed Bus," or 

Chapter XI.M38, "In

of Internal Surfaces 

Miscellaneous Pipin

Ducting Component

VI.A.LP41VI.A13(LP06)Metal enclosed bus: 

external surface of 

enclosure assemblies

Galvanized 

steel; 

aluminum

Air – indoor, 

controlled or 

uncontrolled

None None 

VI.A.LP42VI.A13(LP06)Metal enclosed bus: 

external surface of 

enclosure assemblies

Galvanized 

steel; 

aluminum

Air – outdoor Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.E4, "Met

Enclosed Bus," or 

Chapter XI.S6, "Stru

Monitoring"

VI.A.LP44VI.A13(LP06)Metal enclosed bus: 

external surface of 

enclosure assemblies

Steel Air – indoor, 

controlled

None None 

VI.A.LP43VI.A13(LP06)Metal enclosed bus: 

external surface of 

enclosure assemblies

Steel Air – indoor, 

uncontrolled or 

Air – outdoor

Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.E4, "Met

Enclosed Bus," or 

Chapter XI.S6, "Stru

Monitoring"
NUREG-1801, Rev. 2 VI A-6 December 2010

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 Managemen

Program (AMP)

VI.A.LP26VI.A14(LP05)Metal enclosed bus: 

insulation; insulators

Porcelain; 

xenoy; 

thermo-plastic 

organic 

polymers

Air – indoor, 

controlled or 

uncontrolled or 

Air – outdoor

Reduced insulation 

resistance 

due to thermal/

thermoxidative 

degradation of organics/

thermoplastics, radiationinduced oxidation, 

moisture/debris intrusion, 

and ohmic heating

Chapter XI.E4, "Met

Enclosed Bus"

VI.A.LP39VI.A15(LP09)Switchyard bus and 

connections

Aluminum; 

copper; 

bronze; 

stainless steel; 

galvanized 

steel

Air – outdoor Loss of material 

due to wind-induced 

abrasion; 

Increased resistance of 

connection 

due to oxidation or loss of 

pre-load

A plant-specific agin

management progra

evaluated

VI.A.LP46VI.A16(LP08)Transmission 

conductors

Aluminum Air – outdoor Loss of conductor strength 

due to corrosion

None - for Aluminum 

Conductor Aluminum 

Reinforced (ACAR)

VI.A.LP38VI.A16(LP08)

Transmission 

conductors

Aluminum; 

steel

Air – outdoor Loss of conductor strength 

due to corrosion

A plant-specific agin

management progra

evaluated for Alumin

Conductor Steel Re

(ACSR)

VI.A.LP47VI.A16(LP08)Transmission 

conductors

Aluminum; 

Steel

Air – outdoor Loss of material 

due to wind-induced 

abrasion

A plant-specific agin

management progra

evaluated for ACAR 

ACSR

VI.A.LP48VI.A16(LP08)Transmission 

connectors

Aluminum; 

steel

Air – outdoor Increased resistance of 

connection 

due to oxidation or loss of 

pre-load

A plant-specific agin

management progra

evaluated
December 2010 VI B-1 NUREG-1801, Rev. 2

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. 2 VI B-2 December 2010

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 

VI.B.L-05 VI.B-1(L05)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 aging 

effects

due to various 

mechanisms in 

accordance with 

10 CFR 50.49

EQ is a time-limited aging anal

(TLAA) to be evaluated for the 

of extended operation. See the 

Standard Review Plan, Section 

"Environmental Qualification (E

Electrical Equipment," for acce

methods for meeting the requir

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

 

See Chapter X.E1, "Environme

Qualification (EQ) of Electric 

Components," of this report for 

the requirements of 10 CFR 

54.21(c)(1)(iii).
December 2010 VII-i NUREG-1801, Rev. 2

CHAPTER VII

AUXILIARY SYSTEMS 

December 2010 VII-iii NUREG-1801, Rev. 2

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)

E5. Waste Water Systems

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

December 2010 VII A1-1 NUREG-1801, Rev. 2

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 period of extended 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. 2 VII A1-2 December 2010

VII AUXILIARY SYSTEMS 

A1 New Fuel Storage

Item Link Structure and/or 

Component Material Environment Aging Effect/ Mechanism Aging ManagProgram (AM

VII.A1.A94VII.A1-1(A94)Structural steel Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general, pitting, and 

crevice corrosion

Chapter XI.S6

"Structures Mo
December 2010 VII A2-1 NUREG-1801, Rev. 2

A2. SPENT FUEL STORAGE

Systems, Structures, and Components

This section discusses those structures and components used for spent fuel storage and 

includes 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 period of extended operation are included in 

VII.J. 

The system piping includes all pipe sizes, including instrument piping.

System Interfaces

No other systems discussed in this report interface with those used for spent fuel storage. 
NUREG-1801, Rev. 2 VII A2-2 December 2010

VII AUXILIARY SYSTEMS 

A2 Spent Fuel Storage

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.A2.AP-79 VII.A2-

1(AP-79)

Piping, piping 

components, 

and piping 

elements

Steel (with 

stainless steel 

cladding); 

stainless steel

Treated borated 

water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chem

VII.A2.A-96 VII.A2-6(A96)Spent fuel 

storage racks 

(BWR)

Stainless steel Treated water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion 

cracking

Chapter XI.M2, “Water Chem

VII.A2.A-97 VII.A2-7(A97)Spent fuel 

storage racks 

(PWR)

Stainless steel Treated borated 

water >60°C 

(>140°F)

Cracking 

due to stress 

corrosion 

cracking

Chapter XI.M2, “Water Chem

VII.A2.A-87 VII.A2-2(A87)Spent fuel 

storage racks: 

neutronabsorbing 

sheets (BWR)

Boraflex Treated water Reduction of 

neutronabsorbing 

capacity 

due to boraflex 

degradation

Chapter XI.M22, “Boraflex Mo

VII.A2.AP-236 VII.A2-3(A89)Spent fuel 

storage racks: 

neutronabsorbing 

sheets (BWR)

Boral®; boron 

steel, and 

other materials 

(excluding

Boraflex)

Treated water Reduction of 

neutronabsorbing 

capacity; change 

in dimensions 

and loss of 

material 

due to effects of 

SFP environment

Chapter XI.M40, "Monitoring o

Neutron-Absorbing Materials 

than Boraflex"

VII.A2.A-86 VII.A2-4(A86)Spent fuel 

storage racks: 

neutronabsorbing 

sheets (PWR)

Boraflex Treated borated 

water

Reduction of 

neutronabsorbing 

capacity 

due to boraflex 

degradation

Chapter XI.M22, “Boraflex Mo
December 2010 VII A2-3 NUREG-1801, Rev.

2

VII AUXILIARY SYSTEMS 

A2 Spent Fuel Storage

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.A2.AP-235 VII.A2-5(A88)Spent fuel 

storage racks: 

neutronabsorbing 

sheets (PWR)

Boral®; boron 

steel, and 

other materials 

(excluding

Boraflex)

Treated borated 

water

Reduction of 

neutronabsorbing 

capacity; change 

in dimensions 

and loss of 

material 

due to effects of 

SFP environment

Chapter XI.M40, "Monitoring o

Neutron-Absorbing Materials 

than Boraflex"

December 2010 VII A3-1 NUREG-1801, Rev. 2

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 period of extended 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. 2 VII A3-2 December 2010

VII AUXILIARY SYSTEMS 

A3 Spent Fuel Pool Cooling and Cleanup (PWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progr

(AMP)

VII.A3.AP100VII.A3-1(A15)Elastomers, 

linings

Elastomers Treated borated 

water

Hardening and 

loss of strength 

due to elastomer 

degradation

Chapter XI.M38, "Inspection 

Internal Surfaces in Miscella

Piping and Ducting Compon

VII.A3.A-79 VII.A3-2(A79)External 

surfaces

Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion 

Chapter XI.M10, “Boric Acid 

Corrosion”

VII.A3.AP189VII.A3-3(A63)Heat 

exchanger 

components

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, "Closed T

Water Systems"

VII.A3.AP-1 VII.A3-

4(AP-1)

Piping, piping 

components, 

and piping 

elements

Aluminum Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid 

Corrosion”

VII.A3.AP199VII.A3-

5(AP-12)

Piping, piping 

components, 

and piping 

elements

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, "Closed T

Water Systems"

VII.A3.AP-43 VII.A3-

6(AP-43)

Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or >8% 

Al)

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VII.A3.AP-31 VII.A3-

7(AP-31)

Piping, piping 

components, 

and piping 

elements

Gray cast iron Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”
December 2010 VII A3-3 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS 

A3 Spent Fuel Pool Cooling and Cleanup (PWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progr

(AMP)

VII.A3.AP107VII.A3-9(A39)Piping, piping 

components, 

and piping 

elements

Steel (with 

elastomer lining)

Treated water Loss of material 

due to pitting and 

crevice corrosion 

(only for steel 

after 

lining/cladding 

degradation)

Chapter XI.M2, “Water Che

and 

Chapter XI.M32, “One-Time 

Inspection”

VII.A3.AP-79 VII.A3-

8(AP-79)

Piping, piping 

components, 

and piping 

elements

Steel (with 

stainless steel 

cladding); 

stainless steel

Treated borated 

water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Che

VII.A3.A-56 VII.A3-

10(A-56)

Piping, piping 

components, 

and piping 

elements

Steel (with 

stainless steel or 

nickel-alloy 

cladding)

Treated borated 

water >60°C 

(>140°F)

Cracking 

due to stress 

corrosion 

cracking

Chapter XI.M2, “Water Che

December 2010 VII A4-1 NUREG-1801, Rev. 2

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 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 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 period of extended 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. 2 VII A4-2 December 2010

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 

VII.A4.AP-101 VII.A4-1(A16)Elastomers, 

linings

Elastomers Treated water Hardening and 

loss of strength 

due to elastomer 

degradation

Chapter XI.M38, "Inspection o

Surfaces in Miscellaneous Pip

Ducting Components"

VII.A4.AP-111 VII.A4-2(A70)Heat 

exchanger 

components

Stainless 

steel; steel 

with stainless 

steel 

cladding

Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemis

and 

Chapter XI.M32, “One-Time 

Inspection”

VII.A4.AP-189 VII.A4-3(A63)Heat 

exchanger 

components

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, "Closed Tre

Water Systems"

VII.A4.AP-139 VII.A4-

4(AP-62)

Heat 

exchanger 

tubes

Stainless 

steel

Treated water Reduction of heat 

transfer 

due to fouling

Chapter XI.M2, “Water Chemis

and 

Chapter XI.M32, “One-Time 

Inspection"

VII.A4.AP-130 VII.A4-

5(AP-38)

Piping, piping 

components, 

and piping 

elements

Aluminum Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemis

and 

Chapter XI.M32, “One-Time 

Inspection”

VII.A4.AP-199 VII.A4-

6(AP-12)

Piping, piping 

components, 

and piping 

elements

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, "Closed Tre

Water Systems"

VII.A4.AP-140 VII.A4-

7(AP-64)

Piping, piping 

components, 

and piping 

elements

Copper alloy Treated water Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M2, “Water Chemis

and 

Chapter XI.M32, “One-Time 

Inspection”
December 2010 VII A4-3 NUREG-1801, Rev. 2

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 

VII.A4.AP-43 VII.A4-

8(AP-43)

Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective Le

VII.A4.AP-32 VII.A4-

9(AP-32)

Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective Le

VII.A4.AP-31 VII.A4-

10(AP-31)

Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective Le

VII.A4.AP-110 VII.A4-

11(A-58)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemis

and 

Chapter XI.M32, “One-Time 

Inspection”

VII.A4.AP-108 VII.A4-

12(A-40)

Piping, piping 

components, 

and piping 

elements

Steel (with 

elastomer 

lining or 

stainless 

steel 

cladding)

Treated water Loss of material 

due to pitting and 

crevice corrosion 

(only for steel after 

lining/cladding 

degradation)

Chapter XI.M2, “Water Chemis

and 

Chapter XI.M32, “One-Time 

Inspection”

December 2010 VII A5-1 NUREG-1801, Rev. 2

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 period of extended 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 containments 

(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 [AMR line-items VII.A4.AP-111, 

VII.A4.4AP-139, VII.A4.AP-189].)

December 2010 VII B-1 NUREG-1801, Rev. 2

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 period of extended 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. 2 VII B-2 December 2010

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 

VII.B.A-05 VII.B-1(A05)Cranes - rails Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to wear

Chapter XI.M23, “Inspection of 

Overhead Heavy Load and Ligh

(Related to Refueling) Handling 

Systems”

VII.B.A-07 VII.B-3(A07)Cranes: rails 

and structural 

girders

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M23, “Inspection of 

Overhead Heavy Load and Ligh

(Related to Refueling) Handling 

Systems”

VII.B.A-06 VII.B-2(A06)Cranes: 

structural 

girders

Steel Air – indoor, 

uncontrolled 

(External)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a time-limited aging a

(TLAA) to be evaluated for the p

extended operation for structura

of cranes that fall within the sco

CFR 54. See SRP-LR Sec. 4.7, 

Plant-Specific Time-Limited Agi

Analyses,” for generic guidance 

meeting the requirements of 10 

54.21(c)(1)).
December 2010 VII C1-1 NUREG-1801, Rev. 2

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 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 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 period of extended 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. 2 VII C1-2 December 2010

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 P

(AMP)

VII.C1.AP75VII.C1-

1(AP-75)

Elastomer: 

seals and 

components

Elastomers Raw water Hardening and 

loss of strength 

due to elastomer 

degradation

Chapter XI.M20, "Open

Cooling Water System"

VII.C1.AP76VII.C1-

2(AP-76)

Elastomer: 

seals and 

components

Elastomers Raw water Loss of material 

due to erosion

Chapter XI.M20, "Open

Cooling Water System"

VII.C1.AP179VII.C1-

3(A-65)

Heat 

exchanger 

components

Copper alloy Raw water Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

corrosion

Chapter XI.M20, "Open

Cooling Water System"

VII.C1.A-66 VII.C1-

4(A-66)

Heat 

exchanger 

components

Copper alloy (>15% Zn 

or >8% Al)

Raw water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selec

Leaching”

VII.C1.AP183VII.C1-

5(A-64)

Heat 

exchanger 

components

Steel Raw water Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

corrosion

Chapter XI.M20, "Open

Cooling Water System"
December 2010 VII C1-3 NUREG-1801, Rev. 2

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 P

(AMP)

VII.C1.AP152Heat 

exchanger 

components 

other than 

tubes

Titanium (ASTM 

Grades 1,2, 7, 11, or 

12 that contains > 5% 

aluminum or more than 

0.20% oxygen or any 

amount of tin)

Raw water None None 

VII.C1.A-72 VII.C1-

6(A-72)

Heat 

exchanger 

tubes

Copper alloy Raw water Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "Open

Cooling Water System"

VII.C1.AP187VII.C1-

7(AP-61)

Heat 

exchanger 

tubes

Stainless steel Raw water Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "Open

Cooling Water System"

VII.C1.AP153Heat 

exchanger 

tubes

Titanium Raw water Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "Open

Cooling Water System"

VII.C1.AP173Piping, piping 

components, 

and piping 

elements

Aluminum Soil or concrete Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M41, "Burie

Underground Piping an

VII.C1.AP237Piping, piping 

components, 

and piping 

elements

Asbestos cement pipe Soil or concrete Cracking, spalling, 

corrosion of rebar 

due to exposure of 

rebar

Chapter XI.M41, "Burie

Underground Piping an

VII.C1.AP178Piping, piping 

components, 

and piping 

elements

Concrete Soil or concrete Cracking, spalling, 

corrosion of rebar 

due to exposure of 

rebar

Chapter XI.M41, "Burie

Underground Piping an

VII.C1.AP177Piping, piping 

components, 

and piping 

elements

Concrete cylinder 

piping

Soil or concrete Cracking, spalling, 

corrosion of rebar 

due to exposure of 

rebar

Chapter XI.M41, "Burie

Underground Piping an
NUREG-1801, Rev. 2 VII C1-4 December 2010

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 P

(AMP)

VII.C1.AP253Piping, piping 

components, 

and piping 

elements

Concrete; cementitious 

material 

Air - outdoor Changes in 

material properties 

due to aggressive 

chemical attack

Chapter XI.M36, "Exter

Surfaces Monitoring of 

Mechanical Componen

VII.C1.AP251Piping, piping 

components, 

and piping 

elements

Concrete; cementitious 

material

Air - outdoor Cracking 

due to settling

Chapter XI.M36, "Exter

Surfaces Monitoring of 

Mechanical Componen

VII.C1.AP252Piping, piping 

components, 

and piping 

elements

Concrete; cementitious 

material

Air - outdoor Loss of material 

due to abrasion, 

cavitation, 

aggressive 

chemical attack, 

and leaching

Chapter XI.M36, "Exter

Surfaces Monitoring of 

Mechanical Componen

VII.C1.AP250Piping, piping 

components, 

and piping 

elements

Concrete; cementitious 

material

Raw Water Changes in 

material properties 

due to aggressive 

chemical attack

Chapter XI.M20, "Open

Cooling Water System"

VII.C1.AP248Piping, piping 

components, 

and piping 

elements

Concrete; cementitious 

material

Raw Water Cracking 

due to settling

Chapter XI.M20, "Open

Cooling Water System"

VII.C1.AP249Piping, piping 

components, 

and piping 

elements

Concrete; cementitious 

material

Raw Water Loss of material 

due to abrasion, 

cavitation, 

aggressive 

chemical attack, 

and leaching

Chapter XI.M20, "Open

Cooling Water System"

VII.C1.AP133VII.C1-

8(AP-47)

Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M39, "Lubric

Analysis," and 

Chapter XI.M32, “One-T

Inspection”
December 2010 VII C1-5 NUREG-1801, Rev. 2

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 P

(AMP)

VII.C1.AP196VII.C1-

9(A-44)

Piping, piping 

components, 

and piping 

elements

Copper alloy Raw water Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

corrosion

Chapter XI.M20, "Open

Cooling Water System"

VII.C1.AP174Piping, piping 

components, 

and piping 

elements

Copper Alloy Soil or concrete Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M41, "Burie

Underground Piping an

VII.C1.A-47 VII.C1-

10(A-47)

Piping, piping 

components, 

and piping 

elements

Copper alloy (>15% Zn 

or >8% Al)

Raw water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selec

Leaching”

VII.C1.AP238Piping, piping 

components, 

and piping 

elements

Fiberglass Raw water 

(internal)

Cracking, 

blistering, change 

in color 

due to water 

absorption

Chapter XI.M20, "Open

Cooling Water System" 

VII.C1.AP176Piping, piping 

components, 

and piping 

elements

Fiberglass Soil or concrete Cracking, 

blistering, change 

in color 

due to water 

absorption

Chapter XI.M41, "Burie

Underground Piping an

VII.C1.A-51 VII.C1-

11(A-51)

Piping, piping 

components, 

and piping 

elements

Gray cast iron Raw water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selec

Leaching”
NUREG-1801, Rev. 2 VII C1-6 December 2010

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 P

(AMP)

VII.C1.A-02 VII.C1-

12(A-02)

Piping, piping 

components, 

and piping 

elements

Gray cast iron Soil Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selec

Leaching”

VII.C1.AP239Piping, piping 

components, 

and piping 

elements

HDPE Raw water 

(internal)

Cracking, 

blistering, change 

in color 

due to water 

absorption

Chapter XI.M20, "Open

Cooling Water System" 

VII.C1.AP175Piping, piping 

components, 

and piping 

elements

HDPE Soil or concrete Cracking, 

blistering, change 

in color 

due to water 

absorption

Chapter XI.M41, "Burie

Underground Piping an

VII.C1.AP206VII.C1-

13(AP-53)

Piping, piping 

components, 

and piping 

elements

Nickel alloy Raw water Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M20, "Open

Cooling Water System"

VII.C1.AP156Piping, piping 

components, 

and piping 

elements

Reinforced concrete, 

asbestos cement

Air – outdoor Cracking 

due to aggressive 

chemical attack 

and leaching; 

Changes in 

material properties

due to aggressive 

chemical attack

Chapter XI.M36, "Exter

Surfaces Monitoring of 

Mechanical Componen
December 2010 VII C1-7 NUREG-1801, Rev. 2

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 P

(AMP)

VII.C1.AP155Piping, piping 

components, 

and piping 

elements

Reinforced concrete, 

asbestos cement

Raw water Cracking 

due to aggressive 

chemical attack 

and leaching; 

Changes in 

material properties

due to aggressive 

chemical attack

Chapter XI.M20, "Open

Cooling Water System"

VII.C1.AP157Piping, piping 

components, 

and piping 

elements

Reinforced concrete, 

asbestos cement

Soil or concrete Cracking 

due to aggressive 

chemical attack 

and leaching; 

Changes in 

material properties

due to aggressive 

chemical attack

Chapter XI.M41, "Burie

Underground Piping an

VII.C1.AP138VII.C1-

14(AP-59)

Piping, piping 

components, 

and piping 

elements

Stainless steel Lubricating oil Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M39, "Lubric

Analysis," and 

Chapter XI.M32, “One-T

Inspection”

VII.C1.A-54 VII.C1-

15(A-54)

Piping, piping 

components, 

and piping 

elements

Stainless steel Raw water Loss of material 

due to pitting and 

crevice corrosion; 

fouling that leads 

to corrosion

Chapter XI.M20, "Open

Cooling Water System"

VII.C1.AP137VII.C1-

16(AP-56)

Piping, piping 

components, 

and piping 

elements

Stainless steel Soil or concrete Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M41, "Burie

Underground Piping an
NUREG-1801, Rev. 2 VII C1-8 December 2010

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 P

(AMP)

VII.C1.AP127VII.C1-

17(AP-30)

Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M39, "Lubric

Analysis," and 

Chapter XI.M32, “One-T

Inspection”

VII.C1.AP194VII.C1-

19(A-38)

Piping, piping 

components, 

and piping 

elements

Steel (with coating or 

lining)

Raw water Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

corrosion; 

lining/coating 

degradation

Chapter XI.M20, "Open

Cooling Water System"

VII.C1.AP198VII.C1-

18(A-01)

Piping, piping 

components, 

and piping 

elements

Steel (with coating or 

wrapping)

Soil or concrete Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M41, "Burie

Underground Piping an

VII.C1.AP172Piping, piping 

components, 

and piping 

elements

Super austenitic Soil or concrete Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M41, "Burie

Underground Piping an

VII.C1.AP171Piping, piping 

components, 

and piping 

elements

Titanium Soil or concrete Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M41, "Burie

Underground Piping an
December 2010 VII C1-9 NUREG-1801, Rev. 2

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 P

(AMP)

VII.C1.AP161Piping, piping 

components,

and piping 

elements

Titanium (ASTM 

Grades 1,2, 7, 11, or 

12 that contains > 5% 

aluminum or more than 

0.20% oxygen or any 

amount of tin)

Raw water None None 

VII.C1.AP209Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless steel Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "Exter

Surfaces Monitoring of 

Mechanical Componen

VII.C1.AP221Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless steel Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "Exter

Surfaces Monitoring of 

Mechanical Componen

December 2010 VII C2-1 NUREG-1801, Rev. 2

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 PWR 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 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 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 period of extended 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 PWR 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 
NUREG-1801, Rev. 2 VII C2-2 December 2010

spray system (V.A), the PWR and BWR emergency core cooling systems (V.D1 and V.D2), the 

PWR steam generator blowdown system (VIII.F), the condensate system (VIII.E), and the PWR 

auxiliary feedwater system (VIII.G). 
December 2010 VII C2-3 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS 

C2 Closed-Cycle Cooling Water System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.C2.AP259Elastomer 

seals and 

components

Elastomers Closed-cycle 

cooling water

Hardening and loss 

of strength 

due to elastomer 

degradation

Chapter XI.M38, "Inspection o

Internal Surfaces in Miscellan

Piping and Ducting Compone

VII.C2.AP189VII.C2-1(A63)Heat 

exchanger 

components

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed Tr

Water Systems"

VII.C2.AP205VII.C2-

2(AP-80)

Heat 

exchanger 

tubes

Copper Alloy Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Closed Tr

Water Systems"

VII.C2.AP188VII.C2-

3(AP-63)

Heat 

exchanger 

tubes

Stainless 

steel

Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Closed Tr

Water Systems"

VII.C2.AP254Piping, piping 

components, 

and piping 

elements

Aluminum Closed-cycle 

cooling water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M21A, "Closed Tr

Water Systems"

VII.C2.AP257Piping, piping 

components, 

and piping 

elements

Aluminum Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chem

and 

Chapter XI.M32, “One-Time 

Inspection”

VII.C2.AP199VII.C2-

4(AP-12)

Piping, piping 

components, 

and piping 

elements

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed Tr

Water Systems"

VII.C2.AP133VII.C2-

5(AP-47)

Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M39, "Lubricating 

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”
NUREG-1801, Rev. 2 VII C2-4 December 2010

VII AUXILIARY SYSTEMS 

C2 Closed-Cycle Cooling Water System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.C2.AP-43 VII.C2-

6(AP-43)

Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective L

VII.C2.AP-32 VII.C2-

7(AP-32)

Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective L

VII.C2.A-50 VII.C2-8(A50)Piping, piping 

components, 

and piping 

elements

Gray cast iron Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective L

VII.C2.AP-31 VII.C2-

9(AP-31)

Piping, piping 

components, 

and piping 

elements

Gray cast iron Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective L

VII.C2.A-52 VII.C2-

10(A-52)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed-cycle 

cooling water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M21A, "Closed Tr

Water Systems"

VII.C2.AP186VII.C2-

11(AP-60)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed-cycle 

cooling water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M21A, "Closed Tr

Water Systems"

VII.C2.AP138VII.C2-

12(AP-59)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Lubricating oil Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M39, "Lubricating 

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”
December 2010 VII C2-5 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS 

C2 Closed-Cycle Cooling Water System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.C2.AP127VII.C2-

13(AP-30)

Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M39, "Lubricating 

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”

VII.C2.AP209Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "External Su

Monitoring of Mechanical 

Components"

VII.C2.AP221Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External Su

Monitoring of Mechanical 

Components"

VII.C2.AP202VII.C2-

14(A-25)

Piping, piping 

components, 

and piping 

elements; 

tanks

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M21A, "Closed Tr

Water Systems"

December 2010 VII C3-1 NUREG-1801, Rev. 2

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 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 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 period of extended 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. 2 VII C3-2 December 2010

VII AUXILIARY SYSTEMS 

C3 Ultimate Heat Sink

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progra

(AMP)

VII.C3.AP187VII.C3-

1(AP-61)

Heat 

exchanger 

tubes

Stainless steel Raw water Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "Open-Cyc

Cooling Water System"

VII.C3.AP195VII.C3-2(A43)Piping, piping 

components, 

and piping 

elements

Copper alloy Raw water Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M20, "Open-Cyc

Cooling Water System"

VII.C3.A-47 VII.C3-3(A47)Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Raw water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VII.C3.A-51 VII.C3-4(A51)Piping, piping 

components, 

and piping 

elements

Gray cast iron Raw water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VII.C3.A-02 VII.C3-5(A02)Piping, piping 

components, 

and piping 

elements

Gray cast iron Soil Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VII.C3.AP206VII.C3-

6(AP-53)

Piping, piping 

components, 

and piping 

elements

Nickel alloy Raw water Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M20, "Open-Cyc

Cooling Water System"

VII.C3.A-53 VII.C3-7(A53)Piping, piping 

components, 

and piping 

elements

Stainless steel Raw water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M20, "Open-Cyc

Cooling Water System"

VII.C3.AP137VII.C3-

8(AP-56)

Piping, piping 

components, 

and piping 

elements

Stainless steel Soil Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M41, "Buried and 

Underground Piping and Tan
December 2010 VII C3-3 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS 

C3 Ultimate Heat Sink

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progra

(AMP)

VII.C3.AP194VII.C3-

10(A-38)

Piping, piping 

components, 

and piping 

elements

Steel (with 

coating or 

lining)

Raw water Loss of material 

due to general, 

pitting, crevice, and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

corrosion; 

lining/coating 

degradation

Chapter XI.M20, "Open-Cyc

Cooling Water System"

VII.C3.AP198VII.C3-9(A01)Piping, piping 

components, 

and piping 

elements

Steel (with 

coating or 

wrapping)

Soil Loss of material 

due to general, 

pitting, crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M41, "Buried and 

Underground Piping and Tan

VII.C3.AP209Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless steel Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

VII.C3.AP221Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless steel Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

December 2010 VII D-1 NUREG-1801, Rev. 2

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 receivers, 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 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 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 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 period of extended 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. 2 VII D-2 December 2010

VII AUXILIARY SYSTEMS 

D Compressed Air System

Item Link Structure and/

or Component Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.D.AP-121 VII.D-1(A103)Closure bolting Steel; 

stainless 

steel

Condensation Loss of material 

due to general 

(steel only), 

pitting, and 

crevice corrosion

Chapter XI.M18, "Bolting Integ

VII.D.A-80 VII.D-3(A80)Piping and 

components 

(External 

surfaces)

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External Surf

Monitoring of Mechanical Com

VII.D.AP-240 Piping, piping 

components, 

and piping 

elements

Copper 

alloy

Condensation Loss of material 

due to general, 

pitting, and 

crevice corrosion

Chapter XI.M24, “Compressed 

Monitoring"

VII.D.AP-81 VII.D4(AP-81)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Condensation 

(Internal)

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M24, “Compressed 

Monitoring”

VII.D.A-26 VII.D-2(A26)Piping, piping 

components, 

and piping 

elements: 

compressed air 

system

Steel Condensation 

(Internal)

Loss of material 

due to general 

and pitting 

corrosion

Chapter XI.M24, “Compressed 

Monitoring”

VII.D.AP-209 Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Cracking 

due to stress 

corrosion 

cracking

Chapter XI.M36, "External Surf

Monitoring of Mechanical Com

VII.D.AP-221 Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External Surf

Monitoring of Mechanical Com
December 2010 VII E1-1 NUREG-1801, Rev. 2

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 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 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 period of extended 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. 2 VII E1-2 December 2010

VII AUXILIARY SYSTEMS 

E1 Chemical and Volume Control System (PWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ 

Mechanism

Aging Managemen

Program (AMP)

VII.E1.A-79 VII.E1-

1(A-79)

External surfaces Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Bo

Acid Corrosion”

VII.E1.AP203VII.E1-

2(AP-34)

Heat exchanger 

components

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, 

"Closed Treated Wa

Systems"

VII.E1.AP65VII.E1-

3(AP-65)

Heat exchanger 

components

Copper alloy 

(>15% Zn or >8% 

Al)

Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

VII.E1.AP118VII.E1-

5(A-84)

Heat exchanger 

components

Stainless steel Treated borated 

water >60°C 

(>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Wa

Chemistry,” and 

Chapter XI.M32, “On

Time Inspection”

VII.E1.AP189VII.E1-

6(A-63)

Heat exchanger 

components

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, 

"Closed Treated Wa

Systems"

VII.E1.A100VII.E1-

4(A-100)

Heat exchanger 

components and 

tubes

Stainless steel Treated borated 

water

Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time-lim

aging analysis (TLAA

be evaluated for the 

period of extended 

operation. See the S

Section 4.3 “Metal 

Fatigue,” for accepta

methods for meeting 

requirements of 10 C

54.21(c)(1).

VII.E1.AP119VII.E1-

5(A-84)

Heat exchanger 

components and 

tubes

Stainless steel Treated borated 

water >60°C 

(>140°F)

Cracking 

due to cyclic loading

Chapter XI.M1, "ASM

Section XI Inservice 

Inspection, Subsecti

IWB, IWC, and IWD
December 2010 VII E1-3 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS 

E1 Chemical and Volume Control System (PWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ 

Mechanism

Aging Managemen

Program (AMP)

VII.E1.A-69 VII.E1-

9(A-69)

Heat exchanger 

components, 

non-regenerative

Stainless steel Treated borated 

water >60°C 

(>140°F)

Cracking 

due to stress 

corrosion cracking; 

cyclic loading

Chapter XI.M2, “Wa

Chemistry.” 

The AMP is to be 

augmented by verify

the absence of crack

due to stress corros

cracking and cyclic 

loading. An accepta

verification program 

include temperature 

radioactivity monitor

the shell side water, 

eddy current testing 

tubes.

VII.E1.AP115VII.E1-

7(A-76)

High-pressure 

pump, casing

Stainless steel Treated borated 

water

Cracking 

due to cyclic loading

Chapter XI.M1, "ASM

Section XI Inservice 

Inspection, Subsecti

IWB, IWC, and IWD

VII.E1.AP114VII.E1-

7(A-76)

High-pressure 

pump, casing

Stainless steel Treated borated 

water >60°C 

(>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Wa

Chemistry,” and 

Chapter XI.M32, “On

Time Inspection”

VII.E1.AP122VII.E1-

8(A-104)

High-pressure 

pump, closure 

bolting

Steel, highstrengthAir with steam or 

water leakage

Cracking 

due to stress 

corrosion cracking; 

cyclic loading

Chapter XI.M18, "Bo

Integrity"

VII.E1.AP1 VII.E1-

10(AP-1)

Piping, piping 

components, and 

piping elements

Aluminum Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Bo

Acid Corrosion”

VII.E1.AP199VII.E1-

11(AP-12)

Piping, piping 

components, and 

piping elements

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, 

"Closed Treated Wa

Systems"
NUREG-1801, Rev. 2 VII E1-4 December 2010

VII AUXILIARY SYSTEMS 

E1 Chemical and Volume Control System (PWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ 

Mechanism

Aging Managemen

Program (AMP)

VII.E1.AP133VII.E1-

12(AP-47)

Piping, piping 

components, and 

piping elements

Copper alloy Lubricating oil Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M39, 

"Lubricating Oil Ana

and 

Chapter XI.M32, “On

Time Inspection”

VII.E1.AP43VII.E1-

13(AP-43)

Piping, piping 

components, and 

piping elements

Copper alloy 

(>15% Zn or >8% 

Al)

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

VII.E1.AP31VII.E1-

14(AP-31)

Piping, piping 

components, and 

piping elements

Gray cast iron Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

VII.E1.AP138VII.E1-

15(AP-59)

Piping, piping 

components, and 

piping elements

Stainless steel Lubricating oil Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced corrosion

Chapter XI.M39, 

"Lubricating Oil Ana

and 

Chapter XI.M32, “On

Time Inspection”

VII.E1.A-57 VII.E1-

16(A-57)

Piping, piping 

components, and 

piping elements

Stainless steel Treated borated 

water

Cumulative fatigue

damage 

due to fatigue

Fatigue is a time-lim

aging analysis (TLAA

be evaluated for the 

period of extended 

operation. See the S

Section 4.3 “Metal 

Fatigue,” for accepta

methods for meeting 

requirements of 10 C

54.21(c)(1).
December 2010 VII E1-5 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS 

E1 Chemical and Volume Control System (PWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ 

Mechanism

Aging Managemen

Program (AMP)

VII.E1.A-34 VII.E1-

18(A-34)

Piping, piping 

components, and 

piping elements

Steel Air - indoor, 

uncontrolled

Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time-lim

aging analysis (TLAA

be evaluated for the 

period of extended 

operation. See the S

Section 4.3 “Metal 

Fatigue,” for accepta

methods for meeting 

requirements of 10 C

54.21(c)(1).

VII.E1.AP127VII.E1-

19(AP-30)

Piping, piping 

components, and 

piping elements

Steel Lubricating oil Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M39, 

"Lubricating Oil Ana

and 

Chapter XI.M32, “On

Time Inspection”

VII.E1.AP79VII.E1-

17(AP-79)

Piping, piping 

components, and 

piping elements

Steel (with 

stainless steel 

cladding); stainless 

steel

Treated borated 

water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Wa

Chemistry”

VII.E1.AP209Piping, piping 

components, and 

piping elements; 

tanks

Stainless steel Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "Ex

Surfaces Monitoring 

Mechanical Compon

VII.E1.AP221Piping, piping 

components, and 

piping elements; 

tanks

Stainless steel Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "Ex

Surfaces Monitoring 

Mechanical Compon

VII.E1.AP82VII.E1-

20(AP-82)

Piping, piping 

components, and 

piping elements; 

tanks

Stainless steel Treated borated 

water >60°C 

(>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Wa

Chemistry”
NUREG-1801, Rev. 2 VII E1-6 December 2010

VII AUXILIARY SYSTEMS 

E1 Chemical and Volume Control System (PWR)

Item Link Structure and/or 

Component Material Environment Aging Effect/ 

Mechanism

Aging Managemen

Program (AMP)

VII.E1.AP85VII.E1-

21(AP-85)

Pump Casings Steel (with 

stainless steel or 

nickel-alloy 

cladding)

Treated borated 

water

Loss of material

due to cladding

breach

A plant-specific agin

management progra

to be evaluated. 

Reference NRC 

Information Notice 9

“Boric Acid Corrosio

Charging Pump Cas

Caused by Cladding 

Cracks."
December 2010 VII E2-1 NUREG-1801, Rev. 2

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 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 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 period of extended 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. 2 VII E2-2 December 2010

VII AUXILIARY SYSTEMS 

E2 Standby Liquid Control System (BWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.E2.AP-141 VII.E2-

1(AP-73)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Sodium 

pentaborate 

solution

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time Ins

VII.E2.AP-181 VII.E2-2(A59)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Sodium 

pentaborate 

solution >60°C 

(>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time Ins
December 2010 VII E3-1 NUREG-1801, Rev. 2

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 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 period of extended 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. 2 VII E3-2 December 2010

VII AUXILIARY SYSTEMS 

E3 Reactor Water Cleanup System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.E3.AP191VII.E3-1(A67)Heat 

exchanger 

components

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Closed-cycle 

cooling water

Loss of material 

due to 

microbiologicallyinfluenced 

corrosion

Chapter XI.M21A, "Closed Tre

Water Systems"

VII.E3.AP192VII.E3-2(A68)Heat 

exchanger 

components

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Closed-cycle 

cooling water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M21A, "Closed Tre

Water Systems"

VII.E3.AP112VII.E3-3(A71)Heat 

exchanger 

components

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Treated water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”

VII.E3.AP189VII.E3-4(A63)Heat 

exchanger 

components

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed Tre

Water Systems"

VII.E3.AP188VII.E3-

5(AP-63)

Heat 

exchanger 

tubes

Stainless 

steel

Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Closed Tre

Water Systems"

VII.E3.AP139VII.E3-

6(AP-62)

Heat 

exchanger 

tubes

Stainless 

steel

Treated water Reduction of heat 

transfer 

due to fouling

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”

VII.E3.AP130VII.E3-

7(AP-38)

Piping, piping 

components, 

and piping 

elements

Aluminum Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”
December 2010 VII E3-3 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS 

E3 Reactor Water Cleanup System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.E3.AP199VII.E3-

8(AP-12)

Piping, piping 

components, 

and piping 

elements

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed Tre

Water Systems"

VII.E3.AP140VII.E3-

9(AP-64)

Piping, piping 

components, 

and piping 

elements

Copper alloy Treated water Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”

VII.E3.AP-43 VII.E3-

10(AP-43)

Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective Le

VII.E3.AP-32 VII.E3-

11(AP-32)

Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective Le

VII.E3.AP-31 VII.E3-

12(AP-31)

Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective Le

VII.E3.AP186VII.E3-

13(AP-60)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed-cycle 

cooling water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M21A, "Closed Tre

Water Systems"

VII.E3.A-62 VII.E3-

14(A-62)

Piping, piping

components, 

and piping 

elements

Stainless 

steel

Treated water Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluate

the period of extended operati

the SRP, Section 4.3 “Metal F

for acceptable methods for me

the requirements of 10 CFR 

54.21(c)(1).
NUREG-1801, Rev. 2 VII E3-4 December 2010

VII AUXILIARY SYSTEMS 

E3 Reactor Water Cleanup System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.E3.AP110VII.E3-

15(A-58)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”

VII.E3.AP283VII.E3-

16(A-60)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking, 

intergranular stress 

corrosion cracking

Chapter XI.M2, "Water Chemi

and 

Chapter XI.M25, “BWR React

Cleanup System”

VII.E3.A-34 VII.E3-

17(A-34)

Piping, piping 

components, 

and piping 

elements

Steel Air - indoor, 

uncontrolled

Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluate

the period of extended operati

the SRP, Section 4.3 “Metal F

for acceptable methods for me

the requirements of 10 CFR 

54.21(c)(1).

VII.E3.AP106VII.E3-

18(A-35)

Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”

VII.E3.AP120VII.E3-

19(A-85)

Regenerative 

heat 

exchanger 

components

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”
December 2010 VII E4-1 NUREG-1801, Rev. 2

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 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 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 period of extended 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. 2 VII E4-2 December 2010

VII AUXILIARY SYSTEMS 

E4 Shutdown Cooling System (Older BWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.E4.AP-191VII.E4-1(A67)Heat 

exchanger 

components

Stainless 

steel; steel 

with 

stainless 

steel 

cladding

Closed-cycle 

cooling water

Loss of material 

due to 

microbiologicallyinfluenced 

corrosion

Chapter XI.M21A, "Closed Tre

Water Systems"

VII.E4.AP-189VII.E4-2(A63)Heat 

exchanger 

components

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed Tre

Water Systems"

VII.E4.AP-188VII.E4-

3(AP-63)

Heat 

exchanger 

tubes

Stainless 

steel

Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Closed Tre

Water Systems"

VII.E4.AP-130VII.E4-

4(AP-38)

Piping, piping 

components, 

and piping 

elements

Aluminum Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”

VII.E4.AP-199VII.E4-

5(AP-12)

Piping, piping 

components, 

and piping 

elements

Copper alloy Closed-cycle 

cooling water

Loss of material

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed Tre

Water Systems"

VII.E4.AP-133VII.E4-

6(AP-47)

Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M39, "Lubricating O

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”

VII.E4.AP-140VII.E4-

7(AP-64)

Piping, piping 

components, 

and piping 

elements

Copper alloy Treated water Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”
December 2010 VII E4-3 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS 

E4 Shutdown Cooling System (Older BWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.E4.AP-43 VII.E4-

8(AP-43)

Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective Le

VII.E4.AP-32 VII.E4-

9(AP-32)

Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective Le

VII.E4.AP-31 VII.E4-

10(AP-31)

Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective Le

VII.E4.AP-186VII.E4-

11(AP-60)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed-cycle 

cooling water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M21A, "Closed Tre

Water Systems"

VII.E4.AP-138VII.E4-

12(AP-59)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Lubricating oil Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M39, "Lubricating O

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”

VII.E4.A-62 VII.E4-

13(A-62)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time-limited aging 

(TLAA) to be evaluated for the 

of extended operation. See the 

Section 4.3 “Metal Fatigue,” fo

acceptable methods for meetin

requirements of 10 CFR 54.21

VII.E4.AP-110VII.E4-

14(A-58)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”
NUREG-1801, Rev. 2 VII E4-4 December 2010

VII AUXILIARY SYSTEMS 

E4 Shutdown Cooling System (Older BWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.E4.A-61 VII.E4-

15(A-61)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M7, “BWR Stress 

Corrosion Cracking,” and 

Chapter XI.M2, “Water Chemi

VII.E4.AP-127VII.E4-

16(AP-30)

Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M39, "Lubricating O

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”

VII.E4.AP-106VII.E4-

17(A-35)

Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”

VII.E4.AP-209 Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "External Sur

Monitoring of Mechanical 

Components"

VII.E4.AP-221 Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External Sur

Monitoring of Mechanical 

Components"
December 2010 VII E5-1 NUREG-1801, Rev. 2

E5. WASTE WATER SYSTEMS

Systems, Structures, and Components

This section discusses liquid waste systems such as liquid radioactive waste systems, oily 

waste systems, floor drainage systems, chemical waste water systems, and secondary waste 

water systems. Plants may include portions of waste water systems within the scope of license 

renewal based on the criterion of 10CFR 54.4.(a)(2).

Based on Regulatory Guide 1.26, “Quality Group Classifications and Standards for Water-, 

Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants,” radioactivewaste-containing portions of waste water systems are classified as Group C Quality Standards, 

with the exception of those forming part of the containment pressure boundary, which is 

classified as Group B. Waste water systems that do not contain radioactive waste or form a part 

of the containment pressure boundary are classified as Group D. 

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 period of extended 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 waste water systems.
NUREG-1801, Rev. 2 VII E5-2 December 2010

VII AUXILIARY SYSTEMS 

E5 Wastewater Systems

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.E5.AP-276 Heat 

exchanger 

components

Nickel alloy Waste water Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M38, "Inspection o

Internal Surfaces in Miscellane

Piping and Ducting Componen

VII.E5.AP-275 Heat 

exchanger 

components

Stainless 

steel

Waste water Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M38, "Inspection o

Internal Surfaces in Miscellane

Piping and Ducting Componen

VII.E5.AP-271 Piping, piping 

components, 

and piping 

elements

Copper alloy Raw water 

(potable)

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M38, "Inspection o

Internal Surfaces in Miscellane

Piping and Ducting Componen

VII.E5.AP-272 Piping, piping 

components, 

and piping 

elements

Copper alloy Waste water Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M38, "Inspection o

Internal Surfaces in Miscellane

Piping and Ducting Componen

VII.E5.AP-274 Piping, piping 

components, 

and piping 

elements

Nickel alloy Condensation 

(Internal)

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M38, "Inspection o

Internal Surfaces in Miscellane

Piping and Ducting Componen
December 2010 VII E5-3 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS 

E5 Wastewater Systems

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.E5.AP-273 Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Condensation 

(Internal)

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M38, "Inspection o

Internal Surfaces in Miscellane

Piping and Ducting Componen

VII.E5.AP-270 Piping, piping 

components, 

and piping 

elements

Steel; 

stainless 

steel

Raw water 

(potable)

Loss of material 

due to general 

(steel only), pitting, 

and crevice 

corrosion

Chapter XI.M38, "Inspection o

Internal Surfaces in Miscellane

Piping and Ducting Componen

VII.E5.AP-279 Piping, piping 

components, 

and piping 

elements; 

tanks

Nickel alloy Waste water Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M38, "Inspection o

Internal Surfaces in Miscellane

Piping and Ducting Componen

VII.E5.AP-278 Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Waste water Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M38, "Inspection o

Internal Surfaces in Miscellane

Piping and Ducting Componen

VII.E5.AP-280 Piping, piping 

components, 

and piping 

elements; 

tanks

Steel Condensation 

(Internal)

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M38, "Inspection o

Internal Surfaces in Miscellane

Piping and Ducting Componen
NUREG-1801, Rev. 2 VII E5-4 December 2010

VII AUXILIARY SYSTEMS 

E5 Wastewater Systems

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.E5.AP-281 Piping, piping 

components, 

and piping 

elements; 

tanks

Steel Waste water Loss of material 

due to general, 

pitting, crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M38, "Inspection o

Internal Surfaces in Miscellane

Piping and Ducting Componen
December 2010 VII F1-1 NUREG-1801, Rev. 2

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 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 period of extended 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. 2 VII F1-2 December 2010

VII AUXILIARY SYSTEMS 

F1 Control Room Area Ventilation System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism 

Aging Management Progra

(AMP)

VII.F1.AP-99 VII.F1-1(A09)Ducting and 

components

Stainless 

steel

Condensation Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M38, "Inspection 

Internal Surfaces in Miscella

Piping and Ducting Compone

VII.F1.A-10 VII.F1-2(A10)Ducting and 

components 

(External 

surfaces)

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

VII.F1.A-08 VII.F1-3(A08)Ducting and 

components 

(Internal 

surfaces)

Steel Condensation 

(Internal)

Loss of material 

due to general, 

pitting, crevice, and 

(for drip pans and 

drain lines) 

microbiologicallyinfluenced 

corrosion 

Chapter XI.M38, "Inspection 

Internal Surfaces in Miscella

Piping and Ducting Compone

VII.F1.A-105 VII.F1-4(A105)Ducting; 

closure bolting

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

VII.F1.AP113VII.F1-5(A73)Elastomer: 

seals and 

components

Elastomers Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to wear

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

VII.F1.AP103VII.F1-6(A18)Elastomer: 

seals and 

components

Elastomers Air – indoor, 

uncontrolled 

(Internal)

Loss of material 

due to wear

Chapter XI.M38, "Inspection 

Internal Surfaces in Miscella

Piping and Ducting Compone

VII.F1.AP102VII.F1-7(A17)Elastomer: 

seals and 

components

Elastomers Air – indoor, 

uncontrolled 

(Internal/External)

Hardening and loss 

of strength 

due to elastomer 

degradation

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"
December 2010 VII F1-3 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS 

F1 Control Room Area Ventilation System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism 

Aging Management Progra

(AMP)

VII.F1.AP203VII.F1-

8(AP-34)

Heat 

exchanger 

components

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed T

Water Systems"

VII.F1.AP-65 VII.F1-

9(AP-65)

Heat 

exchanger 

components

Copper alloy 

(>15% Zn or 

>8% Al)

Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VII.F1.AP-41 VII.F1-

10(AP-41)

Heat 

exchanger 

components

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

VII.F1.AP189VII.F1-

11(A-63)

Heat 

exchanger 

components

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed T

Water Systems"

VII.F1.AP205VII.F1-

12(AP-80)

Heat 

exchanger 

tubes

Copper alloy Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Closed T

Water Systems"

VII.F1.AP204VII.F1-

13(AP-77)

Heat 

exchanger 

tubes

Steel Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Closed T

Water Systems"

VII.F1.AP142VII.F1-

14(AP-74)

Piping, piping 

components,

and piping 

elements

Aluminum Condensation 

(Internal)

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M38, "Inspection 

Internal Surfaces in Miscella

Piping and Ducting Compone

VII.F1.AP199VII.F1-

15(AP-12)

Piping, piping 

components, 

and piping 

elements

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed T

Water Systems"
NUREG-1801, Rev. 2 VII F1-4 December 2010

VII AUXILIARY SYSTEMS 

F1 Control Room Area Ventilation System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism 

Aging Management Progra

(AMP)

VII.F1.AP109VII.F1-

16(A-46)

Piping, piping 

components, 

and piping 

elements

Copper alloy Condensation 

(External)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

VII.F1.AP-43 VII.F1-

17(AP-43)

Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VII.F1.AP-31 VII.F1-

18(AP-31)

Piping, piping 

components, 

and piping 

elements

Gray cast iron Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VII.F1.AP127VII.F1-

19(AP-30)

Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M39, "Lubricating 

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”

VII.F1.AP209Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

VII.F1.AP221Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

VII.F1.AP202VII.F1-

20(A-25)

Piping, piping 

components, 

and piping 

elements; 

tanks

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M21A, "Closed T

Water Systems"
December 2010 VII F2-1 NUREG-1801, Rev. 2

F2. Auxiliary and Radwaste Area Ventilation System

Systems, Structures, and Components

This section discusses the auxiliary and radwaste area 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 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 period of extended 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. 2 VII F2-2 December 2010

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)

VII.F2.AP99VII.F2-

1(A-09)

Ducting and 

components

Stainless steel Condensation Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M38, "Ins

of Internal Surfaces i

Miscellaneous Piping 

Ducting Components

VII.F2.A-10 VII.F2-

2(A-10)

Ducting and 

components 

(External 

surfaces)

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "Ext

Surfaces Monitoring o

Mechanical Compone

VII.F2.A-08 VII.F2-

3(A-08)

Ducting and 

components 

(Internal 

surfaces)

Steel Condensation 

(Internal)

Loss of material 

due to general, 

pitting, crevice, and 

(for drip pans and 

drain lines) 

microbiologicallyinfluenced 

corrosion 

Chapter XI.M38, "Ins

of Internal Surfaces i

Miscellaneous Piping 

Ducting Components

VII.F2.A105VII.F2-

4(A-105)

Ducting; closure 

bolting

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "Ext

Surfaces Monitoring o

Mechanical Compone

VII.F2.AP113VII.F2-

5(A-73)

Elastomer: seals 

and components

Elastomers Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to wear

Chapter XI.M36, "Ext

Surfaces Monitoring o

Mechanical Compone

VII.F2.AP103VII.F2-

6(A-18)

Elastomer: seals 

and components

Elastomers Air – indoor, 

uncontrolled 

(Internal)

Loss of material 

due to wear

Chapter XI.M38, "Ins

of Internal Surfaces i

Miscellaneous Piping 

Ducting Components

VII.F2.AP102VII.F2-

7(A-17)

Elastomer: seals 

and components

Elastomers Air – indoor, 

uncontrolled 

(Internal/External)

Hardening and loss 

of strength 

due to elastomer 

degradation

Chapter XI.M36, "Ext

Surfaces Monitoring o

Mechanical Compone
December 2010 VII F2-3 NUREG-1801, Rev. 2

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)

VII.F2.AP41VII.F2-

8(AP-41)

Heat exchanger 

components

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M36, "Ext

Surfaces Monitoring o

Mechanical Compone

VII.F2.AP189VII.F2-

9(A-63)

Heat exchanger 

components

Steel Closed-cycle cooling 

water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "C

Treated Water Syste

VII.F2.AP205VII.F2-

10(AP80)

Heat exchanger 

tubes

Copper Alloy Closed-cycle cooling 

water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "C

Treated Water Syste

VII.F2.AP204VII.F2-

11(AP77)

Heat exchanger 

tubes

Steel Closed-cycle cooling 

water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "C

Treated Water Syste

VII.F2.AP142VII.F2-

12(AP74)

Piping, piping 

components, and 

piping elements

Aluminum Condensation 

(Internal)

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M38, "Ins

of Internal Surfaces i

Miscellaneous Piping 

Ducting Components

VII.F2.AP199VII.F2-

13(AP12)

Piping, piping 

components, and 

piping elements

Copper alloy Closed-cycle cooling 

water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "C

Treated Water Syste

VII.F2.AP109VII.F2-

14(A-46)

Piping, piping 

components, and 

piping elements

Copper alloy Condensation 

(External)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M36, "Ext

Surfaces Monitoring o

Mechanical Compone

VII.F2.AP43VII.F2-

15(AP43)

Piping, piping 

components, and 

piping elements

Copper alloy 

(>15% Zn or 

>8% Al)

Closed-cycle cooling 

water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Sel

Leaching”
NUREG-1801, Rev. 2 VII F2-4 December 2010

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)

VII.F2.AP31VII.F2-

16(AP31)

Piping, piping 

components, and 

piping elements

Gray cast iron Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Sel

Leaching”

VII.F2.AP127VII.F2-

17(AP30)

Piping, piping 

components, and 

piping elements

Steel Lubricating oil Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M39, 

"Lubricating Oil Analy

and 

Chapter XI.M32, “On

Inspection”

VII.F2.AP209Piping, piping 

components, and 

piping elements; 

tanks

Stainless steel Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "Ext

Surfaces Monitoring o

Mechanical Compone

VII.F2.AP221Piping, piping 

components, and 

piping elements; 

tanks

Stainless steel Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "Ext

Surfaces Monitoring o

Mechanical Compone

VII.F2.AP202VII.F2-

18(A-25)

Piping, piping 

components, and 

piping elements; 

tanks

Steel Closed-cycle cooling 

water

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M21A, "C

Treated Water Syste
December 2010 VII F3-1 NUREG-1801, Rev. 2

F3. PRIMARY CONTAINMENT HEATING AND VENTILATION 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 period of extended 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. 2 VII F3-2 December 2010

VII AUXILIARY SYSTEMS 

F3 Primary Containment Heating and Ventilation System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Progra

VII.F3.AP-99 VII.F3-1(A09)Ducting and 

components

Stainless 

steel

Condensation Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M38, "Inspection 

Internal Surfaces in Miscellan

Piping and Ducting Compone

VII.F3.A-10 VII.F3-2(A10)Ducting and 

components 

(External 

surfaces)

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External Su

Monitoring of Mechanical 

Components"

VII.F3.A-08 VII.F3-3(A08)Ducting and 

components 

(Internal 

surfaces)

Steel Condensation 

(Internal)

Loss of material 

due to general, 

pitting, crevice, and 

(for drip pans and 

drain lines) 

microbiologicallyinfluenced 

corrosion 

Chapter XI.M38, "Inspection 

Internal Surfaces in Miscellan

Piping and Ducting Compone

VII.F3.A-105 VII.F3-4(A105)Ducting; 

closure bolting

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External Su

Monitoring of Mechanical 

Components"

VII.F3.AP113VII.F3-5(A73)Elastomer: 

seals and 

components

Elastomers Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to wear

Chapter XI.M36, "External Su

Monitoring of Mechanical 

Components"

VII.F3.AP103VII.F3-6(A18)Elastomer: 

seals and 

components

Elastomers Air – indoor, 

uncontrolled 

(Internal)

Loss of material 

due to wear

Chapter XI.M38, "Inspection 

Internal Surfaces in Miscellan

Piping and Ducting Compone

VII.F3.AP102VII.F3-7(A17)Elastomer: 

seals and 

components

Elastomers Air – indoor, 

uncontrolled 

(Internal/External)

Hardening and loss 

of strength 

due to elastomer 

degradation

Chapter XI.M36, "External Su

Monitoring of Mechanical 

Components"
December 2010 VII F3-3 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS 

F3 Primary Containment Heating and Ventilation System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Progra

VII.F3.AP203VII.F3-

8(AP-34)

Heat 

exchanger 

components

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed Tr

Water Systems"

VII.F3.AP-65 VII.F3-

9(AP-65)

Heat 

exchanger 

components

Copper alloy 

(>15% Zn or 

>8% Al)

Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective L

VII.F3.AP-41 VII.F3-

10(AP-41)

Heat 

exchanger 

components

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M36, "External Su

Monitoring of Mechanical 

Components"

VII.F3.AP189VII.F3-

11(A-63)

Heat 

exchanger 

components

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed Tr

Water Systems"

VII.F3.AP205VII.F3-

12(AP-80)

Heat 

exchanger 

tubes

Copper Alloy Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Closed Tr

Water Systems"

VII.F3.AP204VII.F3-

13(AP-77)

Heat 

exchanger 

tubes

Steel Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Closed Tr

Water Systems"

VII.F3.AP142VII.F3-

14(AP-74)

Piping, piping 

components, 

and piping 

elements

Aluminum Condensation 

(Internal)

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M38, "Inspection 

Internal Surfaces in Miscellan

Piping and Ducting Compone

VII.F3.AP199VII.F3-

15(AP-12)

Piping, piping 

components, 

and piping 

elements

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed Tr

Water Systems"
NUREG-1801, Rev. 2 VII F3-4 December 2010

VII AUXILIARY SYSTEMS 

F3 Primary Containment Heating and Ventilation System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Progra

VII.F3.AP109VII.F3-

16(A-46)

Piping, piping 

components, 

and piping 

elements

Copper alloy Condensation 

(External)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M36, "External Su

Monitoring of Mechanical 

Components"

VII.F3.AP-43 VII.F3-

17(AP-43)

Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective L

VII.F3.A-50 VII.F3-

18(A-50)

Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective L

VII.F3.AP127VII.F3-

19(AP-30)

Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M39, "Lubricating 

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”

VII.F3.AP202VII.F3-

20(A-25)

Piping, piping 

components, 

and piping 

elements; 

tanks

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M21A, "Closed Tr

Water Systems"
December 2010 VII F4-1 NUREG-1801, Rev. 2

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 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 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 period of extended 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. 2 VII F4-2 December 2010

VII AUXILIARY SYSTEMS 

F4 Diesel Generator Building Ventilation System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progra

(AMP)

VII.F4.A-10 VII.F4-1(A10)Ducting and 

components 

(External 

surfaces)

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

VII.F4.A-08 VII.F4-2(A08)Ducting and 

components 

(Internal 

surfaces)

Steel Condensation 

(Internal)

Loss of material 

due to general, 

pitting, crevice, and 

(for drip pans and 

drain lines) 

microbiologicallyinfluenced 

corrosion 

Chapter XI.M38, "Inspection 

Internal Surfaces in Miscella

Piping and Ducting Compone

VII.F4.A-105 VII.F4-3(A105)Ducting; 

closure bolting

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

VII.F4.AP113VII.F4-4(A73)Elastomer: 

seals and 

components

Elastomers Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to wear

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

VII.F4.AP103VII.F4-5(A18)Elastomer: 

seals and 

components

Elastomers Air – indoor, 

uncontrolled 

(Internal)

Loss of material 

due to wear

Chapter XI.M38, "Inspection 

Internal Surfaces in Miscella

Piping and Ducting Compone

VII.F4.AP102VII.F4-6(A17)Elastomer: 

seals and 

components

Elastomers Air – indoor, 

uncontrolled 

(Internal/External)

Hardening and loss 

of strength 

due to elastomer 

degradation

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

VII.F4.AP-41 VII.F4-

7(AP-41)

Heat 

exchanger 

components

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"
December 2010 VII F4-3 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS 

F4 Diesel Generator Building Ventilation System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progra

(AMP)

VII.F4.AP189VII.F4-8(A63)Heat 

exchanger 

components

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed T

Water Systems"

VII.F4.AP204VII.F4-

9(AP-77)

Heat 

exchanger 

tubes

Steel Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Closed T

Water Systems"

VII.F4.AP142VII.F4-

10(AP-74)

Piping, piping 

components, 

and piping 

elements

Aluminum Condensation 

(Internal)

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M38, "Inspection 

Internal Surfaces in Miscella

Piping and Ducting Compone

VII.F4.AP199VII.F4-

11(AP-12)

Piping, piping 

components, 

and piping 

elements

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed T

Water Systems"

VII.F4.AP109VII.F4-

12(A-46)

Piping, piping 

components, 

and piping 

elements

Copper alloy Condensation 

(External)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

VII.F4.AP-43 VII.F4-

13(AP-43)

Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VII.F4.AP-31 VII.F4-

14(AP-31)

Piping, piping 

components, 

and piping 

elements

Gray cast iron Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VII.F4.AP127VII.F4-

15(AP-30)

Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M39, "Lubricating 

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”
NUREG-1801, Rev. 2 VII F4-4 December 2010

VII AUXILIARY SYSTEMS 

F4 Diesel Generator Building Ventilation System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progra

(AMP)

VII.F4.AP209Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

VII.F4.AP221Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External S

Monitoring of Mechanical 

Components"

VII.F4.AP202VII.F4-

16(A-25)

Piping, piping 

components, 

and piping 

elements; 

tanks

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M21A, "Closed T

Water Systems"
December 2010 VII G-1 NUREG-1801, Rev. 2

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 the 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 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 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 period of extended 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. 2 VII G-2 December 2010

VII AUXILIARY SYSTEMS 

G Fire Protection

Item Link Structure and/or 

Component Material Environment Aging Effect/ 

Mechanism

Aging Management P

(AMP)

VII.G.A-19 VII.G1(A-19)Fire barrier 

penetration seals

Elastomers Air - indoor, 

uncontrolled

Increased 

hardness; 

shrinkage; loss of 

strength 

due to weathering

Chapter XI.M26, "Fire 

Protection"

VII.G.A-20 VII.G2(A-20)Fire barrier 

penetration seals

Elastomers Air – outdoor Increased 

hardness; 

shrinkage; loss of 

strength 

due to weathering

Chapter XI.M26, "Fire 

Protection"

VII.G.AP149Fire Hydrants Steel Air – outdoor Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M27, "Fire 

System"

VII.G.A-21 VII.G3(A-21)Fire rated doors Steel Air - indoor, 

uncontrolled

Loss of material 

due to wear

Chapter XI.M26, "Fire 

Protection"

VII.G.A-22 VII.G4(A-22)Fire rated doors Steel Air – outdoor Loss of material 

due to wear

Chapter XI.M26, "Fire 

Protection"

VII.G.AP150Halon/carbon 

dioxide fire 

suppression 

system piping, 

piping 

components, and 

piping elements

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M26, "Fire 

Protection"

VII.G.AP41VII.G5(AP-41)Heat exchanger 

components

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M36, "Exte

Surfaces Monitoring of 

Mechanical Componen
December 2010 VII G-3 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS 

G Fire Protection

Item Link Structure and/or 

Component Material Environment Aging Effect/ 

Mechanism

Aging Management P

(AMP)

VII.G.AP40VII.G6(AP-40)Heat exchanger 

components

Steel Air – outdoor 

(External)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M36, "Exte

Surfaces Monitoring of 

Mechanical Componen

VII.G.AP187VII.G7(AP-61)Heat exchanger 

tubes

Stainless steel Raw water Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "Ope

Cooling Water System

VII.G.AP180VII.G8(AP-83)Piping, piping 

components, and 

piping elements

Aluminum Raw water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M27, "Fire 

System"

VII.G.AP143VII.G9(AP-78)Piping, piping 

components, and 

piping elements

Copper alloy Condensation 

(Internal)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M38, "Insp

Internal Surfaces in 

Miscellaneous Piping a

Ducting Components"

VII.G.AP132VII.G10(AP44)Piping, piping 

components, and 

piping elements

Copper alloy Fuel oil Loss of material 

due to general, 

pitting, crevice, and 

microbiologicallyinfluenced corrosion

Chapter XI.M30, “Fuel 

Chemistry,” and 

Chapter XI.M32, “One

Inspection”

VII.G.AP133VII.G11(AP47)Piping, piping 

components, and 

piping elements

Copper alloy Lubricating oil Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M39, "Lubr

Oil Analysis," and 

Chapter XI.M32, “One

Inspection”

VII.G.AP197VII.G12(A-45)Piping, piping 

components, and 

piping elements

Copper alloy Raw water Loss of material 

due to general, 

pitting, crevice, and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

corrosion

Chapter XI.M27, "Fire 

System"
NUREG-1801, Rev. 2 VII G-4 December 2010

VII AUXILIARY SYSTEMS 

G Fire Protection

Item Link Structure and/or 

Component Material Environment Aging Effect/ 

Mechanism

Aging Management P

(AMP)

VII.G.A-47 VII.G13(A-47)Piping, piping 

components, and 

piping elements

Copper alloy 

(>15% Zn or >8% 

Al)

Raw water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Sele

Leaching”

VII.G.A-51 VII.G14(A-51)Piping, piping 

components, and 

piping elements

Gray cast iron Raw water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Sele

Leaching”

VII.G.A-02 VII.G15(A-02)Piping, piping 

components, and 

piping elements

Gray cast iron Soil Loss of material 

due to selective 

leaching

Chapter XI.M33, “Sele

Leaching”

VII.G.AP31VII.G16(AP31)Piping, piping 

components, and 

piping elements

Gray cast iron Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Sele

Leaching”

VII.G.AP136VII.G17(AP54)Piping, piping 

components, and 

piping elements

Stainless steel Fuel oil Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced corrosion

Chapter XI.M30, “Fuel 

Chemistry,” and 

Chapter XI.M32, “One

Inspection”

VII.G.AP138VII.G18(AP59)Piping, piping 

components, and 

piping elements

Stainless steel Lubricating oil Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced corrosion

Chapter XI.M39, "Lubr

Oil Analysis," and 

Chapter XI.M32, “One

Inspection”

VII.G.A-55 VII.G19(A-55)Piping, piping 

components, and 

piping elements

Stainless steel Raw water Loss of material 

due to pitting and 

crevice corrosion; 

fouling that leads to 

corrosion

Chapter XI.M27, "Fire 

System"

VII.G.AP137VII.G20(AP56)Piping, piping 

components, and 

piping elements

Stainless steel Soil Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M41, "Burie

Underground Piping an

Tanks"
December 2010 VII G-5 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS 

G Fire Protection

Item Link Structure and/or 

Component Material Environment Aging Effect/ 

Mechanism

Aging Management P

(AMP)

VII.G.AP234VII.G21(A-28)Piping, piping 

components, and 

piping elements

Steel Fuel oil Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M30, "Fuel 

Chemistry", and 

Chapter XI.M32, "One

Inspection" 

VII.G.AP127VII.G22(AP30)Piping, piping 

components, and 

piping elements

Steel Lubricating oil Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M39, "Lubr

Oil Analysis," and 

Chapter XI.M32, “One

Inspection”

VII.G.A-23 VII.G23(A-23)Piping, piping 

components, and 

piping elements

Steel Moist air or 

condensation 

(Internal)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M38, "Insp

Internal Surfaces in 

Miscellaneous Piping a

Ducting Components"

VII.G.A-33 VII.G24(A-33)Piping, piping 

components, and 

piping elements

Steel Raw water Loss of material 

due to general, 

pitting, crevice, and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

corrosion

Chapter XI.M27, "Fire 

System"

VII.G.AP198VII.G25(A-01)Piping, piping 

components, and 

piping elements

Steel (with 

coating or 

wrapping)

Soil Loss of material 

due to general, 

pitting, crevice, and 

microbiologicallyinfluenced corrosion

Chapter XI.M41, "Burie

Underground Piping an

Tanks"

VII.G.AP209Piping, piping 

components, and 

piping elements; 

tanks

Stainless steel Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "Exte

Surfaces Monitoring of 

Mechanical Componen
NUREG-1801, Rev. 2 VII G-6 December 2010

VII AUXILIARY SYSTEMS 

G Fire Protection

Item Link Structure and/or 

Component Material Environment Aging Effect/ 

Mechanism

Aging Management P

(AMP)

VII.G.AP221Piping, piping 

components, and 

piping elements; 

tanks

Stainless steel Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "Exte

Surfaces Monitoring of 

Mechanical Componen

VII.G.AP117VII.G26(A-83)Reactor coolant 

pump oil 

collection system: 

piping, tubing, 

valve bodies

Steel Lubricating oil Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M39, "Lubr

Oil Analysis," and 

Chapter XI.M32, “One

Inspection”

VII.G.AP116VII.G27(A-82)Reactor coolant 

pump oil 

collection system: 

tanks

Steel Lubricating oil Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M39, "Lubr

Oil Analysis," and 

Chapter XI.M32, “One

Inspection”

VII.G.A-90 VII.G28(A-90)Structural fire 

barriers: walls, 

ceilings and 

floors

Reinforced 

concrete

Air - indoor, 

uncontrolled

Concrete cracking 

and spalling 

due to aggressive 

chemical attack, 

and reaction with 

aggregates

Chapter XI.M26, “Fire 

Protection,” and 

Chapter XI.S6, “Struct

Monitoring”

VII.G.A-91 VII.G29(A-91)Structural fire 

barriers: walls, 

ceilings and 

floors

Reinforced 

concrete

Air - indoor, 

uncontrolled

Loss of material 

due to corrosion of 

embedded steel

Chapter XI.M26, “Fire 

Protection,” and 

Chapter XI.S6, “Struct

Monitoring”

VII.G.A-92 VII.G30(A-92)Structural fire 

barriers: walls, 

ceilings and 

floors

Reinforced 

concrete

Air – outdoor Cracking, loss of 

material 

due to freeze-thaw, 

aggressive 

chemical attack, 

and reaction with 

aggregates

Chapter XI.M26, “Fire 

Protection,” and 

Chapter XI.S6, “Struct

Monitoring”
December 2010 VII G-7 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS 

G Fire Protection

Item Link Structure and/or 

Component Material Environment Aging Effect/ 

Mechanism

Aging Management P

(AMP)

VII.G.A-93 VII.G31(A-93)Structural fire 

barriers: walls, 

ceilings and 

floors

Reinforced 

concrete

Air – outdoor Loss of material 

due to corrosion of 

embedded steel

Chapter XI.M26, “Fire 

Protection,” and 

Chapter XI.S6, “Struct

Monitoring”

December 2010 VII H1-1 NUREG-1801, Rev. 2

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 period of extended 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. 2 VII H1-2 December 2010

VII AUXILIARY SYSTEMS 

H1 Diesel Fuel Oil System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.H1.AP129VII.H1-

1(AP-35)

Piping, piping 

components, 

and piping 

elements

Aluminum Fuel oil Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M30, “Fuel Oil Che

and 

Chapter XI.M32, “One-Time 

Inspection”

VII.H1.AP199VII.H1-

2(AP-12)

Piping, piping 

components, 

and piping 

elements

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed Tre

Water Systems"

VII.H1.AP132VII.H1-

3(AP-44)

Piping, piping 

components, 

and piping 

elements

Copper alloy Fuel oil Loss of material 

due to general, 

pitting, crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M30, “Fuel Oil Che

and 

Chapter XI.M32, “One-Time 

Inspection”

VII.H1.AP-43 VII.H1-

4(AP-43)

Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective Le

VII.H1.A-02 VII.H1-5(A02)Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Soil Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective Le

VII.H1.AP136VII.H1-

6(AP-54)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Fuel oil Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M30, “Fuel Oil Che

and 

Chapter XI.M32, “One-Time 

Inspection”
December 2010 VII H1-3 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS 

H1 Diesel Fuel Oil System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.H1.AP137VII.H1-

7(AP-56)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Soil Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M41, "Buried and 

Underground Piping and Tank

VII.H1.A-24 VII.H1-8(A24)Piping, piping 

components, 

and piping 

elements

Steel Air – outdoor 

(External)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M36, "External Sur

Monitoring of Mechanical 

Components"

VII.H1.AP198VII.H1-9(A01)Piping, piping 

components, 

and piping 

elements

Steel (with 

coating or 

wrapping)

Soil Loss of material 

due to general, 

pitting, crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M41, "Buried and 

Underground Piping and Tank

VII.H1.AP209Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "External Sur

Monitoring of Mechanical 

Components"

VII.H1.AP221Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External Sur

Monitoring of Mechanical 

Components"

VII.H1.AP105VII.H1-

10(A-30)

Piping, piping 

components, 

and piping 

elements; 

tanks

Steel Fuel oil Loss of material 

due to general, 

pitting, crevice, and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

corrosion

Chapter XI.M30, “Fuel Oil Che

and 

Chapter XI.M32, “One-Time 

Inspection”
NUREG-1801, Rev. 2 VII H1-4 December 2010

VII AUXILIARY SYSTEMS 

H1 Diesel Fuel Oil System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VII.H1.A-95 VII.H1-

11(A-95)

Tanks Steel Air – outdoor 

(External)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M29, “Abovegroun

Metallic Tanks”
December 2010 VII H2-1 NUREG-1801, Rev. 2

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 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 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.

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 period of extended 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. 2 VII H2-2 December 2010

VII AUXILIARY SYSTEMS

H2 Emergency Diesel Generator System

Item Link Structure and/or 

Component Material Environment Aging Effect/ 

Mechanism

Aging Management Prog

(AMP)

VII.H2.AP128VII.H2-

1(AP-33)

Diesel engine 

exhaust piping, 

piping 

components, and 

piping elements

Stainless steel Diesel exhaust Cracking 

due to stress 

corrosion cracking

Chapter XI.M38, "Inspectio

Internal Surfaces in Miscell

Piping and Ducting Compo

VII.H2.AP-41 VII.H2-

3(AP-41)

Heat exchanger 

components

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M36, "External 

Monitoring of Mechanical 

Components"

VII.H2.AP-40 VII.H2-

4(AP-40)

Heat exchanger 

components

Steel Air – outdoor 

(External)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M36, "External 

Monitoring of Mechanical 

Components"

VII.H2.AP131VII.H2-

5(AP-39)

Heat exchanger 

components

Steel Lubricating oil Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

corrosion

Chapter XI.M39, "Lubricatin

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”

VII.H2.AP154Heat exchanger 

tubes

Aluminum Lubricating oil Reduction of heat 

transfer 

due to fouling

Chapter XI.M39, "Lubricatin

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”

VII.H2.AP187VII.H2-

6(AP-61)

Heat exchanger 

tubes

Stainless steel Raw water Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "Open-Cy

Cooling Water System"

VII.H2.AP255Piping, piping 

components, and 

piping elements

Aluminum Closed-cycle 

cooling water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M21A, "Closed 

Water Systems"
December 2010 VII H2-3 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS

H2 Emergency Diesel Generator System

Item Link Structure and/or 

Component Material Environment Aging Effect/ 

Mechanism

Aging Management Prog

(AMP)

VII.H2.AP129VII.H2-

7(AP-35)

Piping, piping 

components, and 

piping elements

Aluminum Fuel oil Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M30, “Fuel Oil 

Chemistry,” and 

Chapter XI.M32, “One-Time 

Inspection”

VII.H2.AP162Piping, piping 

components, and 

piping elements

Aluminum Lubricating oil Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M39, "Lubricatin

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”

VII.H2.AP258Piping, piping 

components, and 

piping elements

Aluminum Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Che

and 

Chapter XI.M32, “One-Time 

Inspection”

VII.H2.AP199VII.H2-

8(AP-12)

Piping, piping 

components, and 

piping elements

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, "Closed 

Water Systems"

VII.H2.AP132VII.H2-

9(AP-44)

Piping, piping 

components, and 

piping elements

Copper alloy Fuel oil Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M30, “Fuel Oil 

Chemistry,” and 

Chapter XI.M32, “One-Time 

Inspection”

VII.H2.AP133VII.H2-

10(AP-47)

Piping, piping 

components, and 

piping elements

Copper alloy Lubricating oil Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M39, "Lubricatin

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”
NUREG-1801, Rev. 2 VII H2-4 December 2010

VII AUXILIARY SYSTEMS

H2 Emergency Diesel Generator System

Item Link Structure and/or 

Component Material Environment Aging Effect/ 

Mechanism

Aging Management Prog

(AMP)

VII.H2.AP193VII.H2-

11(AP-45)

Piping, piping

components, and 

piping elements

Copper alloy Raw water Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M20, "Open-Cy

Cooling Water System"

VII.H2.AP-43 VII.H2-

12(AP-43)

Piping, piping 

components, and 

piping elements

Copper alloy 

(>15% Zn or 

>8% Al)

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VII.H2.A-47 VII.H2-

13(A-47)

Piping, piping 

components, and 

piping elements

Copper alloy 

(>15% Zn or 

>8% Al)

Raw water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VII.H2.A-51 VII.H2-

14(A-51)

Piping, piping 

components, and 

piping elements

Gray cast iron Raw water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VII.H2.A-02 VII.H2-

15(A-02)

Piping, piping 

components, and 

piping elements

Gray cast iron Soil Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VII.H2.AP136VII.H2-

16(AP-54) 

Piping, piping 

components, and 

piping elements

Stainless steel Fuel oil Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M30, “Fuel Oil 

Chemistry,” and 

Chapter XI.M32, “One-Time 

Inspection”

VII.H2.AP138VII.H2-

17(AP-59)

Piping, piping 

components, and 

piping elements

Stainless steel Lubricating oil Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M39, "Lubricatin

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”
December 2010 VII H2-5 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS

H2 Emergency Diesel Generator System

Item Link Structure and/or 

Component Material Environment Aging Effect/ 

Mechanism

Aging Management Prog

(AMP)

VII.H2.AP-55 VII.H2-

18(AP-55)

Piping, piping 

components, and 

piping elements

Stainless steel Raw water Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M20, "Open-Cy

Cooling Water System"

VII.H2.AP137VII.H2-

19(AP-56)

Piping, piping 

components, and 

piping elements

Stainless steel Soil Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M41, "Buried an

Underground Piping and Ta

VII.H2.AP127VII.H2-

20(AP-30)

Piping, piping 

components, and 

piping elements

Steel Lubricating oil Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M39, "Lubricatin

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection”

VII.H2.A-23 VII.H2-

21(A-23)

Piping, piping 

components, and 

piping elements

Steel Moist air or 

condensation 

(Internal)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M38, "Inspectio

Internal Surfaces in Miscell

Piping and Ducting Compo

VII.H2.AP194VII.H2-

22(A-38)

Piping, piping 

components, and 

piping elements

Steel (with 

coating or 

lining)

Raw water Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

corrosion; 

lining/coating

degradation

Chapter XI.M20, "Open-Cy

Cooling Water System"

VII.H2.AP104VII.H2-

2(A-27)

Piping, piping 

components, and 

piping elements, 

diesel engine 

exhaust

Steel; 

stainless steel

Diesel exhaust Loss of material 

due to general 

(steel only), pitting, 

and crevice 

corrosion

Chapter XI.M38, "Inspectio

Internal Surfaces in Miscell

Piping and Ducting Compo
NUREG-1801, Rev. 2 VII H2-6 December 2010

VII AUXILIARY SYSTEMS

H2 Emergency Diesel Generator System

Item Link Structure and/or 

Component Material Environment Aging Effect/ 

Mechanism

Aging Management Prog

(AMP)

VII.H2.AP209Piping, piping 

components, and 

piping elements; 

tanks

Stainless steel Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "External 

Monitoring of Mechanical 

Components"

VII.H2.AP221Piping, piping 

components, and 

piping elements; 

tanks

Stainless steel Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External 

Monitoring of Mechanical 

Components"

VII.H2.AP202VII.H2-

23(A-25)

Piping, piping 

components, and 

piping elements; 

tanks

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M21A, "Closed 

Water Systems"

VII.H2.AP105VII.H2-

24(A-30)

Piping, piping 

components, and 

piping elements; 

tanks

Steel Fuel oil Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

corrosion

Chapter XI.M30, “Fuel Oil 

Chemistry,” and 

Chapter XI.M32, “One-Time 

Inspection”
December 2010 VII I-1 NUREG-1801, Rev. 2

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 bolting 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. 2 VII I-2 December 2010

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 

VII.I.AP-261 Bolting Copper alloyAny 

environment

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integr

VII.I.AP-262 Bolting Nickel alloy Any 

environment

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integr

VII.I.AP-243 Bolting Stainless 

steel

Soil or concrete Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M41, "Buried and 

Underground Piping and Tanks

VII.I.AP-244 Bolting Stainless 

steel

Soil Loss of preload Chapter XI.M18, "Bolting Integr

VII.I.AP-265 Bolting Stainless 

steel

Treated borated 

water

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integr

VII.I.A-102 VII.I-2(A102)Bolting Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid Co

VII.I.AP-241 Bolting Steel Soil or concrete Loss of material

due to general, 

pitting and crevice 

corrosion

Chapter XI.M41, "Buried and 

Underground Piping and Tanks

VII.I.AP-242 Bolting Steel Soil Loss of preload Chapter XI.M18, "Bolting Integr
December 2010 VII I-3 NUREG-1801, Rev. 2

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 

VII.I.AP-126 VII.I-1(AP28)Bolting Steel; 

stainless 

steel

Air – outdoor 

(External)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice corrosion

Chapter XI.M18, "Bolting Integr

VII.I.AP-263 Bolting Steel; 

stainless 

steel

Air – outdoor 

(External)

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integr

VII.I.AP-266 Bolting Steel; 

stainless 

steel

Fuel oil Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integr

VII.I.AP-264 Bolting Steel; 

stainless 

steel

Raw water Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integr

VII.I.AP-267 Bolting Steel; 

stainless 

steel

Treated water Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integr

VII.I.A-03 VII.I-6(A03)Closure 

bolting

Steel Air with steam or 

water leakage

Loss of material 

due to general 

corrosion

Chapter XI.M18, "Bolting Integr

VII.I.A-04 VII.I-3(A04)Closure 

bolting

Steel, highstrengthAir with steam or 

water leakage

Cracking 

due to stress 

corrosion 

cracking; cyclic 

loading

Chapter XI.M18, "Bolting Integr
NUREG-1801, Rev. 2 VII I-4 December 2010

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 

VII.I.AP-125 VII.I-4(AP27)Closure 

bolting

Steel; 

stainless 

steel

Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice corrosion

Chapter XI.M18, "Bolting Integr

VII.I.AP-124 VII.I-5(AP26)Closure 

bolting

Steel; 

stainless 

steel

Air – indoor, 

uncontrolled 

(External)

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integr

VII.I.A-105 VII.I-7(A105)Ducting; 

closure bolting

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External Surfa

Monitoring of Mechanical Comp

VII.I.A-77 VII.I-8(A77)External 

surfaces

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External Surfa

Monitoring of Mechanical Comp

VII.I.A-78 VII.I-9(A78)External 

surfaces

Steel Air – outdoor 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External Surfa

Monitoring of Mechanical Comp

VII.I.A-79 VII.I-10(A79)External 

surfaces

Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid Co

VII.I.A-81 VII.I-11(A81)External 

surfaces

Steel Condensation 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External Surfa

Monitoring of Mechanical Comp

VII.I.AP-256 Piping, piping 

components, 

and piping 

elements

Aluminum Air - outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External Surfa

Monitoring of Mechanical Comp
December 2010 VII I-5 NUREG-1801, Rev. 2

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 

VII.I.AP-159 Piping, piping 

components, 

and piping 

elements

Copper alloyAir – outdoor 

(External)

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External Surfa

Monitoring of Mechanical Comp

VII.I.AP-66 VII.I12(AP-66)Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid Co

VII.I.AP-284 Underground 

piping, piping 

components, 

and piping 

elements

Steel; 

stainless 

steel; 

copper 

alloy; 

aluminum

Air-indoor 

uncontrolled or 

condensation 

(external)

Loss of material 

due to general 

(steel only), pitting 

and crevice 

corrosion

Chapter XI.M41, “Buried and 

Underground Piping and Tanks

December 2010 VII J-1 NUREG-1801, Rev. 2

J. 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 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 period of extended 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. 2 VII J-2 December 2010

VII AUXILIARY SYSTEMS 

J Common Miscellaneous Material/Environment Combinations

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progr

(AMP)

VII.J.AP-151 Heat 

exchanger 

components

Titanium Air – indoor, 

uncontrolled or Air – 

outdoor

None None 

VII.J.AP-48 VII.J7(AP-48)Piping 

elements

Glass Air None None 

VII.J.AP-14 VII.J8(AP-14)Piping 

elements

Glass Air – indoor, 

uncontrolled 

(External)

None None 

VII.J.AP-167 Piping 

elements

Glass Air – outdoor None None 

VII.J.AP-96 Piping 

elements

Glass Air with borated 

water leakage

None None 

VII.J.AP-166 Piping 

elements

Glass Closed-cycle 

cooling water

None None 

VII.J.AP-97 Piping 

elements

Glass Condensation 

(Internal/External)

None None 

VII.J.AP-49 VII.J9(AP-49)Piping 

elements

Glass Fuel oil None None 

VII.J.AP-98 Piping 

elements

Glass Gas None None 
December 2010 VII J-3 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS 

J Common Miscellaneous Material/Environment Combinations

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progr

(AMP)

VII.J.AP-15 VII.J10(AP-15)Piping 

elements

Glass Lubricating oil None None 

VII.J.AP-50 VII.J11(AP-50)Piping 

elements

Glass Raw water None None 

VII.J.AP-52 VII.J12(AP-52)Piping 

elements

Glass Treated borated 

water

None None 

VII.J.AP-51 VII.J13(AP-51)Piping 

elements

Glass Treated water None None 

VII.J.AP-36 VII.J1(AP-36)Piping, piping 

components, 

and piping 

elements

Aluminum Air – indoor, 

controlled (External)

None None 

VII.J.AP-134 Piping, piping 

components, 

and piping 

elements

Aluminum Air – dry 

(Internal/External)

None None 

VII.J.AP-135 Piping, piping 

components, 

and piping 

elements

Aluminum Air – indoor, 

uncontrolled 

(Internal/External)

None None 

VII.J.AP-37 VII.J2(AP-37)Piping, piping 

components, 

and piping 

elements

Aluminum Gas None None 
NUREG-1801, Rev. 2 VII J-4 December 2010

VII AUXILIARY SYSTEMS 

J Common Miscellaneous Material/Environment Combinations

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progr

(AMP)

VII.J.AP-8 VII.J3(AP-8)Piping, piping 

components, 

and piping 

elements

Copper alloy Air – dry None None 

VII.J.AP-144 Piping, piping 

components, 

and piping 

elements

Copper alloy Air – indoor, 

uncontrolled 

(Internal/External)

None None 

VII.J.AP-9 VII.J4(AP-9)Piping, piping 

components, 

and piping 

elements

Copper alloy Gas None None 

VII.J.AP-11 VII.J5(AP-11)Piping, piping 

components, 

and piping 

elements

Copper alloy 

(≤15% Zn and 

≤8% Al)

Air with borated 

water leakage

None None 

VII.J.AP-13 VII.J6(AP-13)Piping, piping 

components, 

and piping 

elements

Galvanized 

steel

Air - indoor, 

uncontrolled

None None 

VII.J.AP-277 Piping, piping 

components, 

and piping 

elements

Glass Waste water None None 

VII.J.AP-16 VII.J14(AP-16)Piping, piping 

components, 

and piping 

elements

Nickel alloy Air – indoor, 

uncontrolled 

(External)

None None 

VII.J.AP-260 Piping, piping 

components, 

and piping 

elements

Nickel alloy Air with borated 

water leakage

None None 
December 2010 VII J-5 NUREG-1801, Rev. 2

VII AUXILIARY SYSTEMS 

J Common Miscellaneous Material/Environment Combinations

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progr

(AMP)

VII.J.AP-268 Piping, piping 

components, 

and piping 

elements

PVC Air – indoor, 

uncontrolled

None None 

VII.J.AP-269 Piping, piping 

components, 

and piping 

elements

PVC Condensation 

(Internal)

None None 

VII.J.AP-20 VII.J18(AP-20)Piping, piping 

components, 

and piping 

elements

Stainless steel Air – dry None None 

VII.J.AP-17 VII.J15(AP-17)Piping, piping 

components, 

and piping 

elements

Stainless steel Air – indoor, 

uncontrolled 

(External)

None None 

VII.J.AP-123 Piping, piping 

components, 

and piping 

elements

Stainless steel Air – indoor, 

uncontrolled 

(Internal/External)

None None 

VII.J.AP-18 VII.J16(AP-18)Piping, piping 

components, 

and piping 

elements

Stainless steel Air with borated 

water leakage

None None 

VII.J.AP-19 VII.J17(AP-19)Piping, piping 

components, 

and piping 

elements

Stainless steel Concrete None None 

VII.J.AP-22 VII.J19(AP-22)Piping, piping 

components, 

and piping 

elements

Stainless steel Gas None None 
NUREG-1801, Rev. 2 VII J-6 December 2010

VII AUXILIARY SYSTEMS 

J Common Miscellaneous Material/Environment Combinations

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Progr

(AMP)

VII.J.AP-4 VII.J22(AP-4)Piping, piping 

components, 

and piping 

elements

Steel Air – dry None None 

VII.J.AP-2 VII.J20(AP-2)Piping, piping 

components, 

and piping 

elements

Steel Air – indoor, 

controlled (External)

None None 

VII.J.AP-282 VII.J21(AP-3)Piping, piping 

components, 

and piping 

elements

Steel Concrete None None, provided 

1) attributes of the concrete 

consistent with ACI 318 or A

(low water-to-cement ratio, 

permeability, and adequate 

entrainment) as cited in NU

1557, and 

2) plant OE indicates no

degradation of the concrete

VII.J.AP-6 VII.J23(AP-6)Piping, piping 

components, 

and piping 

elements

Steel Gas None None 

VII.J.AP-160 Piping, piping 

components, 

and piping 

elements

Titanium Air – indoor, 

uncontrolled or Air – 

outdoor

None None 
 

December 2010 VIII-i NUREG-1801, Rev. 2

CHAPTER VIII

STEAM AND POWER CONVERSION SYSTEM

 

December 2010 VIII-iii NUREG-1801, Rev. 2

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

 

December 2010 VIII A-1 NUREG-1801, Rev. 2

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 a 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 period of extended 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. 2 VIII A-2 December 201

0

VIII STEAM AND POWER CONVERSION SYSTEM

A Steam Turbine System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VIII.A.S-23 VIII.A-1(S23)Heat 

exchanger 

components

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed Tre

Water Systems"

VIII.A.SP-64 VIII.A2(SP-64)Heat 

exchanger 

components 

and tubes

Steel Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Closed Tre

Water Systems"

VIII.A.SP-92 VIII.A3(SP-32)Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M39, "Lubricating O

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection” 

VIII.A.SP-31 VIII.A4(SP-31)Piping, piping 

components, 

and piping 

elements

Copper alloy Raw water Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M20, "Open-Cycle 

Water System"

VIII.A.SP-101 VIII.A5(SP-61)Piping, piping 

components, 

and piping 

elements

Copper alloy Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time 

Inspection”

VIII.A.SP-30 VIII.A6(SP-30)Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Raw water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective Lea

VIII.A.SP-28 VIII.A7(SP-28)Piping, piping 

components, 

and piping 

elements

Gray cast 

iron

Raw water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective Lea
December 2010 VIII A-3 NUREG-1801, Rev. 2 

VIII STEAM AND POWER CONVERSION SYSTEM

A Steam Turbine System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VIII.A.SP-27 VIII.A8(SP-27)Piping, piping 

components, 

and piping

elements

Gray cast 

iron

Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective Lea

VIII.A.SP-95 VIII.A9(SP-38)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Lubricating oil Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M39, "Lubricating O

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection” 

VIII.A.SP-98 VIII.A11(SP-45)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Steam Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time 

Inspection”

VIII.A.SP-155 VIII.A12(SP-43)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Steam Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time 

Inspection”

VIII.A.SP-91 VIII.A14(SP-25)Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M39, "Lubricating O

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection” 

VIII.A.SP-71 VIII.A15(S-04)Piping, piping 

components, 

and piping 

elements

Steel Steam Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time 

Inspection”

VIII.A.S-15 VIII.A17(S-15)Piping, piping 

components, 

and piping 

elements

Steel Steam Wall thinning 

due to flowaccelerated 

corrosion

Chapter XI.M17, “Flow-Acceler

Corrosion”
NUREG-1801, Rev. 2 VIII A-4 December 201

0

VIII STEAM AND POWER CONVERSION SYSTEM

A Steam Turbine System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VIII.A.SP-118 Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "External Sur

Monitoring of Mechanical 

Components"

VIII.A.SP-127 Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External Sur

Monitoring of Mechanical 

Components"
 

December 2010 VIII B1-1 NUREG-1801, Rev. 2

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 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 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 period of extended 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. 2 VIII B1-2 December 2010

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 

VIII.B1.SP157VIII.B1-

1(SP-18)

Piping, piping 

components, 

and piping 

elements

Nickel alloy Steam Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time 

Inspection”

VIII.B1.SP110Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Condensation 

(Internal)

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M38, "Inspection of 

Surfaces in Miscellaneous Pipi

Ducting Components"

VIII.B1.SP-98 VIII.B1-

2(SP-44)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Steam Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time 

Inspection”

VIII.B1.SP155VIII.B1-

3(SP-43)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Steam Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time

Inspection”

VIII.B1.SP-87 VIII.B1-

4(SP-16)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time 

Inspection”

VIII.B1.SP-88 VIII.B1-

5(SP-17)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time 

Inspection”

VIII.B1.SP-59 VIII.B1-

6(SP-59)

Piping, piping 

components, 

and piping 

elements

Steel Air – outdoor 

(Internal)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M38, "Inspection of 

Surfaces in Miscellaneous Pipi

Ducting Components"

VIII.B1.SP-60 VIII.B1-

7(SP-60)

Piping, piping 

components, 

and piping 

elements

Steel Condensation 

(Internal)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M38, "Inspection of 

Surfaces in Miscellaneous Pipi

Ducting Components"
December 2010 VIII B1-3 NUREG-1801, Rev. 2 

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 

VIII.B1.SP-71 VIII.B1-

8(S-07)

Piping, piping 

components, 

and piping 

elements

Steel Steam Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time 

Inspection”

VIII.B1.S-15 VIII.B1-

9(S-15)

Piping, piping 

components, 

and piping 

elements

Steel Steam Wall thinning 

due to flowaccelerated 

corrosion

Chapter XI.M17, “Flow-Acceler

Corrosion”

VIII.B1.S-08 VIII.B1-

10(S-08)

Piping, piping 

components, 

and piping 

elements

Steel Steam or 

Treated water

Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time-limited aging 

(TLAA) to be evaluated for the 

of extended operation. See the 

Section 4.3 “Metal Fatigue,” fo

acceptable methods for meetin

requirements of 10 CFR 54.21

VIII.B1.SP-74 VIII.B1-

11(S-10)

Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time 

Inspection”

VIII.B1.SP118Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "External Surf

Monitoring of Mechanical 

Components"

VIII.B1.SP127Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External Surf

Monitoring of Mechanical 

Components"

 

December 2010 VIII B2-1 NUREG-1801, Rev. 2

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 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 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 period of extended 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. 2 VIII B2-2 December 2010

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 

VIII.B2.SP110Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Condensation 

(Internal)

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M38, "Inspection of 

Surfaces in Miscellaneous Pipi

Ducting Components"

VIII.B2.SP-98 VIII.B2-

1(SP-45)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Steam Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time 

Inspection”

VIII.B2.SP155VIII.B2-

2(SP43)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Steam Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time 

Inspection”

VIII.B2.SP160VIII.B2-

3(S-05)

Piping, piping 

components, 

and piping 

elements

Steel Steam Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time 

Inspection”

VIII.B2.S-15 VIII.B2-

4(S-15)

Piping, piping 

components, 

and piping 

elements

Steel Steam Wall thinning 

due to flowaccelerated 

corrosion

Chapter XI.M17, “Flow-Acceler

Corrosion”

VIII.B2.S-08 VIII.B2-

5(S-08)

Piping, piping 

components, 

and piping 

elements

Steel Steam or 

Treated water

Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time-limited aging 

(TLAA) to be evaluated for the 

of extended operation. See the 

Section 4.3 “Metal Fatigue,” fo

acceptable methods for meetin

requirements of 10 CFR 54.21

VIII.B2.SP-73 VIII.B2-

6(S-09)

Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time 

Inspection”
December 2010 VIII B2-3 NUREG-1801, Rev. 2

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 

VIII.B2.SP118Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "External Sur

Monitoring of Mechanical 

Components"

VIII.B2.SP127Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External Sur

Monitoring of Mechanical 

Components"

 

December 2010 VIII C-1 NUREG-1801, Rev. 2

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 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 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 period of extended 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. 2 VIII C-2 December 2010

VIII STEAM AND POWER CONVERSION SYSTEM

C Extraction Steam System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VIII.C.SP-87 VIII.C1(SP-16)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time 

Inspection”

VIII.C.SP-88 VIII.C2(SP-17)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time 

Inspection”

VIII.C.SP-71 VIII.C-3(S04)Piping, piping 

components, 

and piping 

elements

Steel Steam Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time 

Inspection”

VIII.C.S-15 VIII.C-5(S15)Piping, piping 

components, 

and piping 

elements

Steel Steam Wall thinning 

due to flowaccelerated 

corrosion

Chapter XI.M17, “Flow-Acceler

Corrosion”

VIII.C.SP-73 VIII.C-6(S09)Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M2, “Water Chemis

Chapter XI.M32, “One-Time 

Inspection”

VIII.C.SP-118 Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "External Sur

Monitoring of Mechanical 

Components"

VIII.C.SP-127 Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External Sur

Monitoring of Mechanical 

Components"
December 2010 VIII D1-1 NUREG-1801, Rev. 2

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 period of extended 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. 2 VIII D1-2 December 2010

VIII STEAM AND POWER CONVERSION SYSTEM

D1 Feedwater Systems (PWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VIII.D1.SP-90 VIII.D1-

1(SP-24)

Piping, piping 

components, 

and piping 

elements

Aluminum Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”

VIII.D1.SP-92 VIII.D1-

2(SP-32)

Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M39, "Lubricating 

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection” 

VIII.D1.SP-95 VIII.D1-

3(SP-38)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Lubricating oil Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M39, "Lubricating 

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection” 

VIII.D1.SP-87 VIII.D1-

4(SP-16)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”

VIII.D1.SP-88 VIII.D1-

5(SP-17)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”

VIII.D1.SP-91 VIII.D1-

6(SP-25)

Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M39, "Lubricating 

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection” 

VIII.D1.S-11 VIII.D1-

7(S-11)

Piping, piping 

components, 

and piping 

elements

Steel Treated water Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluate

the period of extended operat

the SRP, Section 4.3 “Metal F

for acceptable methods for me

the requirements of 10 CFR 

54.21(c)(1).
December 2010 VIII D1-3 NUREG-1801, Rev. 2

VIII STEAM AND POWER CONVERSION SYSTEM

D1 Feedwater Systems (PWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VIII.D1.SP-74 VIII.D1-

8(S-10)

Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”

VIII.D1.S-16 VIII.D1-

9(S-16)

Piping, piping 

components, 

and piping 

elements

Steel Treated water Wall thinning 

due to flowaccelerated 

corrosion

Chapter XI.M17, “Flow-Accele

Corrosion”

VIII.D1.SP118Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "External Su

Monitoring of Mechanical 

Components"

VIII.D1.SP127Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External Su

Monitoring of Mechanical 

Components"

 

December 2010 VIII D2-1 NUREG-1801, Rev. 2

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 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 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 period of extended 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. 2 VIII D2-2 December 2010

VIII STEAM AND POWER CONVERSION SYSTEM

D2 Feedwater Systems (BWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VIII.D2.SP-90 VIII.D2-

1(SP-24)

Piping, piping 

components, 

and piping 

elements

Aluminum Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”

VIII.D2.SP-92 VIII.D2-

2(SP-32)

Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M39, "Lubricating 

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection” 

VIII.D2.SP-95 VIII.D2-

3(SP-38)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Lubricating oil Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Chapter XI.M39, "Lubricating 

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection” 

VIII.D2.SP-87 VIII.D2-

4(SP-16)

Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”

VIII.D2.SP-91 VIII.D2-

5(SP-25)

Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M39, "Lubricating 

Analysis," and 

Chapter XI.M32, “One-Time 

Inspection” 

VIII.D2.S-11 VIII.D2-

6(S-11)

Piping, piping 

components, 

and piping 

elements

Steel Treated water Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time-limited aging 

analysis (TLAA) to be evaluate

the period of extended operat

the SRP, Section 4.3 “Metal F

for acceptable methods for me

the requirements of 10 CFR 

54.21(c)(1).

VIII.D2.SP-73 VIII.D2-

7(S-09)

Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M2, “Water Chemi

and 

Chapter XI.M32, “One-Time 

Inspection”
December 2010 VIII D2-3 NUREG-1801, Rev. 2

VIII STEAM AND POWER CONVERSION SYSTEM

D2 Feedwater Systems (BWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism Aging Management Program 

VIII.D2.S-16 VIII.D2-

8(S-16)

Piping, piping 

components, 

and piping 

elements

Steel Treated water Wall thinning 

due to flowaccelerated 

corrosion

Chapter XI.M17, “Flow-Accele

Corrosion”

VIII.D2.SP118Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "External Su

Monitoring of Mechanical 

Components"

VIII.D2.SP127Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External Su

Monitoring of Mechanical 

Components"

 

December 2010 VIII E-1 NUREG-1801, Rev. 2

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 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 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 period of extended 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 

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. 2 VIII E-2 December 2010

VIII STEAM AND POWER CONVERSION SYSTEM

E Condensate System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management 

Program (AMP)

VIII.E.S-25 VIII.E2(S-25)Heat exchanger 

components

Stainless 

steel

Closed-cycle

cooling water

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M21A, "Clo

Treated Water System

VIII.E.SP117VIII.E3(S-26)Heat exchanger 

components

Stainless 

steel

Raw water Loss of material 

due to general, pitting, 

crevice, galvanic, and 

microbiologicallyinfluenced corrosion; 

fouling that leads to 

corrosion

Chapter XI.M20, "Ope

Cooling Water System

VIII.E.S-23 VIII.E5(S-23)Heat exchanger 

components

Steel Closed-cycle 

cooling water

Loss of material 

due to general, pitting, 

crevice, and galvanic 

corrosion

Chapter XI.M21A, "Clo

Treated Water System

VIII.E.SP146VIII.E6(S-24)Heat exchanger 

components

Steel Raw water Loss of material 

due to general, pitting, 

crevice, galvanic, and 

microbiologicallyinfluenced corrosion; 

fouling that leads to 

corrosion

Chapter XI.M20, "Ope

Cooling Water System

VIII.E.SP-77 VIII.E7(S-18)Heat exchanger 

components

Steel Treated water Loss of material 

due to general, pitting, 

crevice, and galvanic 

corrosion

Chapter XI.M2, “Wate

Chemistry,” and 

Chapter XI.M32, “One

Inspection”

VIII.E.SP-80 VIII.E4(S-21)Heat exchanger 

components and 

tubes

Stainless 

steel

Treated water Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M2, “Wate

Chemistry,” and 

Chapter XI.M32, “One

Inspection”

VIII.E.SP-57 VIII.E8(SP-57)Heat exchanger 

tubes

Copper alloy Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Clo

Treated Water System
December 2010 VIII E-3 NUREG-1801, Rev. 2

VIII STEAM AND POWER CONVERSION SYSTEM

E Condensate System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management 

Program (AMP)

VIII.E.SP-56 VIII.E9(SP-56)Heat exchanger 

tubes

Copper alloy Raw water Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "Ope

Cooling Water System

VIII.E.SP100VIII.E10(SP58)

Heat exchanger 

tubes

Copper alloy Treated water Reduction of heat 

transfer 

due to fouling

Chapter XI.M2, “Wate

Chemistry,” and 

Chapter XI.M32, “One

Inspection”

VIII.E.SP-41 VIII.E11(SP41)Heat exchanger 

tubes

Stainless 

steel

Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Clo

Treated Water System

VIII.E.S-28 VIII.E12(S-28)Heat exchanger 

tubes

Stainless 

steel

Raw water Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "Ope

Cooling Water System

VIII.E.SP-96 VIII.E13(SP40)Heat exchanger 

tubes

Stainless 

steel

Treated water Reduction of heat 

transfer 

due to fouling

Chapter XI.M2, “Wate

Chemistry,” and 

Chapter XI.M32, “One

Inspection”

VIII.E.SP-64 VIII.E14(SP64)Heat exchanger 

tubes

Steel Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Clo

Treated Water System

VIII.E.SP-90 VIII.E15(SP24)Piping, piping 

components, and 

piping elements

Aluminum Treated water Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M2, “Wate

Chemistry,” and 

Chapter XI.M32, “One

Inspection”

VIII.E.SP-8 VIII.E16(SP-8)Piping, piping 

components, and 

piping elements

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to pitting, crevice, 

and galvanic corrosion

Chapter XI.M21A, "Clo

Treated Water System

VIII.E.SP-92 VIII.E17(SP32)Piping, piping 

components, and 

piping elements

Copper alloy Lubricating oil Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M39, "Lubr

Oil Analysis," and 

Chapter XI.M32, “One

Inspection” 
NUREG-1801, Rev. 2 VIII E-4 December 2010

VIII STEAM AND POWER CONVERSION SYSTEM

E Condensate System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management 

Program (AMP)

VIII.E.SP-31 VIII.E18(SP31)Piping, piping 

components, and 

piping elements

Copper alloy Raw water Loss of material 

due to pitting, crevice, 

and microbiologicallyinfluenced corrosion

Chapter XI.M20, "Ope

Cooling Water System

VIII.E.SP-29 VIII.E19(SP29)Piping, piping 

components, and 

piping elements

Copper alloy 

(>15% Zn or 

>8% Al)

Closed-cycle 

cooling water

Loss of material 

due to selective leaching

Chapter XI.M33, “Sele

Leaching”

VIII.E.SP-30 VIII.E20(SP30)Piping, piping 

components, and 

piping elements

Copper alloy 

(>15% Zn or 

>8% Al)

Raw water Loss of material 

due to selective leaching

Chapter XI.M33, “Sele

Leaching”

VIII.E.SP-55 VIII.E21(SP55)Piping, piping 

components, and 

piping elements

Copper alloy 

(>15% Zn or 

>8% Al)

Treated water Loss of material 

due to selective leaching

Chapter XI.M33, “Sele

Leaching”

VIII.E.SP-26 VIII.E22(SP26)Piping, piping 

components, and 

piping elements

Gray cast iron Soil Loss of material 

due to selective leaching

Chapter XI.M33, “Sele

Leaching”

VIII.E.SP-27 VIII.E23(SP27)Piping, piping 

components, and 

piping elements

Gray cast iron Treated water Loss of material 

due to selective leaching

Chapter XI.M33, “Sele

Leaching”

VIII.E.SP-39 VIII.E24(SP39)Piping, piping 

components, and 

piping elements

Stainless 

steel

Closed-cycle 

cooling water

Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M21A, "Clo

Treated Water System

VIII.E.SP-54 VIII.E25(SP54)Piping, piping 

components, and 

piping elements

Stainless 

steel

Closed-cycle 

cooling water 

>60°C (>140°F)

Cracking 

due to stress corrosion 

cracking

Chapter XI.M21A, "Clo

Treated Water System

VIII.E.SP-95 VIII.E26(SP38)Piping, piping 

components, and 

piping elements

Stainless 

steel

Lubricating oil Loss of material 

due to pitting, crevice, 

and microbiologicallyinfluenced corrosion

Chapter XI.M39, "Lubr

Oil Analysis," and 

Chapter XI.M32, “One

Inspection” 
December 2010 VIII E-5 NUREG-1801, Rev. 2

VIII STEAM AND POWER CONVERSION SYSTEM

E Condensate System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management 

Program (AMP)

VIII.E.SP-36 VIII.E27(SP36)Piping, piping 

components, and 

piping elements

Stainless 

steel

Raw water Loss of material 

due to pitting, crevice, 

and microbiologicallyinfluenced corrosion

Chapter XI.M20, "Ope

Cooling Water System

VIII.E.SP-94 VIII.E28(SP37)Piping, piping 

components, and 

piping elements

Stainless 

steel

Soil or concrete Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M41, "Buri

Underground Piping a

Tanks"

VIII.E.SP-87 VIII.E29(SP16)Piping, piping 

components, and 

piping elements

Stainless 

steel

Treated water Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M2, “Wate

Chemistry,” and 

Chapter XI.M32, “One

Inspection”

VIII.E.SP-88 VIII.E30(SP17)Piping, piping 

components, and 

piping elements

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking 

due to stress corrosion 

cracking

Chapter XI.M2, “Wate

Chemistry,” and 

Chapter XI.M32, “One

Inspection”

VIII.E.SP-91 VIII.E32(SP25)Piping, piping 

components, and 

piping elements

Steel Lubricating oil Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.M39, "Lubr

Oil Analysis," and 

Chapter XI.M32, “One

Inspection” 

VIII.E.SP-73 VIII.E33(S-09)Piping, piping 

components, and 

piping elements

Steel Treated water Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.M2, “Wate

Chemistry,” and 

Chapter XI.M32, “One

Inspection”

VIII.E.S-16 VIII.E35(S-16)Piping, piping 

components, and 

piping elements

Steel Treated water Wall thinning 

due to flow-accelerated 

corrosion

Chapter XI.M17, “Flow

Accelerated Corrosion

VIII.E.SP118Piping, piping 

components, and 

piping elements; 

tanks

Stainless 

steel

Air – outdoor Cracking 

due to stress corrosion 

cracking

Chapter XI.M36, "Exte

Surfaces Monitoring o

Mechanical Compone
NUREG-1801, Rev. 2 VIII E-6 December 2010

VIII STEAM AND POWER CONVERSION SYSTEM

E Condensate System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management 

Program (AMP)

VIII.E.SP127Piping, piping 

components, and 

piping elements; 

tanks

Stainless 

steel

Air – outdoor Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M36, "Exte

Surfaces Monitoring o

Mechanical Compone

VIII.E.SP145VIII.E1(S-01)Piping, piping 

components, and 

piping elements; 

tanks

Steel (with 

coating or 

wrapping)

Soil or concrete Loss of material 

due to general, pitting, 

crevice, and 

microbiologicallyinfluenced corrosion

Chapter XI.M41, "Buri

Underground Piping a

Tanks"

VIII.E.SP-81 VIII.E36(S-22)PWR heat 

exchanger 

components

Stainless 

steel

Treated water Loss of material 

due to pitting and crevice 

corrosion

Chapter XI.M2, “Wate

Chemistry,” and 

Chapter XI.M32, “One

Inspection”

VIII.E.SP-78 VIII.E37(S-19)PWR heat 

exchanger 

components

Steel Treated water Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.M2, “Wate

Chemistry,” and 

Chapter XI.M32, “One

Inspection”

VIII.E.SP140Tanks Aluminum Air – outdoor 

(External)

Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.M29, 

“Aboveground Metallic 

Tanks”

VIII.E.SP139Tanks Aluminum Soil or Concrete Loss of material 

due to pitting, and 

crevice corrosion

Chapter XI.M29, 

“Aboveground Metallic 

Tanks”

VIII.E.SP138Tanks Stainless 

steel

Air – outdoor 

(External)

Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.M29, 

“Aboveground Metallic 

Tanks”

VIII.E.SP137Tanks Stainless 

steel

Soil or Concrete Loss of material 

due to pitting, and 

crevice corrosion

Chapter XI.M29, 

“Aboveground Metallic 

Tanks”
December 2010 VIII E-7 NUREG-1801, Rev. 2

VIII STEAM AND POWER CONVERSION SYSTEM

E Condensate System

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management 

Program (AMP)

VIII.E.SP-97 VIII.E38(SP42)Tanks Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking 

due to stress corrosion 

cracking

Chapter XI.M2, “Wate

Chemistry,” and 

Chapter XI.M32, “One

Inspection”

VIII.E.S-31 VIII.E39(S-31)Tanks Steel Air – outdoor 

(External)

Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.M29, 

“Aboveground Metallic 

Tanks”

VIII.E.SP115Tanks Steel Soil or Concrete Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.M29, 

“Aboveground Metallic 

Tanks”

VIII.E.SP-75 VIII.E40(S-13)Tanks Steel; 

stainless steel

Treated water Loss of material 

due to general (steel 

only), pitting, and crevice 

corrosion

Chapter XI.M2, “Wate

Chemistry,” and 

Chapter XI.M32, “One

Inspection”

 

December 2010 VIII F-1 NUREG-1801, Rev. 2

F. STEAM GENERATOR 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 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 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 period of extended 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. 2 VIII F-2 December 2010

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 Progr

(AMP)

VIII.F.SP-56 VIII.F6(SP-56)Heat 

exchanger 

components

Copper alloy Raw water Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "Open-Cy

Cooling Water System"

VIII.F.S-25 VIII.F-1(S25)Heat 

exchanger 

components

Stainless 

steel

Closed-cycle 

cooling water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M21A, "Closed 

Water Systems"

VIII.F.SP117VIII.F-2(S26)Heat 

exchanger 

components

Stainless 

steel

Raw water Loss of material 

due to pitting, crevice, 

and microbiologicallyinfluenced corrosion; 

fouling that leads to 

corrosion

Chapter XI.M20, "Open-Cy

Cooling Water System"

VIII.F.SP-85 VIII.F-3(S39)Heat 

exchanger 

components

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking 

due to stress corrosion 

cracking

Chapter XI.M2, “Water Che

and 

Chapter XI.M32, “One-Time 

Inspection”

VIII.F.S-23 VIII.F-4(S23)Heat 

exchanger 

components

Steel Closed-cycle 

cooling water

Loss of material 

due to general, pitting, 

crevice, and galvanic 

corrosion

Chapter XI.M21A, "Closed 

Water Systems"

VIII.F.SP146VIII.F-5(S24)Heat 

exchanger 

components

Steel Raw water Loss of material 

due to general, pitting, 

crevice, galvanic, and 

microbiologicallyinfluenced corrosion; 

fouling that leads to 

corrosion

Chapter XI.M20, "Open-Cy

Cooling Water System"

VIII.F.SP100VIII.F7(SP-58)Heat 

exchanger 

tubes

Copper alloy Treated water Reduction of heat 

transfer 

due to fouling

Chapter XI.M2, “Water Che

and 

Chapter XI.M32, “One-Time 

Inspection”
December 2010 VIII F-3 NUREG-1801, Rev. 2

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 Progr

(AMP)

VIII.F.SP-41 VIII.F8(SP-41)Heat 

exchanger 

tubes

Stainless 

steel

Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Closed 

Water Systems"

VIII.F.S-28 VIII.F-9(S28)Heat 

exchanger 

tubes

Stainless 

steel

Raw water Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "Open-Cy

Cooling Water System"

VIII.F.SP-96 VIII.F10(SP-40)Heat 

exchanger 

tubes

Stainless 

steel

Treated water Reduction of heat 

transfer 

due to fouling

Chapter XI.M2, “Water Che

and 

Chapter XI.M32, “One-Time 

Inspection”

VIII.F.SP-64 VIII.F11(SP-64)Heat 

exchanger 

tubes

Steel Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Closed 

Water Systems"

VIII.F.SP-90 VIII.F12(SP-24)Piping, piping 

components, 

and piping 

elements

Aluminum Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Che

and 

Chapter XI.M32, “One-Time 

Inspection”

VIII.F.SP-8 VIII.F13(SP-8)Piping, piping 

components, 

and piping 

elements

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to pitting, crevice, 

and galvanic corrosion

Chapter XI.M21A, "Closed 

Water Systems"

VIII.F.SP-31 VIII.F14(SP-31)Piping, piping 

components, 

and piping 

elements

Copper alloy Raw water Loss of material 

due to pitting, crevice, 

and microbiologicallyinfluenced corrosion

Chapter XI.M20, "Open-Cy

Cooling Water System"

VIII.F.SP101VIII.F15(SP-61)Piping, piping 

components, 

and piping 

elements

Copper alloy Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Che

and 

Chapter XI.M32, “One-Time 

Inspection”
NUREG-1801, Rev. 2 VIII F-4 December 2010

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 Progr

(AMP)

VIII.F.SP-29 VIII.F16(SP-29)Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VIII.F.SP-30 VIII.F17(SP-30)Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Raw water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VIII.F.SP-55 VIII.F18(SP-55)Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VIII.F.SP-27 VIII.F19(SP-27)Piping, piping 

components, 

and piping 

elements

Gray cast iron Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VIII.F.SP-39 VIII.F20(SP-39)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed-cycle 

cooling water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M21A, "Closed 

Water Systems"

VIII.F.SP-54 VIII.F21(SP-54)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Closed-cycle 

cooling water 

>60°C (>140°F)

Cracking 

due to stress corrosion 

cracking

Chapter XI.M21A, "Closed 

Water Systems"

VIII.F.SP-36 VIII.F22(SP-36)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Raw water Loss of material 

due to pitting, crevice, 

and microbiologicallyinfluenced corrosion

Chapter XI.M20, "Open-Cy

Cooling Water System"

VIII.F.SP-87 VIII.F23(SP-16)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Che

and 

Chapter XI.M32, “One-Time 

Inspection”
December 2010 VIII F-5 NUREG-1801, Rev. 2

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 Progr

(AMP)

VIII.F.SP-88 VIII.F24(SP-17)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Treated water 

>60°C (>140°F)

Cracking 

due to stress corrosion 

cracking

Chapter XI.M2, “Water Che

and 

Chapter XI.M32, “One-Time 

Inspection”

VIII.F.SP-74 VIII.F25(S-10)Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.M2, “Water Che

and 

Chapter XI.M32, “One-Time 

Inspection”

VIII.F.S-16 VIII.F26(S-16)Piping, piping 

components, 

and piping 

elements

Steel Treated water Wall thinning 

due to flow-accelerated 

corrosion

Chapter XI.M17, “Flow-Acc

Corrosion”

VIII.F.SP118Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Cracking 

due to stress corrosion 

cracking

Chapter XI.M36, "External 

Monitoring of Mechanical 

Components"

VIII.F.SP127Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless 

steel

Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External 

Monitoring of Mechanical 

Components" 

VIII.F.SP-81 VIII.F27(S-22)PWR heat 

exchanger 

components

Stainless 

steel

Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Che

and 

Chapter XI.M32, “One-Time 

Inspection”

VIII.F.SP-78 VIII.F28(S-19)PWR heat 

exchanger 

components

Steel Treated water Loss of material 

due to general, pitting, 

and crevice corrosion

Chapter XI.M2, “Water Che

and 

Chapter XI.M32, “One-Time 

Inspection”

 

December 2010 VIII G-1 NUREG-1801, Rev. 2

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 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 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 period of extended 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. 2 VIII G-2 December 2010

VIII STEAM AND POWER CONVERSION SYSTEM

G Auxiliary Feedwater System (PWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Prog

(AMP)

VIII.G.S-25 VIII.G2(S-25)Heat 

exchanger 

components

Stainless steel Closed-cycle 

cooling water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M21A, "Closed 

Water Systems"

VIII.G.SP-79 VIII.G3(S-20)Heat 

exchanger 

components

Stainless steel Lubricating oil Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced corrosion

Chapter XI.M39, "Lubricat

Analysis," and 

Chapter XI.M32, “One-Tim

Inspection” 

VIII.G.SP117VIII.G4(S-26)Heat 

exchanger 

components

Stainless steel Raw water Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to

corrosion

Chapter XI.M20, "Open-C

Cooling Water System"

VIII.G.S-23 VIII.G5(S-23)Heat 

exchanger 

components

Steel Closed-cycle 

cooling water

Loss of material 

due to general, 

pitting, crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed 

Water Systems"

VIII.G.SP-76 VIII.G6(S-17)Heat 

exchanger 

components

Steel Lubricating oil Loss of material 

due to general, 

pitting, crevice, and 

microbiologicallyinfluenced corrosion

Chapter XI.M39, "Lubricat

Analysis," and 

Chapter XI.M32, “One-Tim

Inspection” 
December 2010 VIII G-3 NUREG-1801, Rev. 2

VIII STEAM AND POWER CONVERSION SYSTEM

G Auxiliary Feedwater System (PWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Prog

(AMP)

VIII.G.SP146VIII.G7(S-24)Heat 

exchanger 

components

Steel Raw water Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

corrosion

Chapter XI.M20, "Open-C

Cooling Water System"

VIII.G.SP113Heat 

exchanger 

components 

and tubes

Aluminum Lubricating oil Reduction of heat 

transfer 

due to fouling

Chapter XI.M39, "Lubricat

Analysis," and 

Chapter XI.M32, “One-Tim

Inspection”

VIII.G.SP-99 VIII.G8(SP-53)Heat 

exchanger 

tubes

Copper alloy Lubricating oil Reduction of heat 

transfer 

due to fouling

Chapter XI.M39, "Lubricat

Analysis," and 

Chapter XI.M32, “One-Tim

Inspection” 

VIII.G.SP-56 VIII.G9(SP-56)Heat 

exchanger 

tubes

Copper alloy Raw water Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "Open-C

Cooling Water System"

VIII.G.SP100VIII.G10(SP-58)Heat 

exchanger 

tubes

Copper alloy Treated water Reduction of heat 

transfer 

due to fouling

Chapter XI.M2, “Water Ch

and 

Chapter XI.M32, “One-Tim

Inspection”

VIII.G.SP-41 VIII.G11(SP-41)Heat 

exchanger 

tubes

Stainless steel Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Closed 

Water Systems"

VIII.G.SP102VIII.G12(SP-62)Heat 

exchanger 

tubes

Stainless steel Lubricating oil Reduction of heat 

transfer 

due to fouling

Chapter XI.M39, "Lubricat

Analysis," and 

Chapter XI.M32, “One-Tim

Inspection” 
NUREG-1801, Rev. 2 VIII G-4 December 2010

VIII STEAM AND POWER CONVERSION SYSTEM

G Auxiliary Feedwater System (PWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Prog

(AMP)

VIII.G.S-28 VIII.G13(S-28)Heat 

exchanger 

tubes

Stainless steel Raw water Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "Open-C

Cooling Water System"

VIII.G.SP-64 VIII.G14(SP-64)Heat 

exchanger 

tubes

Steel Closed-cycle 

cooling water

Reduction of heat 

transfer 

due to fouling

Chapter XI.M21A, "Closed 

Water Systems"

VIII.G.SP103VIII.G15(SP-63)Heat 

exchanger 

tubes

Steel Lubricating oil Reduction of heat 

transfer 

due to fouling

Chapter XI.M39, "Lubricat

Analysis," and 

Chapter XI.M32, “One-Tim

Inspection” 

VIII.G.S-27 VIII.G16(S-27)Heat 

exchanger 

tubes

Steel Raw water Reduction of heat 

transfer 

due to fouling

Chapter XI.M20, "Open-C

Cooling Water System"

VIII.G.SP114Piping, piping 

components, 

and piping 

elements

Aluminum Lubricating oil Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M39, "Lubricat

Analysis," and 

Chapter XI.M32, “One-Tim

Inspection”

VIII.G.SP-90 VIII.G17(SP-24)Piping, piping 

components, 

and piping 

elements

Aluminum Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Ch

and 

Chapter XI.M32, “One-Tim

Inspection”

VIII.G.SP-8 VIII.G18(SP-8)Piping, piping 

components, 

and piping 

elements

Copper alloy Closed-cycle 

cooling water

Loss of material 

due to pitting, 

crevice, and 

galvanic corrosion

Chapter XI.M21A, "Closed 

Water Systems"

VIII.G.SP-92 VIII.G19(SP-32)Piping, piping 

components, 

and piping 

elements

Copper alloy Lubricating oil Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M39, "Lubricat

Analysis," and 

Chapter XI.M32, “One-Tim

Inspection” 
December 2010 VIII G-5 NUREG-1801, Rev. 2

VIII STEAM AND POWER CONVERSION SYSTEM

G Auxiliary Feedwater System (PWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Prog

(AMP)

VIII.G.SP-31 VIII.G20(SP-31)Piping, piping 

components, 

and piping 

elements

Copper alloy Raw water Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced corrosion

Chapter XI.M20, "Open-C

Cooling Water System"

VIII.G.SP-29 VIII.G21(SP-29)Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Closed-cycle 

cooling water

Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VIII.G.SP-30 VIII.G22(SP-30)Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Raw water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VIII.G.SP-55 VIII.G23(SP-55)Piping, piping 

components, 

and piping 

elements

Copper alloy 

(>15% Zn or 

>8% Al)

Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VIII.G.SP-28 VIII.G24(SP-28)Piping, piping 

components, 

and piping 

elements

Gray cast iron Raw water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VIII.G.SP-26 VIII.G25(SP-26)Piping, piping 

components, 

and piping 

elements

Gray cast iron Soil Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VIII.G.SP-27 VIII.G26(SP-27)Piping, piping 

components, 

and piping 

elements

Gray cast iron Treated water Loss of material 

due to selective 

leaching

Chapter XI.M33, “Selective 

Leaching”

VIII.G.SP-39 VIII.G27(SP-39)Piping, piping 

components, 

and piping 

elements

Stainless steel Closed-cycle 

cooling water

Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M21A, "Closed 

Water Systems"
NUREG-1801, Rev. 2 VIII G-6 December 2010

VIII STEAM AND POWER CONVERSION SYSTEM

G Auxiliary Feedwater System (PWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Prog

(AMP)

VIII.G.SP-54 VIII.G28(SP-54)Piping, piping 

components, 

and piping 

elements

Stainless steel Closed-cycle 

cooling water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M21A, "Closed 

Water Systems"

VIII.G.SP-95 VIII.G29(SP-38)Piping, piping 

components, 

and piping 

elements

Stainless steel Lubricating oil Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced corrosion

Chapter XI.M39, "Lubricat

Analysis," and 

Chapter XI.M32, “One-Tim

Inspection” 

VIII.G.SP-36 VIII.G30(SP-36)Piping, piping 

components, 

and piping 

elements

Stainless steel Raw water Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced corrosion

Chapter XI.M20, "Open-C

Cooling Water System"

VIII.G.SP-94 VIII.G31(SP-37)Piping, piping 

components, 

and piping 

elements

Stainless steel Soil or concrete Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M41, "Buried a

Underground Piping and T

VIII.G.SP-87 VIII.G32(SP-16)Piping, piping 

components, 

and piping 

elements

Stainless steel Treated water Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M2, “Water Ch

and 

Chapter XI.M32, “One-Tim

Inspection”

VIII.G.SP-88 VIII.G33(SP-17)Piping, piping 

components, 

and piping 

elements

Stainless steel Treated water 

>60°C (>140°F)

Cracking 

due to stress 

corrosion cracking

Chapter XI.M2, “Water Ch

and 

Chapter XI.M32, “One-Tim

Inspection”

VIII.G.SP-60 VIII.G34(SP-60)Piping, piping 

components, 

and piping 

elements

Steel Condensation 

(Internal)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M38, "Inspectio

Internal Surfaces in Misce

Piping and Ducting Compo
December 2010 VIII G-7 NUREG-1801, Rev. 2

VIII STEAM AND POWER CONVERSION SYSTEM

G Auxiliary Feedwater System (PWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Prog

(AMP)

VIII.G.SP-91 VIII.G35(SP-25)Piping, piping 

components, 

and piping 

elements

Steel Lubricating oil Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M39, "Lubricat

Analysis," and 

Chapter XI.M32, “One-Tim

Inspection” 

VIII.G.S-11 VIII.G37(S-11)Piping, piping 

components, 

and piping 

elements

Steel Treated water Cumulative fatigue 

damage 

due to fatigue

Fatigue is a time-limited ag

analysis (TLAA) to be eva

for the period of extended 

operation. See the SRP, S

4.3 “Metal Fatigue,” for ac

methods for meeting the 

requirements of 10 CFR 

54.21(c)(1).

VIII.G.SP-74 VIII.G38(S-10)Piping, piping 

components, 

and piping 

elements

Steel Treated water Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M2, “Water Ch

and 

Chapter XI.M32, “One-Tim

Inspection”

VIII.G.S-16 VIII.G39(S-16)Piping, piping 

components, 

and piping 

elements

Steel Treated water Wall thinning 

due to flowaccelerated 

corrosion

Chapter XI.M17, “FlowAccelerated Corrosion”

VIII.G.SP118Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless steel Air – outdoor Cracking 

due to stress 

corrosion cracking

Chapter XI.M36, "External 

Surfaces Monitoring of Me

Components"

VIII.G.SP127Piping, piping 

components, 

and piping 

elements; 

tanks

Stainless steel Air – outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External 

Surfaces Monitoring of Me

Components"
NUREG-1801, Rev. 2 VIII G-8 December 2010

VIII STEAM AND POWER CONVERSION SYSTEM

G Auxiliary Feedwater System (PWR)

Item Link 

Structure 

and/or 

Component 

Material Environment Aging Effect/ 

Mechanism

Aging Management Prog

(AMP)

VIII.G.SP145VIII.G1(S-01)Piping, piping 

components, 

and piping 

elements; 

tanks

Steel (with 

coating or 

wrapping)

Soil or concrete Loss of material 

due to general, 

pitting, crevice, and 

microbiologicallyinfluenced corrosion

Chapter XI.M41, "Buried a

Underground Piping and T

VIII.G.SP136VIII.G36(S-12)Steel Piping, 

piping 

components, 

and piping 

elements 

exposed to 

Raw water

Steel Raw water Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologicallyinfluenced 

corrosion; fouling 

that leads to 

corrosion

Chapter XI.M38, "Inspectio

Internal Surfaces in Misce

Piping and Ducting Compo

VIII.G.S-31 VIII.G40(S-31)Tanks Steel Air – outdoor 

(External)

Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M29, “Abovegr

Metallic Tanks”

VIII.G.SP116Tanks Steel Soil or Concrete Loss of material 

due to general, 

pitting, and crevice 

corrosion

Chapter XI.M29, “Abovegr

Metallic Tanks”

VIII.G.SP-75 VIII.G41(S-13)Tanks Steel; stainless 

steel

Treated water Loss of material 

due to general 

(steel only), pitting, 

and crevice 

corrosion

Chapter XI.M2, “Water Ch

and 

Chapter XI.M32, “One-Tim

Inspection”
 

December 2010 VIII H-1 NUREG-1801, Rev. 2

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. 2 VIII H-2 December 2010

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 

VIII.H.SP149Bolting Copper alloy Any environment Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integri

VIII.H.SP150Bolting Nickel alloy Any environment Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integri

VIII.H.SP143Bolting Stainless 

steel

Soil or concrete Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M41, "Buried and 

Underground Piping and Tanks"

VIII.H.SP144Bolting Stainless 

steel

Soil Loss of preload Chapter XI.M18, "Bolting Integri

VIII.H.S-40 VIII.H-2(S40)Bolting Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid Co

VIII.H.SP141Bolting Steel Soil or concrete Loss of material

due to general, 

pitting and crevice 

corrosion

Chapter XI.M41, "Buried and 

Underground Piping and Tanks"

VIII.H.SP142Bolting Steel Soil Loss of preload Chapter XI.M18, "Bolting Integri

VIII.H.SP-82 VIII.H-1(S32)Bolting Steel; 

stainless 

steel

Air – outdoor 

(External)

Loss of material 

due to general 

(steel only), 

pitting, and crevice 

corrosion

Chapter XI.M18, "Bolting Integri
December 2010 VIII H-3 NUREG-1801, Rev. 2

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 

VIII.H.SP151Bolting Steel; 

stainless 

steel

Air – outdoor 

(External)

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integri

VIII.H.S-03 VIII.H-3(S03)Closure 

bolting

Highstrength 

steel

Air with steam or 

water leakage

Cracking 

due to cyclic 

loading, stress 

corrosion cracking

Chapter XI.M18, "Bolting Integri

VIII.H.S-02 VIII.H-6(S02)Closure 

bolting

Steel Air with steam or 

water leakage

Loss of material 

due to general 

corrosion

Chapter XI.M18, "Bolting Integri

VIII.H.SP-84 VIII.H-4(S34)Closure 

bolting

Steel; 

stainless 

steel

Air – indoor, 

uncontrolled 

(External) 

Loss of material 

due to general 

(steel only), 

pitting, and crevice 

corrosion

Chapter XI.M18, "Bolting Integri

VIII.H.SP-83 VIII.H-5(S33)Closure 

bolting

Steel; 

stainless 

steel

Air – indoor, 

uncontrolled 

(External)

Loss of preload 

due to thermal

effects, gasket 

creep, and selfloosening

Chapter XI.M18, "Bolting Integri

VIII.H.S-29 VIII.H-7(S29)External 

surfaces

Steel Air – indoor, 

uncontrolled 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External Surfa

Monitoring of Mechanical Comp

VIII.H.S-41 VIII.H-8(S41)External 

surfaces

Steel Air – outdoor 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External Surfa

Monitoring of Mechanical Comp

VIII.H.S-30 VIII.H-9(S30)External 

surfaces

Steel Air with borated 

water leakage

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, “Boric Acid Co
NUREG-1801, Rev. 2 VIII H-4 December 2010

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 

VIII.H.S-42 VIII.H10(S-42)External 

surfaces

Steel Condensation 

(External)

Loss of material 

due to general 

corrosion

Chapter XI.M36, "External Surfa

Monitoring of Mechanical Comp

VIII.H.SP147Piping, piping 

components, 

and piping 

elements

Aluminum Air - outdoor Loss of material 

due to pitting and 

crevice corrosion

Chapter XI.M36, "External Surfa

Monitoring of Mechanical Comp

VIII.H.SP161Underground 

piping, piping 

components, 

and piping 

elements

Steel; 

stainless 

s eel; t

copper alloy; 

aluminum

Air-indoor 

uncontrolled or 

condensation 

(External)

Loss of material 

due to general 

(steel only), pitting 

and crevice 

corrosion

Chapter XI.M41, “Buried and 

Underground Piping and Tanks”
NUREG-1801, Rev. 2 VIII I-1 December 2010

I. COMMON MISCELLANEOUS MATERIAL/ENVIRONMENT COMBINATIONS

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 period of extended 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.G2 for details). 
December 2010 VIII I-2 NUREG-1801, Rev. 2

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 Progra

(AMP)

VIII.I.SP-33 VIII.I4(SP-33)Piping 

elements

Glass Air None None 

VIII.I.SP-9 VIII.I5(SP-9)Piping 

elements

Glass Air – indoor, 

uncontrolled 

(External)

None None 

VIII.I.SP-108 Piping 

elements

Glass Air – outdoor None None 

VIII.I.SP-67 Piping 

elements

Glass Air with borated 

water leakage

None None 

VIII.I.SP-70 Piping 

elements

Glass Closed-cycle 

cooling water

None None 

VIII.I.SP-68 Piping 

elements

Glass Condensation None None 

VIII.I.SP-111 Piping 

elements

Glass Condensation 

(Internal/External)

None None 

VIII.I.SP-69 Piping 

elements

Glass Gas None None 

VIII.I.SP-10 VIII.I6(SP-10)Piping 

elements

Glass Lubricating oil None None 
NUREG-1801, Rev. 2 VIII I-3 December 2010

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 Progra

(AMP)

VIII.I.SP-34 VIII.I7(SP-34)Piping 

elements

Glass Raw water None None 

VIII.I.SP-35 VIII.I8(SP-35)Piping 

elements

Glass Treated water None None 

VIII.I.SP-93 Piping, piping 

components, 

and piping 

elements

Aluminum Air – indoor, 

uncontrolled 

(Internal/External)

None None 

VIII.I.SP-23 VIII.I1(SP-23)Piping, piping 

components, 

and piping 

elements

Aluminum Gas None None 

VIII.I.SP-6 VIII.I2(SP-6)Piping, piping 

components, 

and piping 

elements

Copper alloy Air – indoor, 

uncontrolled 

(External)

None None 

VIII.I.SP-5 VIII.I3(SP-5)Piping, piping 

components, 

and piping 

elements

Copper alloy Gas None None 

VIII.I.SP-104 Piping, piping 

components, 

and piping 

elements

Copper alloy 

(≤15% Zn 

and ≤8% Al)

Air with borated 

water leakage

None None 
December 2010 VIII I-4 NUREG-1801, Rev. 2

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 Progra

(AMP)

VIII.I.SP-11 VIII.I9(SP-11)Piping, piping 

components, 

and piping 

elements

Nickel alloy Air – indoor, 

uncontrolled 

(External)

None None 

VIII.I.SP-148 Piping, piping 

components, 

and piping 

elements

Nickel alloy Air with borated 

water leakage

None None 

VIII.I.SP-152 Piping, piping 

components, 

and piping 

elements

PVC Air – indoor, 

uncontrolled

None None 

VIII.I.SP-153 Piping, piping 

components, 

and piping 

elements

PVC Condensation 

(Internal)

None None 

VIII.I.SP-12 VIII.I10(SP-12)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Air – indoor, 

uncontrolled 

(External)

None None 

VIII.I.SP-86 Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Air – indoor, 

uncontrolled 

(Internal)

None None 

VIII.I.SP-13 VIII.I11(SP-13)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Concrete None None 
NUREG-1801, Rev. 2 VIII I-5 December 2010

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 Progra

(AMP)

VIII.I.SP-15 VIII.I12(SP-15)Piping, piping 

components, 

and piping 

elements

Stainless 

steel

Gas None None 

VIII.I.SP-1 VIII.I13(SP-1)Piping, piping 

components, 

and piping 

elements

Steel Air – indoor 

controlled 

(External)

None None 

VIII.I.SP-154 VIII.I14(SP-2)Piping, piping 

components, 

and piping 

elements 

Steel Concrete None None, provided:

1) attributes of the concrete a

consistent with ACI 318 or AC

(low water-to-cement ratio, lo

permeability, and adequate a

entrainment) as cited in NUR

1557, and 

2) plant OE indicates no degr

of the concrete

VIII.I.SP-4 VIII.I15(SP-4)Piping, piping 

components, 

and piping 

elements

Steel Gas None None 

December 2010 IX-i NUREG-1801, Rev. 2

CHAPTER IX

SELECTED DEFINITIONS AND USE OF TERMS FOR

STRUCTURES, COMPONENTS, MATERIALS, 

ENVIRONMENTS, AGING EFFECTS, AND AGING 

MECHANISMS 

December 2010 IX-iii NUREG-1801, Rev. 2

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. Significant Aging Mechanisms

G. References

December 2010 IX-1 NUREG-1801, Rev. 2

A. Introduction

The format and content of the aging management review (AMR) tables presented here (GALL 

Report, Rev. 2), have been revised to enhance the report’s applicability to future plant license 

renewal applications. Several types of changes are incorporated in this revision to achieve the 

objective. One of these changes is to incorporate additional material, environment, aging effect 

and program (MEAP) combinations established by precedents based on a strong technical 

justification from earlier license renewal applications (LRAs) and the corresponding NRC safety 

evaluation reports (SERs). 

The NRC has added several new definitions and clarified some of those that were in the GALL 

Report , Rev.1. 

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.
NUREG-1801, Rev. 2 IX-2 December 2010

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 structural bolting, closure bolting, 

or all other 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 or closed. Closure bolting 

in high-pressure or high-temperature systems is 

defined as that in which the pressure exceeds 275 

psi or 200o

F (93oC). Closure bolting is used to join 

pressure boundaries or where a mechanical seal is 

required.

Ducting and components Ducting and components include heating, ventilation, 

and air-conditioning (HVAC) components. Examples 

include ductwork, ductwork fittings, access doors, 

equipment frames and housing, housing supports, 

including housings for valves, dampers (including 

louvers, gravity, and fire dampers), and ventilation 

fans (including exhaust fans, intake fans, and purge 

fans). In some cases, this includes HVAC closure 

bolts or HVAC 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 (e.g., 

emergency core cooling system, containment spray 

system, and containment isolation system, and

refueling water storage tank, etc.) can include 

encapsulation vessels, piping, and valves. 

“Existing programs” 

components

Per EPRI MRP-227 [Ref. 1] guidance on inspection 

and evaluation, PWR vessel internals (GALL AMP 

XI.M16A) were assigned to one of the following four 

groups: Primary, Expansion, Existing Programs, and 

No Additional Measures. 

Existing program components are those PWR 

internals that are susceptible to the effects of at least 

one of the aging mechanisms identified in MRP-227 

and for which generic and plant-specific existing 

AMP elements are capable of managing those 

effects.

“Expansion” components Per EPRI MRP-227 guidance on inspection and 

evaluation, PWR vessel internals (GALL AMP 

XI.M16A) were assigned to one of the following four 
December 2010 IX-3 NUREG-1801, Rev. 2

IX.B Selected Definitions & Use of Terms for Describing and Standardizing

STRUCTURES AND COMPONENTS

Term Definition as used in this document

groups: Primary, Expansion, Existing Programs, and 

No Additional Measures. 

“Expansion” components are those PWR internals 

that are highly or moderately susceptible to the 

effects of at least one of the aging mechanisms 

addressed by MRP-227, but for which functionality 

assessment has shown a degree of tolerance to 

those effects. (See MRP-227, Section 3.3)

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.

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 components 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 

components, heat exchanger internals, including 

tubesheets and fins, contribute to heat transfer and 

may be affected by reduction of heat transfer due to 

fouling [Ref. 2]. The inclusion of components such as 

tubesheets is dependent on manufacturer 

specifications.

High voltage insulators An insulator is an insulating material in a 

configuration designed to physically support a 

conductor and separate the conductor electrically 

from other conductors or objects. The high voltage 

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 bus” (MEB) is the term used in 

electrical and industry standards (IEEE and ANSI) 

for electrical buses installed on electrically-insulated 

supports constructed with all phase conductors 

enclosed in a metal enclosure. 
NUREG-1801, Rev. 2 IX-4 December 2010

IX.B Selected Definitions & Use of Terms for Describing and Standardizing

STRUCTURES AND COMPONENTS

Term Definition as used in this document

“No Additional Measures” 

components

Per EPRI MRP-227 guidance on inspection and 

evaluation, PWR vessel internals (GALL AMP 

XI.M16A) were assigned to one of the following four 

groups: Primary, Expansion, Existing Programs, and 

No Additional Measures. Additional components 

were placed in the “No Additional Measures,” group 

as a result of the Failure Mode, Effects, and 

Criticality Analysis and the functionality assessment.

Note: Components with no additional measures are 

not uniquely identified in GALL tables (see AMR

Items IV.B2.RP-265, IV.B2.RP-267, IV.B3.RP-306, 

IV.B3.RP-307, IV.B4.RP-236, and IV.B4.RP-237.

Components with no additional measures are 

defined in Section 3.3.1 of MRP-227, “Materials 

Reliability Program: Pressurized Water Reactor 

Internals Inspection and Evaluation Guidelines.”

Piping, piping components, 

piping elements, and tanks

This general category includes features of the piping 

system within the scope of license renewal. 

Examples include piping, fittings, tubing, flow 

elements/indicators, demineralizers, nozzles, 

orifices, flex hoses, pump casings and bowls, safe 

ends, sight glasses, spray heads, strainers, 

thermowells, and valve bodies and bonnets. For 

reactor coolant pressure boundary components in 

Chapter IV that are subject to cumulative fatigue 

damage, this category also can include flanges, 

nozzles and safe ends, penetrations, instrument 

connections, vessel heads, shells, welds, weld inlays 

and weld overlays, stub tubes, and miscellaneous 

Class 1 components (e.g., pressure housings, etc.). 

As used in AMP XI.M41, buried piping and tanks are 

in direct contact with soil or concrete (e.g., a wall 

penetration). Underground piping and tanks are 

below grade, but are contained within a tunnel or 

vault such that they are in contact with air and are 

located where access for inspection is restricted.
December 2010 IX-5 NUREG-1801, Rev. 2

IX.B Selected Definitions & Use of Terms for Describing and Standardizing

STRUCTURES AND COMPONENTS

Term Definition as used in this document

Piping elements The category of “piping elements” is a sub-category 

of piping, piping components, and piping elements 

that in GALL Report, Rev. 2 applies only to 

components made of glass (e.g., sight glasses and 

level indicators, etc.). In the GALL Report, Chapters 

V, VII, and VIII, piping elements are thus called out 

separately. 

Pressure housing The term “pressure housing” only refers to pressure 

housing for the control rod drive (CRD) head 

penetration (it is only of concern in Section A2 for 

PWR reactor vessels).

“Primary” components Per EPRI MRP-227 guidance on inspection and 

evaluation, PWR vessel internals (GALL AMP 

XI.M16A) were assigned to one of the following four 

groups: Primary, Expansion, Existing Programs, and 

No Additional Measures. 

Primary components are those PWR internals that 

are highly susceptible to the effects of at least one of 

the aging mechanisms addressed by MRP-227. The 

Primary group also includes components which have 

shown a degree of tolerance to a specific aging 

degradation effect, but for which no highly 

susceptible component exists or for which no highly 

susceptible component is accessible.

Reactor coolant pressure 

boundary components

Reactor coolant pressure boundary components 

include, but are not limited to, piping, piping 

components, piping elements, flanges, nozzles, safe 

ends, pressurizer vessel shell heads and welds, 

heater sheaths and sleeves, penetrations, and 

thermal sleeves.

Seals, gaskets, and moisture 

barriers (caulking, flashing, 

and other sealants)

This category includes elastomer components used 

as sealants or gaskets.

Steel elements: liner; liner 

anchors; integral attachments

This category includes steel liners used in 

suppression pools or spent fuel pools.

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. 2 IX-6 December 2010

IX.B Selected Definitions & Use of Terms for Describing and Standardizing

STRUCTURES AND COMPONENTS

Term Definition as used in this document

Tanks Tanks are large reservoirs used as hold-up volumes 

for liquids or gases. Tanks may have an internal 

liquid and/or vapor space and may be partially buried 

or in close proximity to soils or concrete. Tanks are 

treated separately from piping due to their potential 

need for different aging management programs 

(AMP). One example is GALL AMP XI.M29, 

“Aboveground Metallic Tanks,” for tanks partially 

buried or in contact with soil or concrete that 

experience general corrosion as the aging effect at 

the soil or concrete interface. 

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 This category includes non-steel supports used for 

supporting components prone to vibration.
December 2010 IX-7 NUREG-1801, Rev. 2

C. Materials

The following table defines many generalized materials used in the preceding GALL AMR tables 

in Chapters II through VIII of GALL Report, Rev. 2. 

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 in spent fuel 

storage racks. Degradation of Boraflex panels under gamma 

radiation can lead to a loss of their ability to absorb neutrons 

in spent fuel storage pools. The aging management program 

for Boraflex is found in GALL AMP XI.M22, “Boraflex 

Monitoring.”

Boral®, boron steel Boron steel is steel with a boron content ranging from one to 

several percent. Boron steel absorbs neutrons and is often 

used as a control rod to help control the neutron flux. 

Boral® is a cermet consisting of a core of aluminum and 

boron carbide powder sandwiched between sheets of 

aluminum. Boral refers to patented Aluminum-Boron 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.

Concrete and 

cementitious material

When used generally, this category of concrete applies to 

concrete in many different configurations (block, cylindrical, 

etc.) and prestressed or reinforced concrete. Cementitious 

material can be defined as any material having cementing 

properties, which contributes to the formation of hydrated 

calcium silicate compounds. When mixing concrete, the 

following have cementitious properties: Portland cement, 

blended hydraulic cement, fly ash, ground granulated blast 

furnace slag, silica fume, calcined clay, metakaolin, calcined 

shale, and rice husk ash. This category may include 

asbestos cement. 
NUREG-1801, Rev. 2 IX-8 December 2010

IX.C Selected Definitions & Use of Terms for Describing and Standardizing

MATERIALS

Term Definition as used in this document

Copper alloy (≤15% Zn 

and ≤8% Al)

This category applies to those copper alloys whose critical 

alloying elements are less than the thresholds that keep the 

alloy from being susceptible to aging effects. For example, 

copper, copper nickel, brass, bronze ≤15% zinc (Zn), and 

aluminum bronze ≤8% aluminum (Al) 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. 

Copper alloy (>15% Zn 

or >8% Al)

This category applies to those copper alloys whose critical 

alloying elements are above the thresholds that make them 

susceptible to aging effects. Copper-zinc alloys >15% zinc 

are susceptible to stress corrosion cracking (SCC), selective 

leaching (except for inhibited brass), and pitting and crevice 

corrosion. Additional copper alloys, such as aluminum 

bronze > 8% aluminum, also may be susceptible to SCC or 

leaching. The elements that are most commonly alloyed with 

copper are zinc (forming brass), tin (forming bronze), nickel, 

silicon, aluminum (forming aluminum-bronze), cadmium, and 

beryllium. Additional copper alloys may be susceptible to 

these aging effects if they fall above the threshold for the 

critical alloying element. [Ref. 3]

Elastomers Elastomers are flexible 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 or 

35°C), and additional aging factors (e.g., exposure to ozone, 

oxidation, and radiation, etc.). [Ref. 4]

Galvanized steel Galvanized steel is steel coated with zinc, usually by 

immersion or electrodeposition. The zinc coating protects the 

underlying steel because the corrosion rate of the zinc 

coating in dry, clean air is very low. In the presence of 

moisture, galvanized steel is classified under the category 

“Steel.”

Glass This category includes any glass material. 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-hardened,

and, AISI A10, which is air-hardened), have excellent nonseizing properties. The graphite particles provide selflubricity and hold applied lubricants.
December 2010 IX-9 NUREG-1801, Rev. 2

IX.C Selected Definitions & Use of Terms for Describing and Standardizing

MATERIALS

Term Definition as used in this document

Gray cast iron Gray cast iron is an iron alloy made by adding larger 

amounts of carbon to molten iron than would be used to 

make steel. Most steel has less than about 1.2% by weight 

carbon, while cast irons typically have between 2.5 to 4%. 

Gray cast iron contains flat graphite flakes that reduce its 

strength and form cracks, inducing 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. Gray 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. In some 

environments, gray cast iron is categorized with the group 

“Steel.”

Insulation materials 

(e.g., bakelite, phenolic 

melamine or ceramic, 

molded polycarbonate)

Insulation materials in this category are bakelite, phenolic 

melamine or ceramic, molded polycarbonate, etc. used in 

electrical fuse holders.

Low-alloy steel, yield 

strength >150 ksi

Low-alloy steel includes AISI steels 4140, 4142, 4145, 

4140H, 4142H, and 4145H (UNS#: G41400, G41420, 

G41450, H41400, H41420, H41450). 

Low-alloy steel bolting material, SA 193 Gr. B7, is a ferritic, 

low-alloy steel for high-temperature service. High-strength 

low-alloy (Fe-Cr-Ni-Mo) steel bolting materials have a 

maximum tensile strength of <1172 MPa (<170 ksi). They 

may be subject to stress corrosion cracking if the actual 

measured yield strength, Sy, ≥ 150 ksi (1034 MPa). Bolting 

fabricated from high-strength (actual measured yield 

strength, Sy, ≥ 150 ksi or 1034 MPa) low-alloy steel, SA 193 

Gr. B7, is susceptible to stress corrosion cracking. 

Examples of high-strength alloy steels that comprise this 

category include SA540-Gr. B23/24, SA193-Gr. B8, and 

Grade L43 (AISI4340). 

Lubrite® Lubrite® refers to a patented technology in which the bearing 

substrate (bronze is commonly used, but in unusual 

environments can range from stainless steel and nodulariron to tool-steel) is fastened to lubricant. Lubrite® is often 

defined as bronze attached to ASTM B22, alloy 905, with 

G10 lubricant. 

Even though Lubrite® bearings are characterized as

maintenance-free because of the differences in installation, 
NUREG-1801, Rev. 2 IX-10 December 2010

IX.C Selected Definitions & Use of Terms for Describing and Standardizing

MATERIALS

Term Definition as used in this document

fineness of the surfaces, and lubricant characteristics, they 

can experience mechanical wear and fretting. 

Bearings generally have not shown adverse conditions 

related to the use of Lubrite®. The unique environment and 

precise installation tolerances required for installing the 

bearings require bearing-specific examinations. The vendor’s 

(Lubrite® Technologies) literature shows ten lubricant types 

used in the bearings, ranging from G1 (General Duty) to AE7 

(temperature- and radiation-tested) lubricants. The type of 

lubricant used depends on the plant-specific requirements. 

Careful installation and clearing out any obstructions during 

installation ensures that the required tolerances of the 

bearings are met and reduces the likelihood of functional 

problems during challenging loading conditions (such as 

design basis accident [DBA] or safe shutdown earthquake 

[SSE]). The associated aging effects could include 

malfunctioning, distortion, dirt accumulation, and fatigue 

under vibratory and cyclic thermal loads. The potential aging 

effects could be managed by incorporating its periodic 

examination in ASME Section XI, Subsection IWF (AMP 

XI.S3) or in Structures Monitoring (AMP XI.S6). 

Malleable iron The term “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.”

Nickel alloys Nickel alloys are nickel-chromium-iron (molybdenum) alloys 

and include the Alloys 600 and 690. Examples of nickel 

alloys include Alloy 182, 600, and 690, Gr. 688 (X-750), 

Inconel 182, Inconel 82, NiCrFe, SB-166, -167, and -168, 

and X-750. [Ref. 5]

Polymer This category generally includes flexible polymeric materials 

(such as rubber) and rigid polymers (like PVC).

As used in GALL Report, Rev. 2 AMR Items VI.A.LP-33, 

VI.A.LP-34, and VI.A.LP-35, polymers used in electrical 

applications include EPR (ethylene-propylene rubber), SR 

(silicone rubber), EPDM (ethylene propylene diene 

monomer), and XLPE (crosslinked polyethylene). XLPE is a 

cross-linked polyethylene thermoplastic resin, such as 

polyethylene and polyethylene copolymers. EPR and EPDM 

are ethylene-propylene rubbers in the category of 

thermosetting elastomers.
December 2010 IX-11 NUREG-1801, Rev. 2

IX.C Selected Definitions & Use of Terms for Describing and Standardizing

MATERIALS

Term Definition as used in this document

Porcelain Hard-quality porcelain is used as an insulator for supporting 

high-voltage electrical insulators. Porcelain is a hard, finegrained ceramic that consists of kaolin, quartz, and feldspar 

fired at high temperatures. 

SA508-Cl 2 forgings clad 

with stainless steel using 

a high-heat-input 

welding process

This category consists of quenched and tempered vacuumtreated carbon and alloy steel forgings for pressure vessels. 

Stainless steel Products grouped under the term “stainless steel” include 

wrought or forged austenitic, ferritic, martensitic, 

precipitation-hardened (PH), or duplex stainless steel (Cr 

content >11%). 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 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 

an AMR line-item. 

Steel with stainless steel cladding also may 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 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, and 

Types 304, 304NG, 308, 308L, 309, 309L, 316, 347, 403, 

and 416. Examples of CASS designations include CF-3, -8, -

3M, and -8M. [Ref. 6, 7]

Steel In some environments, 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 under the broad 

term “steel.” Note that this does not include stainless steel, 

which has its own category. However, gray cast iron also is 

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 
NUREG-1801, Rev. 2 IX-12 December 2010

IX.C Selected Definitions & Use of Terms for Describing and Standardizing

MATERIALS

Term Definition as used in this document

materials are specifically identified. Galvanized steel (zinccoated carbon steel) is also included in the category of 

“steel” when exposed to moisture. Malleable iron is 

specifically called out in the phrase “Porcelain, Malleable 

iron, aluminum, galvanized steel, cement,” which is used to 

define the high voltage insulators in GALL Chapter VI.

Examples of steel designations included in this category are

ASTM A36, ASTM A285, 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. [Ref. 6, 7]

Superaustenitic stainless 

steel

Superaustenitic stainless steels have the same structure as 

the common austenitic alloys, but they have enhanced levels 

of elements such as chromium, nickel, molybdenum, copper, 

and nitrogen, which give them superior strength and 

corrosion resistance. Compared to conventional austenitic 

stainless steels, superaustenitic materials have a superior 

resistance to pitting and crevice corrosion in environments 

containing halides. Several NPPs have installed 

superaustenitic stainless steel (AL-6XN) buried piping. 

Titanium The category titanium includes unalloyed titanium (ASTM 

grades 1-4) and various related alloys (ASTM grades 5, 7. 9, 

and 12). The corrosion resistance of titanium is a result of 

the formation of a continuous, stable, highly adherent 

protective oxide layer on the metal surface. 

Titanium and titanium alloys may be susceptible to crevice 

corrosion in saltwater environments at elevated temperatures 

(>160o

F). Titanium Grades 5 and 12 are resistant to crevice 

corrosion in seawater at temperatures as high as 500o

F. 

Stress corrosion cracking of titanium and its alloys is 

considered applicable in sea water or brackish raw water 

systems if the titanium alloy contains more than 5% 

aluminum or more than 0.20% oxygen or any amount of tin. 

ASTM Grades 1, 2, 7, 11, or 12 are not susceptible to stress 

corrosion cracking in seawater or brackish raw water [Ref. 8]. 

Wood Wood piles or sheeting exposed to flowing or standing water 

is subject to loss of material or changes in material 

properties due to weathering, chemical degradation, insect 

infestation, repeated wetting and drying, or fungal decay.

Zircaloy-4 Zircaloy-4, (Zry-4), is a member in the group of highzirconium (Zr) alloys. Such zircaloys are used in nuclear 
December 2010 IX-13 NUREG-1801, Rev. 2

IX.C Selected Definitions & Use of Terms for Describing and Standardizing

MATERIALS

Term Definition as used in this document

technology, as Zr has very low absorption cross-section of 

thermal neutrons. In the GALL Report, Zry-4 is referenced in 

AMR Item IV.B3.RP-357 for incore instrumentation thimble 

tubes. Zry-4 consists of 98.23 weight % zirconium with 

1.45% tin, 0.21% iron, 0.1% chromium, and 0.01% hafnium. 
NUREG-1801, Rev. 2 IX-14 December 2010

D. Environments

The following table defines many of the standardized environments used in the preceding GALL 

AMR tables in Chapters II through VIII of the GALL Report, Rev. 2. 

The usage of temperature thresholds for describing aging effects are continued as in the GALL 

Report, Rev. 1. 

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 [Ref. 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 75o

C (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 [Ref. 8, 9]. 

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. 10]. 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 AMP XI.M12, "Thermal Aging 

Embrittlement of Cast Austenitic Stainless Steel (CASS)," with the exception of niobiumcontaining steels, which require evaluation on a case-by-case basis.
December 2010 IX-15 NUREG-1801, Rev. 2

IX.D Selected Definitions & Use of Terms for Describing and Standardizing

ENVIRONMENTS 

Term Definition as used in this document

Adverse localized 

environment 

An adverse localized environment is an environment 

limited to the immediate vicinity of a component that is 

hostile to the component material, thereby leading to 

potential aging effects. As used in GALL, the conductor 

insulation used for electrical cables in instrumentation 

circuits can be subjected to an adverse localized 

environment. As represented by a specific GALL AMR

Item, an adverse localized environment can be due to any 

of the following: (1) exposure to significant moisture (LP35), (2) heat, radiation, or moisture (L-01 or LP-34), or (3) 

heat, radiation, moisture, or voltage (L-05). 

Aggressive environment 

(steel in concrete)

This environment affects steel embedded in concrete with 

a pH <5.5 or a chloride concentration >500 ppm or sulfate 

> 1500 ppm. [Ref. 11]

Air – indoor controlled This environment is one to which the specified internal or

external surface of the component or structure is exposed; 

a humidity-controlled (i.e., air conditioned) environment. 

For electrical purposes, control must be sufficient to 

eliminate the cited aging effects of contamination and 

oxidation without affecting the resistance.

Air – indoor uncontrolled Uncontrolled indoor air is associated with systems with 

temperatures higher than the dew point (i.e., condensation 

can occur, but only rarely; equipment surfaces are 

normally dry). 

Air – indoor uncontrolled 

>35°C (>95°F) 

(Internal/External)

Uncontrolled indoor air >35°C (>95°F) is above a thermal 

stress threshold for elastomers (i.e., <95°F). It is an 

environment to which the internal or external surface of the 

component or structure can be exposed. If the ambient 

temperature is maintained <95°F, any resultant thermal 

aging of organic materials can be considered as 

insignificant over the 60-yr period of extended operation. 

[Ref. 3] However, elastomers can be subjected 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 (if present). 

A component is considered susceptible to a wetted 

environment when it is submerged, has the potential to 

collect water, or is subject to external condensation.
NUREG-1801, Rev. 2 IX-16 December 2010

IX.D Selected Definitions & Use of Terms for Describing and Standardizing

ENVIRONMENTS 

Term Definition as used in this document

Air with borated water 

leakage

Air and untreated borated water leakage on indoor or 

outdoor systems with temperatures either 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 (germane to PWRs). 

Air with leaking 

secondary-side water 

and/or steam

This environment applies to steel components in the 

pressure boundary and structural parts of the oncethrough steam generator that may be exposed to air with 

leaking secondary-side water and/or steam.

Air with metal 

temperature up to 288°C 

(550°F)

This environment is synonymous with the more commonlyused 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 (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 its dew point well 

below the system operating temperature. Within piping, 

unless otherwise specified, this encompasses either 

internal or external.

Air, moist Air with enough moisture to facilitate the loss of material in 

steel caused by general, pitting, and crevice corrosion. 

Moist air in the absence of condensation also is potentially 

aggressive (e.g., under conditions where hygroscopic 

surface contaminants are present, etc.).

Any This could be any indoor or outdoor environment where 

the aging effects are not dependent on environmental 

conditions.

Buried and underground As referenced in AMP XI.M41, “Buried and Underground 

Piping and Tanks,” buried piping and tanks are those in 

direct contact with soil or concrete (e.g., a wall 

penetration).

Underground piping and tanks are below grade, but are 

contained within a tunnel or vault such that they are in 

contact with air and are located where access for 

inspection is restricted.
December 2010 IX-17 NUREG-1801, Rev. 2

IX.D Selected Definitions & Use of Terms for Describing and Standardizing

ENVIRONMENTS 

Term Definition as used in this document

Closed-cycle cooling 

water

Treated water subject to the closed-cycle cooling water 

chemistry program is included in this environment. Closedcycle cooling water >60°C (>140°F) makes the SCC of 

stainless steel possible. Examples of descriptors that 

comprise this category can include:

• chemically-treated, borated water, and treated 

component cooling water

• demineralized water on one side and closed-cycle 

cooling water (treated water) on the other side

• chemically treated borated water on the tube side and 

closed-cycle cooling water on the shell side.

Concrete This environment consists of components embedded in 

concrete.

Condensation 

(internal/external)

Condensation on the surfaces of systems at temperatures 

below the dew point is considered “raw water” due to the 

potential for internal or external surface contamination. 

Under certain circumstances, the former terms “moist air” 

or “warm moist air” are subsumed by the definition of 

“condensation,” which describes an environment where 

there is enough moisture for corrosion to occur.

Containment 

environment (inert) 

A drywell environment is made inert with nitrogen to 

render the primary containment atmosphere nonflammable by maintaining the oxygen content below 4% by 

volume during normal operation.

Diesel exhaust This environment consists of 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 used for combustion engines 

may be contaminated with water, which may promote 

additional aging effects. 
NUREG-1801, Rev. 2 IX-18 December 2010

IX.D Selected Definitions & Use of Terms for Describing and Standardizing

ENVIRONMENTS 

Term Definition as used in this document

Gas Internal gas environments include dry air or inert, nonreactive gases. This generic term is used only with 

“Common Miscellaneous Material/Environment,” where 

aging effects are not expected to degrade the ability of the 

structure or component to perform its intended function for 

the period of extended operation. 

The term “gas” is not meant to comprehensively include all

gases in the fire suppression system. The GALL AMP 

XI.M26, “Fire Protection,” is used for the periodic 

inspection and testing of the halon/carbon dioxide fire 

suppression system.

Ground water/soil Ground water is subsurface water that can be detected in 

wells, tunnels, or drainage galleries, or that flows naturally 

to the earth's surface via seeps or springs. Soil is a 

mixture of organic and inorganic materials produced by the 

weathering of rock and clay minerals or the decomposition 

of vegetation. Voids containing air and moisture can 

occupy 30 to 60 percent [Ref.12] of the soil volume. 

Concrete subjected to a ground water/soil environment

can be vulnerable to an increase in porosity and 

permeability, cracking, loss of material (spalling, scaling)/, 

or aggressive chemical attack. Other materials with 

prolonged exposures to ground water or moist soils are 

subject to the same aging effects as those systems and 

components exposed to raw water.

Lubricating oil Lubricating oils are low-to-medium viscosity hydrocarbons 

that can contain contaminants and/or moisture. This 

definition also functionally encompasses hydraulic oil 

(non-water based). These oils are used for bearing, gear, 

and engine lubrication. The GALL AMP XI.M39, 

Lubricating Oil Analysis, addresses this environment. 

Piping, piping components, and piping elements, whether 

copper, stainless steel, or steel, when exposed to 

lubricating oil with some water, will have limited 

susceptibility to aging degradation due to general or 

localized corrosion. 

Raw water Raw water consists of untreated surface or ground water, 

whether fresh, brackish, or saline in nature. This includes 

water for use in open-cycle cooling water systems and 

may include potable water, water that is used for drinking 

or other personal use. See also “condensation.”
December 2010 IX-19 NUREG-1801, Rev. 2

IX.D Selected Definitions & Use of Terms for Describing and Standardizing

ENVIRONMENTS 

Term Definition as used in this document

Reactor coolant Reactor coolant is treated water in the reactor coolant 

system and connected systems at or near full operating 

temperature, including steam associated with BWRs. 

Reactor coolant >250°C 

(>482°F)

Treated water above the thermal embrittlement threshold 

for CASS. 

Reactor coolant >250°C 

(>482°F) and neutron 

flux

Treated water in the reactor coolant system and 

connected systems above the thermal embrittlement 

threshold for CASS. 

Reactor coolant and high 

fluence (>1 x 1021 n/cm2

 

E >0.1 MeV)

Reactor coolant subjected to a high fluence (>1 x 1021

n/cm2 E >0.1 MeV). 

Reactor coolant and 

neutron flux

The 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 (GALL AMP XI.M2). 

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 (GALL AMP XI.M2). 

Sodium pentaborate 

solution

Treated water that contains a mixture of borax and boric 

acid.
NUREG-1801, Rev. 2 IX-20 December 2010

IX.D Selected Definitions & Use of Terms for Describing and Standardizing

ENVIRONMENTS 

Term Definition as used in this document

Soil Soil is a mixture of inorganic materials produced by the 

weathering of rock and clay minerals, and organic 

material produced by the decomposition of vegetation. 

Voids containing air and moisture occupy 30 to 60 

percent [Ref.26] of the soil volume. Properties of soil that 

can affect degradation kinetics include moisture content, 

pH, ion exchange capacity, density, and hydraulic 

conductivity. External environments included in the soil 

category consist of components at the air/soil interface, 

buried in the soil, or exposed to ground water in the soil. 

See also “ground water/soil.” 

Steam The steam environment is managed by the BWR water 

chemistry program or PWR secondary plant water 

chemistry program. Defining the temperature of the steam 

is not considered necessary for analysis.

System temperature up 

to 288°C (550°F)

This environment consists of a metal temperature of BWR 

components <288°C (550°F).

System temperature up 

to 340°C (644°F)

This environment consists of a maximum metal 

temperature <340°C (644°F).

Treated borated water Borated (PWR) water is a controlled water system The 

Chemical and Volume Control System (CVCS) maintains 

the proper water chemistry in the reactor coolant system

while adjusting the boron concentration during operation to 

match long-term reactivity changes in the core.

Treated borated water 

>250°C (>482°F)

Treated water with boric acid above the 250°C (>482°F) 

thermal embrittlement threshold for CASS

Treated borated water 

>60°C (>140°F)

Treated water with boric acid in PWR systems above the 

60°C (>140°F) SCC threshold for stainless steel
December 2010 IX-21 NUREG-1801, Rev. 2

IX.D Selected Definitions & Use of Terms for Describing and Standardizing

ENVIRONMENTS 

Term Definition as used in this document

Treated water Treated water is water whose chemistry has been altered 

and is maintained (as evidenced by testing) in a state

which differs from naturally-occurring sources so as to 

meet a desired set of chemical specifications. 

Treated water generally falls into one of two categories. 

(1) The first category is based on demineralized water 

and, with the possible exception of boric acid (for PWRs 

only), generally contains minimal amounts of any 

additions. This water is generally characterized by high 

purity, low conductivity, and very low oxygen content. This 

category of treated water is generally used as BWR 

coolant and PWR primary and secondary water.

(2) The second category may but need not be based on 

demineralized water. It contains corrosion inhibitors and 

also may contain biocides or other additives. This water 

will generally be comparatively higher in conductivity and 

oxygen content than the first category of treated water. 

This category of treated water is generally used in HVAC 

systems, auxiliary boilers, and diesel engine cooling 

systems. Closed-cycle cooling water is a subset of this 

category of treated water

Treated water >60°C 

(>140°F)

Treated water above the 60°C stress corrosion cracking 

threshold for stainless steel

Waste water Radioactive, potentially radioactive, or non-radioactive 

waters that are collected from equipment and floor drains. 

Waste waters may contain contaminants, including oil and 

boric acid, depending on location, as well as originally 

treated water that is not monitored by a chemistry 

program.

Water-flowing Water that is refreshed; thus, it has a greater impact on 

leaching and can include rainwater, raw water, ground 

water, or water flowing under a foundation

Water-standing Water that is stagnant and unrefreshed, thus possibly 

resulting in increased ionic strength up to saturation
NUREG-1801, Rev. 2 IX-22 December 2010

E. Aging Effects

The following table explains the selected usage of many of the standardized aging effects due 

to associated aging mechanisms used in the preceding GALL AMR tables in Chapters II through 

VIII of GALL Report, Rev. 2. 

IX.E Selected Use of Terms for Describing and Standardizing

AGING EFFECTS

Term Usage in this document

Changes in dimensions Changes in dimension can result from various 

phenomena, such as void swelling and, on a 

macroscopic level, denting 

Concrete cracking and 

spalling

Cracking and exfoliation of concrete as the result of 

freeze-thaw, aggressive chemical attack, and reaction 

with aggregates

Corrosion of connector 

contact surfaces

Corrosion of exposed connector contact surfaces when 

caused by borated water intrusion

Crack growth Increase in crack size attributable to cyclic loading 

Cracking This term is synonymous with the phrase “crack initiation 

and growth” in metallic substrates. Cracking in concrete 

when caused by restraint shrinkage, creep, settlement, 

and aggressive environment.

Cracking, loss of bond, 

and loss of material 

(spalling, scaling)

Cracking, loss of bond, and loss of material (spalling, 

scaling) when 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 when caused by 

settlement. Although settlement can 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.

Denting Denting in steam generators can result from corrosion of 

carbon steel tube support plates.

Expansion and cracking Within concrete structures, expansion and cracking can 

result from reaction with aggregates. 

Fatigue Fatigue in metallic fuse holder clamps can result from 

ohmic heating, thermal cycling, electrical transients, 

frequent manipulation, and vibration. [Ref. 13]
December 2010 IX-23 NUREG-1801, Rev. 2

IX.E Selected Use of Terms for Describing and Standardizing

AGING EFFECTS

Term Usage in this document

Fretting or lockup Fretting is 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 (loss of flexibility) and loss of strength (loss of 

ability to withstand tensile or compressive stress) can 

result from elastomer degradation of seals and other

elastomeric components. Weathered elastomers can 

experience increased hardness, shrinkage, and loss of 

strength.

Increase in porosity and 

permeability, cracking, 

loss of material (spalling, 

scaling), loss of strength

Porosity and permeability, cracking, and loss of material 

(spalling, scaling) in concrete can increase due to 

aggressive chemical attack. In concrete, the loss of 

material (spalling, scaling) and cracking can result from 

the freeze-thaw processes. Loss of strength can result 

from leaching of calcium hydroxide in the concrete.

Increased resistance of 

connection

Increased resistance of connection is an aging effect 

that can be caused by the loosening of bolts resulting 

from thermal cycling and ohmic heating. [VI.A. LP-25, 

Ref. 14, 15]

In Chapter VI AMR line-items, increased resistance to 

connection is also said to be caused by the following 

aging mechanisms:

• chemical contamination, corrosion, and oxidation 

(in an air, indoor controlled environment, increased 

resistance of connection due to chemical 

contamination, corrosion and oxidation do not 

apply) [VI.A. LP-23]

• thermal cycling, ohmic heating, electrical 

transients, vibration, chemical contamination, 

corrosion, and oxidation [VI.A. LP-30]

• fatigue caused by frequent manipulation or 

vibration [VI.A. LP-31]

• corrosion of connector contact surfaces caused by 

intrusion of borated water [VI.A. LP-36]

• oxidation or loss of pre-load [VI.A. LP-39, VI.A. LP48]
NUREG-1801, Rev. 2 IX-24 December 2010

IX.E Selected Use of Terms for Describing and Standardizing

AGING EFFECTS

Term Usage in this document

Ligament cracking Steel tube support plates can experience ligament 

cracking due to corrosion. As previously noted in IN 96-

09, tube support plate signal anomalies found during 

eddy-current testing of SG tubes may be indicative of 

support plate damage or ligament cracking. 

Loss of conductor 

strength 

Transmission conductors can experience loss of 

conductor strength due to corrosion.

Loss of fracture 

toughness

Loss of fracture toughness can result from various aging 

mechanisms, including thermal aging embrittlement and 

neutron irradiation embrittlement 

Loss of leak tightness Steel airlocks can experience loss of leak tightness in 

the 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. 

Ref. 14]

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.

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.
December 2010 IX-25 NUREG-1801, Rev. 2

IX.E Selected Use of Terms for Describing and Standardizing

AGING EFFECTS

Term Usage in this document

Loss of preload Loss of preload can be 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). [Ref. 15, 16]

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 sealing in elastomeric phase bus 

enclosure assemblies can result from moisture intrusion.

None Certain material/environment combinations may not be 

subject to significant aging mechanisms; thus, there are 

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.

Reduction of heat 

transfer

Reduction of heat transfer can result from fouling 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 

Report, Rev. 2 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.
NUREG-1801, Rev. 2 IX-26 December 2010

IX.E Selected Use of Terms for Describing and Standardizing

AGING EFFECTS

Term Usage in this document

Reduced insulation 

resistance

Reduced insulation resistance is an aging effect used 

exclusively in GALL Report, Rev. 2 for Chapter VI, 

Electrical Components and is said to result from the 

following aging mechanisms:

• thermal/thermoxidative degradation of 

organics/thermoplastics, radiation-induced 

oxidation, moisture/debris intrusion, and ohmic 

heating [VI.A.LP-26]

• presence of salt deposits or surface contamination 

[VI.A.LP-28]

• thermal/thermoxidative degradation of organics,

radiolysis, and photolysis (UV sensitive materials 

only) of organics; radiation-induced oxidation; 

moisture intrusion [VI.A.LP-33, VI.A.LP-34]

• moisture [VI.A.LP-35]

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 Wall thinning is a specific type of loss of material 

attributed in the AMR line-items to general corrosion or 

flow-accelerated corrosion.
December 2010 IX-27 NUREG-1801, Rev. 2

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 mechanisms used in the preceding 

GALL AMR tables in Chapters II through VIII of GALL Report, Rev. 2. 

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Abrasion As used in the context of GALL Chpt III, “Structures and 

Component Supports,” as water migrates over a concrete 

surface, it may transport material that can abrade the 

concrete. The passage of water also may 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. [Ref. 17]

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 on their 

concentrations in soil/ground water that comes into contact 

with the concrete. Exposed surfaces of Class 1 structures 

may be subject to sulfur-based acid-rain degradation. The 

minimum thresholds causing concrete degradation are 500 

ppm chlorides and 1500 ppm sulfates. [Ref. 17]

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. [Ref. 18] 
NUREG-1801, Rev. 2 IX-28 December 2010

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Borated Water Intrusion The 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 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 Presence of chemicals that do not occur under normal 

conditions at concentrations that could result in the 

degradation of the component.

Cladding breach This refers to the various aging mechanisms breaking

metallic 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.”

It is only used in AMR line-items in the Engineered Safety 

Features and Auxiliary System to describe the loss of 

material in PWR emergency core cooling system pump 

casing constructed of steel with stainless steel cladding 

and the PWR chemical and volume control system pump 

casing constructed of steel with stainless steel cladding.

Cladding degradation This refers to the degradation of the stainless steel 

cladding via any applicable degradation process and is a 

precursor to cladding breach. 

It is only used 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 the environment or between two 

dissimilar metals that produces a deterioration of the 

material and its properties.
December 2010 IX-29 NUREG-1801, Rev. 2

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Corrosion of carbon steel 

tube support plate

Corrosion can occur on the carbon steel tube support 

plates, which are plate-type components providing tube-totube 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. [Ref. 19, 20] 

Corrosion of embedded 

steel

If the pH of concrete in which steel is embedded is 

reduced below 11.5 by intrusion of aggressive ions (e.g., 

chlorides > 500 ppm) in the presence of oxygen, 

embedded steel may corrode. A reduction in pH may be 

caused by the leaching of alkaline products through 

cracks, entry of acidic materials, or carbonation. Chlorides 

may 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. [Ref. 21]

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, or for Ni-based alloys below 1800°F. [Ref.22, 23] 

Creep, in concrete, is related to the loss of absorbed water 

from the hydrated cement paste. It is a function of the 

modulus of elasticity of the aggregate. It may result in loss 

of prestress in the tendons used in prestressed concrete 

containment. [Ref. 19] 

Crevice corrosion 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 nonmetals, 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. 

Localized corrosion of a metal surface at, or immediately 

adjacent to, an area that is shielded from full exposure to 

the environment because of the close proximity of the 

metal to the surface of another dissimilar material.
NUREG-1801, Rev. 2 IX-30 December 2010

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Cyclic loading One source of cyclic loading is the 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 also may cause changes 

in dimensions that result in functional failure.

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 due to containment caused by aging degradation 

of these components. 

Distortion The aging mechanism of distortion (as associated with 

component supports in GALL Chpt III.B2) can be caused 

by time-dependent strain or by 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 those of natural rubber. The term 

elastomer is sometimes used to technically distinguish 

synthetic rubbers and rubber-like plastics from natural 

rubber. Degradation may include mechanisms such as 

cracking, crazing, fatigue breakdown, abrasion, chemical 

attacks, and weathering. [Ref. 24, 25] 

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 Elevated temperature is referenced as an aging 

mechanism only in the context of LWR containments 

(GALL Chpt. II). In concrete, reduction of strength and 

modulus can be attributed to elevated temperatures 

(>150°F general; >200°F local).

Erosion Erosion, or the progressive loss of material from a solid 

surface, is due to mechanical interaction between that 

surface and a fluid, a multicomponent fluid, or solid 

particles carried by the fluid.
December 2010 IX-31 NUREG-1801, Rev. 2

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Erosion settlement Erosion settlement is the subsidence of a containment 

structure that may occur due to changes in the site 

conditions, e.g., erosion or changes in the water table). 

The amount of settlement depends on the foundation 

material. [Ref. 21] Another synonymous 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.

Fatigue Fatigue is 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 from 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. [Ref. 26]

Flow-accelerated 

corrosion (FAC)

Flow-accelerated corrosion, also termed “erosioncorrosion,” is 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 and -R3 recommendations 

for an effective FAC program. [Ref. 27]
NUREG-1801, Rev. 2 IX-32 December 2010

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Fouling Fouling is an accumulation of deposits on the surface of a 

component or structure. This term includes accumulation 

and growth of aquatic organisms on a submerged metal 

surface or the accumulation of deposits (usually inorganic) 

on heat exchanger tubing. Biofouling, a subset of fouling, 

can be caused by either macro-organisms (e.g., 

barnacles, Asian clams, zebra mussels, and others found 

in fresh and salt water) or micro-organisms (e.g., algae, 

etc.). 

Fouling also can be categorized as particulate fouling from 

sediment, silt, dust, and corrosion products, or 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 or loss of material.

Freeze-thaw, frost action Repeated freezing and thawing can cause severe 

degradation of concrete, characterized by scaling, 

cracking, and spalling. The cause is water freezing within 

the pores of the concrete, creating hydraulic pressure. If 

unrelieved, this pressure will lead to freeze-thaw 

degradation.

If the temperature cannot be controlled, other factors that 

enhance the resistance of concrete to freeze-thaw 

degradation are (a) adequate air content (i.e., 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. 

[Ref. 21, 28] 

Fretting Fretting is an aging effect due to accelerated deterioration 

at the interface between contacting surfaces that 

experience a slight, differential oscillatory movement as 

the result of corrosion.

Galvanic corrosion Galvanic corrosion is accelerated corrosion of a metal 

because of an electrical contact with a more noble metal 

or nonmetallic conductor in a corrosive electrolyte. It is 

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.
December 2010 IX-33 NUREG-1801, Rev. 2

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

General corrosion General corrosion, also known as uniform 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 corrosion is not explicitly 

listed in the aging effects/aging mechanism column in 

GALL Report, Rev. 2 AMR Items and when the descriptor 

may only be loss of material due to general corrosion. For 

example, the AMP XI.M36, “External Surfaces Monitoring 

of Mechanical Components,” calls for the inspection of 

general corrosion of steel 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 noticed first. 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, leaves the grain 

boundaries depleted of Cr and, therefore, susceptible to 

preferential attack (intergranular attack) by a corroding 

(oxidizing) medium.

Intergranular stress 

corrosion cracking 

(IGSCC) 

IGSCC is 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).
NUREG-1801, Rev. 2 IX-34 December 2010

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Leaching of calcium 

hydroxide and 

carbonation

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, depending on the solution pH) 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, pH, and temperature. This 

leaching action is effective only if the water passes 

through the concrete. [Ref. 21] 

Low-temperature crack 

propagation

Low-temperature crack propagation (LTCP) is IGSCC at 

low temperatures (~130-170o

F). 

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. [Ref. 23] 
December 2010 IX-35 NUREG-1801, Rev. 2

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

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 by conductors passing 

through electrical penetrations, for example. Ohmic 

heating is especially significant for power circuit 

penetrations. [Ref. 14] 

Outer diameter stress 

corrosion cracking 

(ODSCC)

ODSCC is SCC initiating in the outer diameter (secondary 

side) surface of steam generator tubes. The secondary 

side is part of the secondary system consisting of the shell 

side of the steam generator, high- and low-pressure 

turbines, moisture/separator reheaters, main electrical 

stages and interconnecting piping. 

This differs from PWSCC, which describes inner diameter 

(SG primary side) initiated cracking. [Ref. 20] The primary 

loop basically consists of the reactor vessel, reactor 

coolant pumps, pressurizer steam generator tubes, and 

interconnecting piping. 

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, and vibration isolators, fabricated from steel or 

other materials, such as Lubrite®. 

Oxidation Oxidation involves two types of reactions: (a) an increase 

in valence resulting from a loss of electrons, or (b) a 

corrosion reaction in which the corroded metal forms an 

oxide. [Ref. 24]

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
NUREG-1801, Rev. 2 IX-36 December 2010

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Presence of any salt 

deposits

The surface contamination (and increased electrical 

conductivity) resulting from the aggressive environment 

associated with the presence of salt deposits can degrade 

high voltage 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 also high temperatures. This 

aging mechanism is most likely a factor for nickel alloys in 

the PWR environment. [Ref. 19]

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.

Radiation-induced 

oxidation

Two types of reactions that are affected by radiation are 

(a) 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 GALL Chpt. VI for MEB 

insulation. [Ref. 24]

Radiolysis Radiolysis is a chemical reaction 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. [Ref. 11,

29]

Restraint shrinkage Restraint shrinkage can cause cracking in concrete 

transverse to the longitudinal construction joint.
December 2010 IX-37 NUREG-1801, Rev. 2

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Selective leaching Selective leaching is also known as dealloying (e.g., 

dezincification or graphitic corrosion) and involves 

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) that may include freeze-thaw, leaching, 

aggressive chemicals, reaction with aggregates, corrosion 

of embedded steels, elevated temperatures, irradiation, 

abrasion, and cavitation [Ref. 17] 

Settlement This term is referenced as an aging mechanism in GALL 

Chpt. II, Containment Structures. Settlement of a 

containment structure may occur due to changes in the 

site conditions (e.g., water table, etc.). The amount of 

settlement depends on the foundation material. [Ref. 20] 

Stress corrosion cracking 

(SCC)

SCC is the cracking of a metal produced by the combined 

action of corrosion and tensile stress (applied or residual), 

especially at elevated temperature. SCC is highly 

chemically specific in that certain alloys are likely to 

undergo SCC only when exposed to a small number of 

chemical environments. For PWR internal components, in 

Chapters IV.B2, IV.B3 and IV.B4, SCC includes 

intergranular stress corrosion cracking, transgranular 

stress corrosion cracking, primary water stress corrosion 

cracking, and low temperature crack propagation as aging 

mechanisms.

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. [Ref. 

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 or 

fouling.

Sustained vibratory 

loading

Vibratory loading over time
NUREG-1801, Rev. 2 IX-38 December 2010

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

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 

(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 types of 

embrittlement, but wrought stainless steel is not affected 

by either of these processes. [Ref. 23] 

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) [Ref. 15,

16] 

Thermal and mechanical 

loading

Loads (stress) due to mechanical or thermal (temperature) 

sources

Thermal degradation of 

organic materials

Organic materials, in this case, are polymers. 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. 
December 2010 IX-39 NUREG-1801, Rev. 2

IX.F Selected Definitions & Use of Terms for Describing and Standardizing

AGING MECHANISMS

Term Definition as used in this document

Thermal fatigue Fatigue is the progressive and localized structural damage 

that occurs when a material is subjected to cyclic loading. 

The maximum stress values are less than the ultimate 

tensile stress limit, and may be below the yield stress limit

of the material. Higher temperatures generally decrease 

fatigue strength. Thermal 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 thermo-hydraulic condition with a 

definitive hot and cold water boundary inducing thermal 

fatigue of the piping. Turbulent penetration is a thermohydraulic 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). [Ref. 22]

Transgranular stress 

corrosion cracking

Transgranular stress corrosion cracking (TGSCC) is stress 

corrosion cracking in which cracking occurs across the 

grains

Void swelling Vacancies created in reactor (metallic) materials as a 

result of irradiation may accumulate into voids that may, in 

turn, lead to changes in dimensions (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 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. 2 IX-40 December 2010

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. [Ref. 23] 

Weathering Weathering is the mechanical or chemical degradation of 

external surfaces of materials when exposed to an outside 

environment.

Wind-induced abrasion (See Abrasion) The fluid carrier of abrading particles is 

wind rather than water/liquids. 
December 2010 IX-41 NUREG-1801, Rev. 2

G. References: 

1. EPRI-1016596, EPRI Materials Reliability Program: Pressurized Water Reactor Internals 

Inspection and Evaluation Guidelines (MRP-227-Rev. 0),” Electric Power Research 

Institute, Palo Alto, CA: 12/22/2008.

2. SAND 93-7070, “Aging Management Guideline for Commercial Nuclear Power PlantsHeat Exchangers,” Sandia National Laboratories, June 1994.

3. Metals Handbook, Ninth Edition, Volume 13, Corrosion, American Society of Metals, 

1987, p. 326.

4. Gillen and Clough, Rad. Phys. Chem. Vol. 18, p. 679, 1981.

5. ASME Boiler & Pressure Vessel Code, Section II: Part B, Nonferrous Material 

Specifications.

6. ASME Boiler & Pressure Vessel Code, Section II: Part A, Ferrous Material Specification.

7. NUREG-1833, “Technical Bases for Revision to the License Renewal Guidance 

Documents,” U.S. Nuclear Regulatory Commission, Revision 1, October 2005.

8. Fink, F. W. and W.K. Boyd, “The Corrosion of Metals in Marine Environments,” DMIC 

Report 245, May 1970.

9. Peckner, D. and I. M. Bernstein, Eds., Handbook of Stainless Steels, McGraw-Hill, New 

York, 1977, p. 16-85.

10. Chopra, O.K. 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).

11. NUREG-1557, “Summary of Technical Information and Agreements from Nuclear 

Management and Resources Council Industry Reports Addressing License Renewal,” 

October 1996.

12. Freeze, R.A. and J.A Cherry, “Groundwater,” Prentice-Hall, Englewood Cliffs, NJ, 1979.

13. NUREG-1760, “Aging Assessment of Safety-Related Fuses Used in Low- and MediumVoltage Applications in Nuclear Power Plants,” May 2002.

14. SAND96-0344, “Aging Management Guideline for Commercial Nuclear Power PlantsElectrical Cable and Terminations,” September 1996.

15. EPRI TR-104213, “Bolted Joint Maintenance & Application Guide,” Electric Power 

Research Institute, Palo Alto, CA, December 1995.

16. 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. 

17. NUMARC Report 90-06, Revision 1, December 1991, "Class 1 Structures License 

Renewal Industry Report,” NUMARC, Washington D.C.

18. NRC GL 96-04, “Boraflex Degradation in Spent Fuel Pool Storage Racks,” NRC, 

Rockville, MD, 1996.
NUREG-1801, Rev. 2 IX-42 December 2010

19. Shah, V.N. and D. E. Macdonald, Eds., "Aging and Life Extension of Major Light Water 

Reactor Components,” Elsevier, Amsterdam, 1993.

20. Gavrilas, M., P. Hejzlar, N.E. Todreas, and Y. Shatilla, "Safety Features of Operating 

Light Water Reactors of Western Designs," CANES, MIT, Cambridge, MA, 2000.

21. NUMARC Report 90-01, Revision 1, Sept 1991, "Pressurized Water Reactors 

Containment Structures License Renewal Industry Report,” NUMARC, Washington D.C.

22. 1976 Annual Book of ASTM Standards, Part 10, ASTM, Philadelphia, PA, 1976.

23. NUMARC Report 90-07, May 1992, "PWR Reactor Coolant System License Renewal 

Industry Report,” NUMARC, Washington D.C.

24. Davis, J.R. (Editor) "Corrosion," ASM International, Materials Park, OH, 2000.

25. 2004 Annual Book of ASTM Standards, Volume 09.01, ASTM International, 2004.

26. NUMARC Report 90-05, Revision 1, December 1992, "PWR Reactor Pressure Vessel 

Internals License Renewal Industry Report,” Washington D.C.

27. NSAC-202L-R2, “Recommendations for an Effective Flow Accelerated Corrosion 

Program,” Electric Power Research Institute, Palo Alto, CA, April 8, 1999.

28. ACI 301-84 “Specification for Structural Concrete for Buildings,” (Field Reference 

Manual) American Concrete Institute, Detroit, MI, Revised 1988.

29. ACI 201.2R 77 “Guide to Durable Concrete,” American Concrete Institute, Detroit, MI, 

Reapproved 1982.
December 2010 X-i NUREG-1801, Rev. 2

CHAPTER X

TIME-LIMITED AGING ANALYSES 

EVALUATION OF AGING MANAGEMENT PROGRAMS

UNDER 10 CFR 54.21(C)(1)(iii) 

December 2010 X-1 NUREG-1801, Rev. 2

TIME-LIMITED AGING ANALYSES (TLAAs)

X.M1 Fatigue Monitoring

X.S1 Concrete Containment Tendon Prestress 

X.E1 Environmental Qualification (EQ) of Electric Components 

December 2010 X M1-1 NUREG-1801, Rev. 2

X.M1 FATIGUE MONITORING

Program Description

Fatigue usage factor is a computed mechanical parameter suitable for gauging fatigue damage 

in components subjected to fluctuating stresses. Crack initiation is assumed to have started in a 

structural component when the fatigue usage factor at a point of the component reaches the 

value of 1, the design limit on fatigue. 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 components. The program also verifies that the severity of 

the monitored transients are bounded by the design transient definition for which they are 

classified. 

The AMP addresses the effects of the reactor coolant environment on component fatigue life (to 

determine an environmentally-adjusted cumulative usage factor, or CUFen) by assessing the 

impact of the reactor coolant environment on a set of sample critical components for the plant. 

Examples of critical components are identified in NUREG/CR-6260. Environmental effects on 

fatigue for these critical components may be evaluated using one of the following sets of 

formulae: 

 Carbon and Low Alloy Steels

o Those provided in NUREG/CR-6583, using the applicable ASME Section III fatigue 

design curve 

o Those provided in Appendix A of NUREG/CR-6909, using either the applicable 

ASME Section III fatigue design curve or the fatigue design curve for carbon and low 

alloy steel provided in NUREG/CR-6909 (Figures A.1 and A.2, respectively, and 

Table A.1)

o A staff approved alternative

 Austenitic Stainless Steels

o Those provided in NUREG/CR-5704, using the applicable ASME Section III fatigue 

design curve

o Those provided in NUREG/CR-6909, using the fatigue design curve for austenitic 

stainless steel provided in NUREG/CR-6909 (Figure A.3 and Table A.2)

o A staff approved alternative

 Nickel Alloys

o Those provided in NUREG/CR-6909, using the fatigue design curve for austenitic 

stainless steel provided in NUREG/CR-6909 (Figure A.3 and Table A.2)

o A staff approved alternative

Any one option may be used for calculating the CUFen for each material.
NUREG-1801, Rev. 2 X M1-2 December 2010

Evaluation and Technical Basis

1. Scope of Program: The scope includes those components that have been identified to 

have a fatigue TLAA. The program monitors and tracks the number of critical thermal and 

pressure transients for the selected components. The program ensures the fatigue usage 

remaining within the allowable limit, thus minimizing fatigue cracking of metal components 

caused by anticipated cyclic strains in the material.

For purposes of monitoring and tracking, applicants should include, for a set of sample 

reactor coolant system components, fatigue usage calculations that consider the effects of 

the reactor water environment. This sample set should include the locations identified in 

NUREG/CR-6260 and additional plant-specific component locations in the reactor coolant 

pressure boundary if they may be more limiting than those considered in NUREG/CR-6260. 

2. Preventive Actions: The program prevents the fatigue TLAAs from becoming invalid by 

assuring that the fatigue usage resulting from actual operational transients does not exceed 

the Code design limit of 1.0, including environmental effects where applicable. This could be 

caused by the numbers of actual plant transients exceeding the numbers used in the fatigue 

analyses or by the actual transient severity exceeding the bounds of the design transient 

definitions. However, in either of these cases, if the analysis is revised to account for the 

increased number or severity of transients such that the CUF value remains below 1.0, the 

program remains effective.

3. Parameters Monitored/Inspected: The program monitors all plant design transients that 

cause cyclic strains, which are significant contributors to the fatigue usage factor. The 

number of occurrences of the plant transients that cause significant fatigue usage for each 

component is to be monitored. Alternatively, more detailed monitoring of local pressure and 

thermal conditions may be performed to allow the actual fatigue usage for the specified 

critical locations to be calculated.

4. Detection of Aging Effects: The program provides for updates of the fatigue usage 

calculations on an as-needed basis if an allowable cycle limit is approached, or in a case 

where a transient definition has been changed, unanticipated new thermal events are 

discovered, or the geometry of components have been modified. 

5. Monitoring and Trending: Trending is assessed to ensure that the fatigue usage factor 

remains below the design limit during the period of extended operation, thus minimizing 

fatigue cracking of metal components caused by anticipated cyclic strains in the material. 

6. Acceptance Criteria: The acceptance criterion is maintaining the cumulative fatigue usage 

below the design limit through the period of extended operation, with consideration of the 

reactor water environmental fatigue effects described in the program description and scope 

of program.

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. 

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 period of extended operation. Scope expansion 

includes consideration of other locations with the highest expected cumulative usage factors 

when considering environmental effects. As discussed in the Appendix for GALL, the staff 
December 2010 X M1-3 NUREG-1801, Rev. 2

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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process and administrative controls.

9. Administrative Controls: As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: The program reviews industry experience relevant to fatigue 

cracking. Applicable operating experience relevant to fatigue cracking is to be considered in 

selecting the locations for monitoring. As discussed in NRC Regulatory Issue 

Summary 2008-30, the use of certain simplified analysis methodology to demonstrate 

compliance with the ASME Code fatigue acceptance criteria could be nonconservative; 

therefore, a confirmatory analysis is recommended.

References

NRC Regulatory Issue Summary 2008-30, Fatigue Analysis of Nuclear Power Plant 

Components, U.S. Nuclear Regulatory Commission, December 16, 2008.

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/CR-6909, Effects of LWR Coolant Environments on the Fatigue Life of Reactor 

Materials, U.S. Nuclear Regulatory Commission, February 2007.

December 2010 X S1-1 NUREG-1801, Rev. 2

X.S1 CONCRETE CONTAINMENT TENDON PRESTRESS

Program Description

This aging management program provides reasonable assurance of the adequacy of 

prestressing forces in prestressed concrete containment tendons during the period of extended 

operation under 10 CFR 54.21(c)(1)(iii). The program consists of an assessment of inspections 

performed in accordance with the requirements of Subsection IWL of the American Society of 

Mechanical Engineers (ASME) Code, Section XI, as supplemented by the requirements of 10 

CFR 50.55a(b)(2)(viii). The assessment related to the adequacy of the prestressing force 

establishes (a) acceptance criteria in accordance with U.S. Nuclear Regulatory Commission 

(NRC) Regulatory Guide (RG) 1.35.1 and (b) trend lines based on the guidance provided in 

NRC Information Notice (IN) 99-10. 

As evaluated below, this time-limited aging analysis (TLAA) is an acceptable option to manage 

containment tendon prestress forces. However, it is recommended that the staff further evaluate 

an applicant's operating experience related to the containment tendon prestress force. 

Programs related to the adequacy of prestressing force for containments with grouted tendons 

are 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 performs the containment prestress force TLAA using 

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

2. Preventive Actions: Maintaining the prestress above the minimum required value (MRV), 

as described under the acceptance criteria below, ensures that the structural and functional 

adequacy of the containment are maintained.

3. Parameters Monitored: The parameters 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 predicted lower limit (PLL), MRV, and trending lines are developed for 

the period of extended operation. NRC RG 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 IN 99-10 provides guidance for constructing the trend line. 

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)(viii)(B). The acceptance criteria normally 

consists of PLL and the minimum required prestressing force, also called MRV. 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)(viii)(B).
NUREG-1801, Rev. 2 X S1-2 December 2010

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 for GALL, the staff finds the requirements of 

10 CFR Part 50, Appendix B, acceptable to address the corrective actions.

8. Confirmation Process: The confirmation process ensures that preventive actions are 

adequate and that appropriate corrective actions have been completed and are effective. 

The confirmation process for this program is implemented through the site's quality 

assurance (QA) program in accordance with the requirements of 10 CFR Part 50, 

Appendix B. 

9. Administrative Controls: The administrative controls for this program provide for a formal 

review and approval of corrective actions. The administrative controls for this program are 

implemented through the site's QA program in accordance with the requirements of 10 CFR 

Part 50, Appendix B.

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 IN 99-10 could be useful. 

Additional industry operating experience has been documented in NUREG/CR-4652 and in 

the May/June 1994 Concrete International publication by H. Ashar, C. P. Tan, and D. Naus. 

However, tendon operating experience may be different at plants with prestressed concrete 

containments. The difference could be due to the prestressing system design (e.g., buttonheaded, wedge, or swaged anchorages), environment, and type of reactor (i.e., pressurized 

water reactor and boiling water reactor). Thus, the applicant's plant-specific operating 

experience should be further evaluated for license renewal.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009. 

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2009. 

10 CFR 54.21, Contents of Application-Technical Information, Office of the Federal Register, 

National Archives and Records Administration, 2009.

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.

ASME Section XI, Rules for In-Service Inspection of Nuclear Power Plant Components, 

Subsection IWL, Requirements for Class CC Concrete Components of Light-Water 
December 2010 X S1-3 NUREG-1801, Rev. 2

Cooled Plants, 2004 edition, The ASME Boiler and Pressure Vessel Code, The 

American Society of Mechanical Engineers, New York, NY.

H. Ashar, C.P. Tan, D. Naus, Prestressing in Nuclear Power Plants, Concrete International, 

Detroit, Michigan: ACI, May/June 1994. 

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.

NUREG/CR-4652, Concrete Component Aging and its Significance to Life Extension of Nuclear 

Power Plants, Oak Ridge National Laboratory, September 1986.

December 2010 X E1-1 NUREG-1801, Rev. 2

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, 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 shall 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)(5) also requires replacement or refurbishment of 

components not qualified for the current license term prior to the end of designated life, unless 

additional life is established through ongoing qualification. 10 CFR 50.49(f) establishes four 

methods of demonstrating qualification for aging and accident conditions. 10 CFR 50.49(k) and 

(i) 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 Division of Operating Reactors (DOR) Guidelines; Guidelines for Evaluating 

Environmental Qualification of Class 1E Electrical Equipment in Operating Reactors; NUREG0588, “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 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. 2 X E1-2 December 2010

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. The reanalysis showing the 60-year qualification is established prior to the plant 

entering the period of extended operation. As defined in 10 CFR 50.49(j), a record of the 

qualification must be maintained in an auditable form for the entire period of extended operation

during which the covered item is installed in the nuclear power plant or is stored for future use; 

this permits verification that each item of electric equipment important to safety covered by this 

section (a) is qualified for its application and (b) meets its specified performance requirements 

when it is subjected to the conditions predicted to be present when it must perform a safety 

function up to the end of qualified life. 

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 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 
December 2010 X E1-3 NUREG-1801, Rev. 2

applying the plant temperature data in the evaluation, or (b) using the plant temperature data to 

demonstrate conservatism when using plant design temperatures for an evaluation. Any 

changes to material activation energy values as part of a reanalysis are justified on a plantspecific 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.

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 refurbished, replaced, or requalified prior to exceeding the period for which the 

current qualification remains valid. A reanalysis is 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 
NUREG-1801, Rev. 2 X E1-4 December 2010

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 

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 for GALL, 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 for GALL, 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 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 for GALL, 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 Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009. 
December 2010 X E1-5 NUREG-1801, Rev. 2

10 CFR 50.49, Environmental Qualification of Electrical Equipment Important to Safety for 

Nuclear Power Plants, Office of the Federal Register, National Archives and Records 

Administration, 2009. 

10 CFR 54.21, Contents of Application—Technical Information, Office of the Federal Register, 

National Archives and Records Administration, 2009. 

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.

NRC Regulatory Issue Summary 2003-09, Environmental Qualification of Low-Voltage 

Instrumentation and Control Cables, May 2, 2003. 

NUREG-0588, Interim Staff Position on Environmental Qualification of Safety-Related Electrical 

Equipment, U. S. Nuclear Regulatory Commission, July 1981.

December 2010 XI-i NUREG-1801, Rev. 2 

CHAPTER XI

AGING MANAGEMENT PROGRAMS (AMPS)

December 2010 XI-1 NUREG-1801, Rev. 2 

AGING MANAGEMENT PROGRAMS (AMPs)

Guidance on Use of Later Editions/Revisions of Various Industry Documents

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

and IWD

XI.M2 Water Chemistry

XI.M3 Reactor Head Closure Stud Bolting

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.M11B Cracking of Nickel-Alloy Components and Loss of Material Due to 

Boric Acid-Induced Corrosion in Reactor Coolant Pressure 

Boundary Components (PWRs only)

XI.M12 Thermal Aging Embrittlement of Cast Austenitic Stainless Steel 

(CASS) 

XI.M16 A PWR Vessel Internals

XI.M17 Flow-Accelerated Corrosion

XI.M18 Bolting Integrity

XI.M19 Steam Generators 

XI.M20 Open-Cycle Cooling Water System

XI.M21A Closed Treated Water Systems

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.M29 Aboveground Metallic Tanks

XI.M30 Fuel Oil Chemistry

XI.M31 Reactor Vessel Surveillance

XI.M32 One-Time Inspection

XI.M33 Selective Leaching

XI.M35 One-Time Inspection of ASME Code Class 1 Small Bore-Piping

XI.M36 External Surfaces Monitoring of Mechanical Components

XI.M37 Flux Thimble Tube Inspection 

XI.M38 Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components

XI.M39 Lubricating Oil Analysis

XI.M40 Monitoring of Neutron-Absorbing Materials Other than Boraflex

XI.M41 Buried and Underground Piping and Tanks

XI.S1 ASME Section XI, Subsection IWE

XI.S2 ASME Section XI, Subsection IWL

XI.S3 ASME Section XI, Subsection IWF
NUREG-1801, Rev. 2 XI-2 December 2010

AGING MANAGEMENT PROGRAMS (AMPs) (Continued)

XI.S4 10 CFR 50, Appendix J

XI.S5 Masonry Walls

XI.S6 Structures Monitoring 

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 Insulation Material for Electrical Cables and Connections Not 

Subject to 10 CFR 50.49 Environmental Qualification 

Requirements

XI.E2 Insulation Material for Electrical Cables and Connections Not 

Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Used in Instrumentation Circuits

XI.E3 Inaccessible Power 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 Requirements
December 2010 XI-3 NUREG-1801, Rev. 2 

GUIDANCE ON USE OF LATER EDITIONS/REVISIONS OF 

VARIOUS INDUSTRY DOCUMENTS

To aid applicants in the development of their license renewal applications, the staff has 

developed a list of aging management programs (AMPs) in the GALL Report that are based 

entirely or in part on specific editions/revisions of various industry codes (other than the ASME 

Code), standards, and other industry-generated guidance documents. License renewal 

applicants may use later editions/revisions of these industry generated documents, subject to 

the following provisions: 

(i) If the later edition/revision has been explicitly reviewed and approved/endorsed by the 

NRC staff for license renewal via an NRC Regulatory Guide endorsement, a safety 

evaluation for generic use (such as for a BWRVIP), incorporation into 10 CFR, or a 

license renewal interim staff guidance.

(ii) If the later edition/revision has been explicitly reviewed and approved on a plant-specific 

basis by the NRC staff in their safety evaluation report for another applicant’s license 

renewal application (a precedent exists). Applicants may reference this and justify 

applicability to their facility via the exception process in NEI 95-10.

If either of these methods is used as justification for adopting a later edition/revision than 

specified in the GALL Report, the applicant shall make available for the staff’s review the 

information pertaining to the NRC endorsement/approval of the later edition/revision.

December 2010 XI M1-1 NUREG-1801, Rev. 2

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 of these 

components is covered in Subsections IWB, IWC, and IWD, respectively, in the 2004 edition.

1

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. 10 CFR 50.55a 

imposes additional limitations, modifications, and augmentations of ISI requirements specified in 

ASME Code, Section XI, and those limitations, modifications, or augmentations described in 

10 CFR 50.55a are included as part of this program. 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 Generic Aging Lessons Learned (GALL) Report. 

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. Repair/replacement activities for these components are covered in 

Subsection IWA of the ASME code.

Evaluation and Technical Basis

1. Scope of Program: The ASME Section XI program provides the requirements for ISI, 

repair, and replacement of code Class 1, 2, or 3 pressure-retaining components and their 

integral attachments in light-water cooled nuclear power plants. The components within the 

scope of the program are specified in ASME Code, Section XI, Subsections IWB-1100, IWC1100, and IWD-1100 for Class 1, 2, and 3 components, respectively. The components 

described in Subsections IWB-1220, IWC-1220, and IWD-1220 are exempt from the 

volumetric and surface examination requirements, but not exempt from visual exam 

requirements of Subsections IWB-2500, IWC-2500, and IWD-2500.

2. Preventive Actions: This is a condition monitoring program. It does not implement 

preventive actions.

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.

The program uses three types of examination—visual, surface, and volumetric—in 

accordance with the 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 

 

1 Refer to the GALL Report, Chapter I, for applicability of other editions of the ASME Code, Section XI.
NUREG-1801, Rev. 2 XI M1-2 December 2010

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 constantload 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.

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 are 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 changes in

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 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. For boiling water reactors (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 BWR, 

are included in the approved Boiling Water Reactor Vessel and Internals Project Report 

(BWRVIP-03). 

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-3000 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-2410 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 IWB-2430, IWC-2430, 

or IWD-2430 for Class 1, 2, or, 3 components, respectively.

6. Acceptance Criteria: Any indication or relevant conditions of degradation are evaluated in 

accordance with IWB-3000, IWC-3000, or IWD-3000 for Class 1, 2, or 3 components, 

respectively. Examination results are evaluated in accordance with IWB-3100 or IWC-3100 

by comparing the results with the acceptance standards of IWB-3400 and IWB-3500, or 

IWC-3400 and IWC-3500, 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 
December 2010 XI M1-3 NUREG-1801, Rev. 2

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. 

7. Corrective Actions: Repair and replacement activities are performed in conformance with 

IWA-4000. As discussed in the Appendix for GALL, 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 10 CFR 

Part 50, Appendix B. As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process and administrative controls.

9. Administrative Controls: As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

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).

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. 

IGSCC has also occurred in a number of vessel internal components, such as core shrouds, 

access hole covers, top guides, and core spray spargers (U.S. Nuclear Regulatory 

Commission [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 has

occurred in high-pressure coolant injection piping (NRC IN 89-80) and instrument lines 

(NRC Licensee Event Report [LER] 50-249/99-003-01). 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 50-219/98-014-00).

PWR Primary System: Although the primary pressure boundary piping of PWRs has 

generally not been found to be affected by stress corrosion cracking (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), instrument nozzles in safety injection tanks (NRC IN 91-05), control rod drive 

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 
NUREG-1801, Rev. 2 XI M1-4 December 2010

injection piping (NRC IN 97-46 and NRC Bulletin 88-08). Through-wall circumferential 

cracking has been found in reactor pressure vessel head control rod drive penetration 

nozzles (NRC IN 2001-05). Evidence of reactor coolant leakage, together with crack-like 

indications, has been found in bottom-mounted instrumentation nozzles (NRC IN 2003-11 

and IN 2003-11, Supplement 1). Cracking in pressurizer safety and relief line nozzles and in 

surge line nozzles has been detected (NRC IN 2004-11), and circumferential cracking in 

stainless steel pressurizer heater sleeves has also been found (NRC IN 2006-27). Also, 

primary water stress corrosion cracking (PWSCC) has been observed in steam generator 

drain bowl welds inspected as part of a licensee’s Alloy 600/82/182 program (NRC IN 2005-

02).

PWR Secondary System: Steam generator tubes have experienced outside diameter stress 

corrosion cracking (OGSCC), intergranular attack, 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, 2009.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2009.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, The 

ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 50.55a, The 

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.

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.
December 2010 XI M1-5 NUREG-1801, Rev. 2

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.

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 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.

NRC Information Notice 2003-11, Leakage Found on Bottom-Mounted Instrumentation Nozzles, 

U.S. Nuclear Regulatory Commission, August 13, 2003.

NRC Information Notice 2003-11, Supplement 1, Leakage Found on Bottom-Mounted 

Instrumentation Nozzles, U.S. Nuclear Regulatory Commission, January 8, 2004.
NUREG-1801, Rev. 2 XI M1-6 December 2010

NRC Information Notice 2004-11, Cracking in Pressurizer Safety and Relief Nozzles and in 

Surge Line Nozzles, U.S. Nuclear Regulatory Commission, May 4, 2004.

NRC Information Notice 2005-02, Pressure Boundary Leakage Identified on Steam Generator 

Drain Bowl Welds, U.S. Nuclear Regulatory Commission, February 4, 2005.

NRC Information Notice 2006-27, Circumferential Cracking in the Stainless Steel Pressurizer 

Heater Sleeves of Pressurized Water Reactors, U.S. Nuclear Regulatory Commission, 

December 11, 2006.

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-1544, Status Report: Intergranular Stress Corrosion Cracking of BWR Core Shrouds 

and Other Internal Components, U.S. Nuclear Regulatory Commission, March 1, 1996.
December 2010 XI M2-1 NUREG-1801, Rev. 2

XI.M2 WATER CHEMISTRY

Program Description

The main objective of this program is to mitigate loss of material due to corrosion, cracking due 

to stress corrosion cracking (SCC) and related mechanisms, and reduction of heat transfer due 

to fouling in components exposed to a treated water environment. The program includes 

periodic monitoring of the treated water in order to minimize loss of material or cracking.

The water chemistry program for boiling water reactors (BWRs) relies on monitoring and control 

of reactor water chemistry based on industry guidelines contained in the Boiling Water Reactor 

Vessel and Internals Project (BWRVIP)-190 (Electric Power Research Institute [EPRI] 

1016579). The BWRVIP-190 has three sets of guidelines: one for reactor water, one for 

condensate and feedwater, and one for control rod drive (CRD) mechanism cooling water. The 

water chemistry program for PWRs relies on monitoring and control of reactor water chemistry 

based on industry guidelines contained in EPRI 1014986 (PWR Primary Water Chemistry 

Guidelines-Revision 6) and EPRI 1016555 (PWR Secondary Water Chemistry GuidelinesRevision 7). 

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 is maintained 

during the period of extended operation. 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 components in the reactor coolant system, the 

engineered safety features, the auxiliary systems, and the steam and power conversion 

system. This program addresses the metallic components subject to aging management 

review that are exposed to a treated water environment controlled by the water chemistry 

program.

2. Preventive Actions: The program includes specifications for chemical species, impurities 

and additives, 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, and chemical additive programs such as hydrogen water chemistry, or noble metal 

chemical application also may be used. For PWRs, additives are used for reactivity control 

and to control pH and inhibit corrosion.

3. Parameters Monitored/Inspected: The concentrations of corrosive impurities listed in the 

EPRI water chemistry guidelines are monitored to mitigate loss of material, cracking, and 

reduction of heat transfer. Water quality also is maintained in accordance with the guidance. 

Chemical species and water quality are monitored by in-process methods or through 

sampling. The chemical integrity of the samples is maintained and verified to ensure that the 
NUREG-1801, Rev. 2 XI M2-2 December 2010

method of sampling and storage will not cause a change in the concentration of the 

chemical species in the samples.

4. Detection of Aging Effects: This is a mitigation program and does not provide for detection 

of any aging effects of concern for the components within its scope. The monitoring methods 

and frequency of water chemistry sampling and testing is performed in accordance with the 

EPRI water chemistry guidelines and based on plant operating conditions. The main 

objective of this program is to mitigate loss of material due to corrosion and cracking due to 

SCC in components exposed to a treated water environment.

5. Monitoring and Trending: Chemistry parameter data are recorded, evaluated, and trended 

in accordance with the EPRI water chemistry guidelines.

6. Acceptance Criteria: Maximum levels for various chemical parameters are maintained 

within the system-specific limits as indicated by the limits specified in the corresponding 

EPRI water chemistry guidelines. 

7. Corrective Actions: Any evidence of aging effects or unacceptable water chemistry results 

are evaluated, the cause identified, and the condition corrected. When measured water 

chemistry parameters are outside the specified range, corrective actions are taken to bring 

the parameter back within the acceptable range (or to change the operational mode of the 

plant) within the time period specified in the EPRI water chemistry guidelines. Whenever 

corrective actions are taken to address an abnormal chemistry condition, increased 

sampling or other appropriate actions may be used to verify the effectiveness of these 

actions. As discussed in the Appendix for GALL, 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 for GALL, the staff 

finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process.

9. Administrative Controls: Site quality assurance 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 for GALL, 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 systems, and 

reactor water cleanup 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 
December 2010 XI M2-3 NUREG-1801, Rev. 2

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 potential for SCC-type mechanisms might normally occur 

because of inadvertent introduction of contaminants into the primary coolant system, 

including contaminants introduced from the free surface of the spent fuel pool (which can be 

a natural collector of airborne contaminants) or the introduction of oxygen during plant 

cooldowns (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. 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 (NRC INs 89-33, 94-87, 97-88, 90-10, and 96-11; NRC 

Bulletin 89-01 and its two supplements). IGSCC-induced circumferential cracking has 

occurred in PWR pressurizer heater sleeves (NRC IN 2006-27).

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). Extensive buildup of deposits 

at steam generator tube support holes can result in flow-induced vibrations and tube 

cracking (NRC IN 2007-37).

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, 2009.

BWRVIP-190 (EPRI 1016579), BWR Vessel and Internals Project: BWR Water Chemistry 

Guidelines-2008 Revision, Electric Power Research Institute, Palo Alto, CA, October 2008.

EPRI 1016555, PWR Secondary Water Chemistry Guidelines–Revision 7, Electric Power 

Research Institute, Palo Alto, CA, February 2009.

EPRI 1014986, PWR Primary Water Chemistry Guidelines, Revision 6, Volumes 1 and 2, 

Electric Power Research Institute, Palo Alto, CA, December 2007.

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.
NUREG-1801, Rev. 2 XI M2-4 December 2010

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.

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.
December 2010 XI M2-5 NUREG-1801, Rev. 2

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.

NRC Information Notice 2006-27, Circumferential Cracking in the Stainless Steel Pressurizer 

Heater Sleeves of Pressurized Water Reactors, December 11, 2006.

NRC Information Notice 2007-37, Buildup of Deposits in Steam Generators, November 23, 

2007.

NUREG-1544, Status Report: Intergranular Stress Corrosion Cracking of BWR Core Shrouds 

and Other Internal Components, U.S. Nuclear Regulatory Commission, March 1, 1996.

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.

December 2010 XI M3-1 NUREG-1801, Rev. 2

XI.M3 REACTOR HEAD CLOSURE STUD BOLTING 

Program Description

This program includes (a) inservice inspection (ISI) in accordance with the requirements of the 

American Society of Mechanical Engineers (ASME) Code, Section XI, Subsection IWB (2004 

edition,

2

Evaluation and Technical Basis

no addenda), Table IWB 2500-1; and (b) preventive measures to mitigate cracking. 

The program also relies on recommendations to address reactor head stud bolting degradation 

as delineated in NUREG-1339 and Nuclear Regulatory Commission (NRC) Regulatory Guide 

(RG) 1.65.

1. Scope of Program: The program manages the aging effects of cracking due to stress 

corrosion cracking (SCC) or intergranular stress corrosion cracking (IGSCC) and loss of 

material due to wear or corrosion for reactor vessel closure stud bolting (studs, washers, 

bushings, nuts, and threads in flange) for both boiling water reactors (BWRs) and 

pressurized water reactors (PWRs).

2. Preventive Actions: Preventive measures include: 

(a) avoiding the use of metal-plated stud bolting to prevent degradation due to corrosion or 

hydrogen embrittlement;

(b) using manganese phosphate or other acceptable surface treatments; 

(c) using stable lubricants. Of particular note, use of molybdenum disulfide (MoS2) as a 

lubricant has been shown to be a potential contributor to SCC and should not be used (RG 

1.65); and

(d) using bolting material for closure studs that has an actual measured yield strength less 

than 1,034 megapascals (MPa) (150 kilo-pounds per square inch) (NUREG-1339).

Implementation of these mitigation measures can reduce potential for 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 are 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 

or liquid penetrant examinations to indicate the presence of surface discontinuities and 

 

2 Refer to the GALL Report, Chapter I, for applicability of other editions of the ASME Code, Section XI.
NUREG-1801, Rev. 2 XI M3-2 December 2010

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 in accordance with ASME Code, Section XI, Table 

IWB-2500-1, Examination Category B-G-1, for pressure-retaining bolting greater than 

2 inches in diameter. Examination Category B-P for all pressure-retaining components 

specifies visual VT-2 examination of all pressure-retaining boundary components during the 

system leakage test. Table IWB-2500-1 specifies the extent and frequency of the inspection

and examination methods, and IWB-2400 specifies the schedule of the inspection. 

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 accordance with the 

requirements of IWA-4000 and the material and inspection guidance of RG 1.65. The 

maximum yield strength of replacement material should be limited as recommended in 

NUREG-1339. As discussed in the Appendix for GALL, 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 10 CFR 

Part 50, Appendix B. As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process and administrative controls.

9. Administrative Controls: As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: SCC has occurred in BWR pressure vessel head studs (Stoller, 

1991). The aging management program 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 are adequately managed so that the intended functions of the reactor head closure 

studs and bolts are maintained consistent with the current licensing basis for the period of 

extended operation. 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 Inspection and Enforcement Bulletin 82-02, NRC Generic Letter 91-17). 

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.
December 2010 XI M3-3 NUREG-1801, Rev. 2

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2009.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, The 

ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 50.55a The 

American Society of Mechanical Engineers, New York, NY.

NRC Regulatory Guide 1.65, Material and Inspection for Reactor Vessel Closure Studs, 

Revision 1, U.S. Nuclear Regulatory Commission, April 2010.

NRC Inspection and Enforcement Bulletin 82-02, Degradation of Threaded Fasteners in the 

Reactor Coolant Pressure Boundary of PWR Plants, June 2, 1982.

NUREG-1339, Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear 

Power Plants, June 1990.

NRC Generic Letter 91-17, Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear 

Power Plants, October 17, 1991.

Stoller, S. M., Reactor Head Closure Stud Cracking, Material Toughness Outside FSAR - SCC 

in Thread Roots, Nuclear Power Experience, BWR-2, Ill, 58, p. 30, 1991.

December 2010 XI M4-1 NUREG-1801, Rev. 2

XI.M4 BWR VESSEL ID ATTACHMENT WELDS

Program Description

The program includes inspection and flaw evaluation in accordance with the guidelines of a 

staff-approved boiling water reactor vessel and internals project (BWRVIP-48-A) to provide 

reasonable assurance of the long-term integrity and safe operation of boiling water reactor 

(BWR) vessel inside diameter (ID) attachment welds.

The guidelines of BWRVIP-48-A 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 core spray 

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-A 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.

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 is an augmented inservice inspection program that uses the inspection and 

flaw evaluation criteria in BWRVIP-48-A to detect cracking and monitor the effects of 

cracking on the intended function of the components. The program provides for repair 

and/or replacement, as needed, to maintain the ability to perform the intended function. The 

program is applicable to structural welds for BWR reactor vessel internal integral 

attachments.

2. Preventive Actions: The BWR Vessel ID Attachment Welds Program is a condition 

monitoring program and has no preventive actions. Maintaining high water purity reduces 

susceptibility to SCC or IGSCC. Reactor coolant water chemistry is monitored and 

maintained in accordance with the Water Chemistry Program. The program description, 

evaluation, and technical basis of water chemistry are presented in GALL AMP XI.M2, 

“Water Chemistry.”

3. Parameters Monitored/Inspected: The program monitors for cracks induced by SCC and 

IGSCC on the intended function of BWR vessel ID attachment welds. The program looks for 

surface discontinuities that may indicate the presence of a crack in the component in 

accordance with the guidelines of approved BWRVIP-48-A and the requirements of the 

American Society of Mechanical Engineers (ASME) Code, Section XI, Table IWB 2500-1 

(2004 edition3

4. Detection of Aging Effects: The extent and schedule of the inspection and test techniques 

prescribed by BWRVIP-48-A guidelines are designed to maintain structural integrity and 

ensure that aging effects are 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. 

). 

 

3 Refer to the GALL Report, Chapter I, for applicability of other editions of the ASME Code, Section XI.
NUREG-1801, Rev. 2 XI M4-2 December 2010

The ASME Code, 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-A recommend more 

stringent inspections for certain attachments. The guidelines recommend enhanced visual 

VT-1 examination of all safety-related attachments and those non-safety-related 

attachments identified as being susceptible to IGSCC. Visual VT-1 examination is capable 

of achieving 1/32-inch resolution; the enhanced visual VT-1 examination method is capable 

of achieving a 1/2 mil (0.0005 inch) 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 ASME Code, Section 

XI, IWB-2400 and approved BWRVIP-48-A guidelines provide timely detection of cracks. If 

flaws are detected, the scope of examination is expanded. Any indication detected is 

evaluated in accordance with ASME Code, Section XI or the staff-approved BWRVIP-48-A 

guidelines. Applicable and approved BWRVIP-14-A, BWRVIP-59-A, and BWRVIP-60-A 

documents provide guidelines for evaluation of crack growth in stainless steels, nickel 

alloys, and low-alloy steels, respectively.

6. Acceptance Criteria: Acceptance criteria are given in BWRVIP-48-A and ASME Code, 

Section XI. 

7. Corrective Actions: Repair and replacement procedures are equivalent to those 

requirements in ASME Code, Section XI. Corrective action is performed in accordance with 

ASME Code, Section XI, IWA-4000. As discussed in the Appendix for GALL, the staff finds 

that licensee implementation of the corrective action guidelines in BWRVIP-48-A provides 

an acceptable level of quality in accordance with 10 CFR Part 50, Appendix B corrective 

actions.

8. Confirmation Process: Site quality assurance 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 for GALL, the staff finds that licensee 

implementation of the guidelines in BWRVIP-48-A provides an acceptable level of quality in 

accordance with the 10 CFR Part 50, Appendix B confirmation process and administrative 

controls.

9. Administrative Controls: As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B acceptable to address the administrative 

controls.

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 this 

program provides reasonable assurance that cracking will be adequately managed and that 

the intended functions of the vessel ID attachments will be maintained consistent with the 

current licensing basis for the period of extended operation.
December 2010 XI M4-3 NUREG-1801, Rev. 2

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2009.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, The 

ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 50.55a, The 

American Society of Mechanical Engineers, New York, NY.

BWRVIP-03 (EPRI 105696 R1, March 30, 1999), BWR Vessel and Internals Project, Reactor 

Pressure Vessel and Internals Examination Guidelines, Final Safety Evaluation Report by 

the Office of Nuclear Reactor Regulation for BWRVIP-03, July 15, 1999.

BWRVIP-14-A (EPRI 1016569), Evaluation of Crack Growth in BWR Stainless Steel RPV 

Internals, September 2008. 

BWRVIP-48-A (EPRI 1009948), BWR Vessel and Internals Project, Vessel ID Attachment Weld 

Inspection and Flaw Evaluation Guidelines, November 2004. 

BWRVIP-59-A (EPRI 1014874), Evaluation of Crack Growth in BWR Nickel-Base Austenitic 

Alloys in RPV Internals, May 2007.

BWRVIP-60-A (EPRI 1008871), BWR Vessel and Internals Project, Evaluation of Crack Growth 

in BWR Low Alloy Steel RPV Internals, June 2003.

BWRVIP-62 (EPRI 108705), BWR Vessel and Internals Project, Technical Basis for Inspection 

Relief for BWR Internal Components with Hydrogen Injection, March 7, 2000.

BWRVIP-190 (EPRI 1016579), BWR Vessel and Internals Project: BWR Water Chemistry 

Guidelines—2008 Revision, October 2008.

December 2010 XI M5-1 NUREG-1801, Rev. 2

XI.M5 BWR FEEDWATER NOZZLE

Program Description

This program includes enhanced inservice inspection (ISI) in accordance with (a) the 

requirements of the American Society of Mechanical Engineers (ASME) Code, Section XI, 

Subsection IWB, Table IWB 2500-1 (2004 edition4

Systems modifications to mitigate cracking may have been made, such as removal of stainless 

steel cladding and installation of improved spargers. Mitigation also is accomplished by changes 

to plant-operating procedures, such as improved feedwater control to decrease the magnitude 

and frequency of temperature fluctuations. These modifications are design and operating 

changes and were instituted for many BWRs during their initial 40-year operating period.

); (b) the recommendation of General Electric 

(GE) NE-523-A71-0594, Rev. 1, Alternate BWR Feedwater Nozzle Inspection Requirements; 

and (c) NUREG-0619 recommendations for 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 

due to cyclic loading and its impact on the intended function of BWR feedwater nozzles. 

2. Preventive Actions: This program is a condition monitoring program and has no preventive 

actions. 

3. Parameters Monitored/Inspected: The aging management program (AMP) monitors for 

cracking due to cyclic loading and its impact on the intended function of the BWR feedwater 

nozzle by detection and sizing of cracks by ISI in accordance with ASME Code, Section XI, 

Subsection IWB; the recommendation of GE NE-523-A71-0594, Rev. 1; and NUREG-0619 

recommendations.

4. Detection of Aging Effects: The extent and schedule of the inspection prescribed by the 

program are designed to ensure that aging effects are discovered and repaired before the 

loss of intended function of the component. Inspection can reveal cracking. 

GE NE-523-A71-0594, Rev. 1 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, Rev. 1. 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, Rev. 1. Leakage 

monitoring may be used to modify the inspection interval.

5. Monitoring and Trending: Inspections scheduled in accordance with GE NE-523-A71-

0594, Rev. 1 provide timely detection of cracks.

6. Acceptance Criteria: Any cracking is evaluated in accordance with ASME Code, Section 

XI, IWB-3100 by comparing inspection results with the acceptance standards of ASME 

Code, Section XI, IWB-3400 and IWB-3500.

 

4 Refer to the GALL Report, Chapter I, for applicability of other editions of the ASME Code, Section XI.
NUREG-1801, Rev. 2 XI M5-2 December 2010

7. Corrective Actions: Repair and replacement are in conformance with ASME Code, Section 

XI, Subsection IWA-4000. As discussed in the Appendix for GALL, 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 10 CFR 

Part 50, Appendix B. As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B acceptable to address the confirmation 

process and administrative controls.

9. Administrative Controls: As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B acceptable to address the administrative 

controls.

10. Operating Experience: Cracking has occurred in several BWR plants (NUREG-0619, U.S. 

Nuclear Regulatory Commission [NRC] Generic Letter 81-11). This AMP has been 

implemented for nearly 30 years and has been found to be effective in managing the effects 

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, 2009.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, The 

ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 50.55a, The 

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.
December 2010 XI M6-1 NUREG-1801, Rev. 2

XI.M6 BWR CONTROL ROD DRIVE RETURN LINE NOZZLE

Program Description

This program is a condition monitoring program for boiling water reactor (BWR) control rod drive 

return line (CRDRL) nozzles that is based on the staff’s recommended position in NUREG-0619 

for thermal fatigue. This program is also intended to address stress corrosion cracking (SCC) 

discussed in NRC IN 2004-08. The augmented inspections performed in accordance with the 

recommendations in NUREG-0619 supplement those in-service inspections that are required for 

these nozzles in accordance with the American Society of Mechanical Engineers (ASME) Code, 

Section XI, Table IWB-2500-1, as mandated through reference in 10 CFR 50.55a. Thus, this 

program includes (a) mandatory in-service inspection (ISI) in accordance with the ASME Code, 

Section XI, Table IWB 2500-1 (2004 edition5

Evaluation and Technical Basis

), and (b) augmented ISI examinations in 

accordance with applicant’s commitments to U.S. Nuclear Regulatory Commission (NRC) 

Generic Letter (GL) 80-095 to implement the recommendations in NUREG-0619. 

1. Scope of Program: The program manages the effects of cracking on the intended pressure 

boundary function of CRDRL nozzles. The scope of this program is applicable to BWRs 

whose reactor vessel (RV) design includes a welded CRDRL nozzle design. The scope of 

the program includes CRDRL nozzles and their nozzle-to-RV welds, which are ASME Code 

Class 1 components. The scope of the program also includes a CRDRL nozzle cap 

(including any CRDRL nozzle-to-cap welds) if, to mitigate cracking, an applicant has cut the 

piping to the CRDRL nozzle, and capped the CRDRL nozzle.

2. Preventive Actions: Activities for preventing or mitigating cracking in CRDRL nozzles are 

consistent with a BWR facility’s past preventive or mitigation actions/activities in its current 

licensing basis as stated in the applicant’s docketed response to NRC GL 80-095 and made 

to address the recommendations in NUREG-0619. Maintaining high water purity reduces 

susceptibility to SCC. Reactor coolant water chemistry is monitored and maintained in 

accordance with the Water Chemistry Program. The program description, evaluation, and 

technical basis of water chemistry are addressed through implementation of GALL AMP

XI.M2, “Water Chemistry.”

3. Parameters Monitored/Inspected: The aging management program (AMP) manages the 

effects of cracking on the intended function of the RV, the CRDRL nozzle, and for capped 

nozzles, the nozzle caps, and cap-to-nozzle welds. For liquid penetrant test (PT) 

examinations that are implemented in accordance with this AMP, the AMP monitors for 

linear indications that may be indicative of surface breaking cracks. For the volumetric 

ultrasonic test (UT) examinations that are performed in accordance with this AMP, the AMP 

monitors and evaluates signals that may indicate the presence of a planar flaw (crack).

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 and test recommendations include PT of CRDRL nozzle bend 

radius and bore regions and the RV wall area beneath the nozzle, control rod drive system 

performance testing, and for capped nozzles, the nozzle caps and cap-to-nozzle welds. The 

 

5 Refer to the GALL Report, Chapter I, for applicability of other editions of the ASME Code, Section XI.
NUREG-1801, Rev. 2 XI M6-2 December 2010

inspection is to include base metal to a distance of one-pipe-wall thickness or 0.5 inches, 

whichever is greater, on both sides of the weld. 

5. Monitoring and Trending: The inspection schedule of NUREG-0619 provides timely 

detection of cracks. Indications of cracking are evaluated and trended in accordance with 

the ASME Code, Section XI, IWB-3100, against applicable acceptance standard criteria that 

are specified in the ASME Code, Section XI, IWB-3400 or IWB-3500.

6. Acceptance Criteria: Any cracking is evaluated in accordance with ASME Code, Section 

XI, IWB-3100 by comparing inspection results with the acceptance standards of ASME 

Code, Section XI, IWB-3400 and ASME Code, Section XI, IWB-3500. 

7. Corrective Actions Corrective action is performed in conformance with ASME Code, 

Section XI, IWA-4000. As discussed in the Appendix for GALL, 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 10 CFR 

Part 50, Appendix B. As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B acceptable to address the confirmation 

process and administrative controls.

9. Administrative Controls: As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B acceptable to address the administrative 

controls. 

10. Operating Experience: Cracking of CRDRL nozzle-to-vessel and nozzle-to-cap welds has 

occurred in several BWR plants (NUREG-0619 and Information Notice 2004-08). The 

present AMP has been implemented for nearly 30 years and has been found to be effective 

in managing the effects 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, 2009.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2009.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, The 

ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 50.55a, The 

American Society of Mechanical Engineers, New York, NY.

Letter from D. G. Eisenhut, U.S. Nuclear Regulatory Commission, to R. Gridley, General Electric 

Company, forwarding NRC Generic Technical Activity A-10, January 28, 1980.

NRC Generic Letter 80-095, (Untitled), November 13, 1980.6

 

6 This GL forwarded NUREG-0619 to members of the U.S nuclear power industry and requested that licensees 

owning BWR model reactors provide confirmation of their intent to implement the recommendations of NUREG-0619, 

as applied to the design of their BWRs.
December 2010 XI M6-3 NUREG-1801, Rev. 2

NRC Generic Letter 81-11, (Untitled), February 29, 1981.7

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-0619, BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking, 

U.S. Nuclear Regulatory Commission, November 1980.

 

7 This GL was issued primarily to provide additional clarification on the contents of the confirmatory response that 

was requested in NRC GL 80-095.

December 2010 XI M7-1 NUREG-1801, Rev. 2

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 comprehensive program outlined in NUREG-0313, Rev 2 and NRC GL 88-01 describes 

improvements that, in combination, will reduce the susceptibility to IGSCC. The elements to 

cause IGSCC consist of a susceptible (sensitized) material, a significant tensile stress, and an 

aggressive environment. Sensitization of nonstabilized austenitic stainless steels containing 

greater than 0.035 weight percent carbon involves precipitation of chromium carbides at the 

grain boundaries during certain fabrication or welding processes. The formation of carbides 

creates a 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 

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-A) report allows for modifications to the inspection extent and schedule 

described 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 in-service inspection to monitor 

IGSCC and its effects on the intended function of BWR piping components within the scope 

of license renewal. The program is applicable to all BWR piping and piping welds made of 

austenitic SS and nickel alloy that are 4 inches or larger in nominal diameter containing

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, Rev. 2 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 BWR Stress Corrosion Cracking Program is primarily a condition 

monitoring program. Maintaining high water purity reduces susceptibility to SCC or IGSCC. 

Reactor coolant water chemistry is monitored and maintained in accordance with the Water 

Chemistry Program. The program description, evaluation and technical basis of water 

chemistry are addressed through implementation of GALL AMP XI.M2, “Water Chemistry.” 

In addition, NUREG-0313, Rev. 2 and GL 88-01 delineate the guidance for selection of 

resistant materials and processes that provide resistance to IGSCC such as solution heat 

treatment and stress improvement processes.
NUREG-1801, Rev. 2 XI M7-2 December 2010

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-A 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-A are designed to maintain 

structural integrity and ensure that aging effects are discovered and repaired before the loss 

of intended function of the component. Modifications to the extent and schedule of 

inspection in NRC GL 88-01 are allowed in accordance with the inspection guidance in 

approved BWRVIP-75-A. The program uses volumetric examinations to detect IGSCC. 

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-A guidelines, provide timely 

detection of cracks and leakage of coolant. Indications of cracking are evaluated and 

trended in accordance with the American Society of Mechanical Engineers (ASME) Code, 

Section XI, IWA-3000. 

Applicable and approved BWRVIP-14-A, BWRVIP-59-A, BWRVIP-60-A, and BWRVIP-62 

reports 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.

6. Acceptance Criteria: Any cracking is evaluated in accordance with ASME Code, Section 

XI, IWA-3000 by comparing inspection results with the acceptance standards of ASME 

Code, Section XI, IWB-3000, IWC-3000 and IWD-3000 for Class 1, 2 and 3 components, 

respectively.

7. Corrective Actions: The guidance for weld overlay repair and stress improvement or 

replacement is provided in NRC GL 88-01. Corrective action is performed in accordance 

with IWA-4000. As discussed in the Appendix for GALL, 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 10 CFR 

Part 50, Appendix B. As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B acceptable to address the confirmation 

process and administrative controls. 

9. Administrative Controls: As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B acceptable to address the administrative 

controls. 

10. Operating Experience: Intergranular SCC has occurred in small- and large-diameter BWR 

piping made of austenitic SS and nickel-base alloys. Cracking has occurred in recirculation, 

core spray, residual heat removal, CRD return line penetrations, and reactor water cleanup 
December 2010 XI M7-3 NUREG-1801, Rev. 2

system piping welds (NRC GL 88-01 and NRC Information Notices [INs] 82-39, 84-41, and 

04-08). The comprehensive program outlined in NRC GL 88-01, NUREG-0313, Rev. 2, and 

in the staff-approved BWRVIP-75-A report addresses mitigating measures for SCC or 

IGSCC (e.g., susceptible material, significant tensile stress, and an aggressive 

environment). The GL 88-01 program, with or without the modifications allowed by the staffapproved BWRVIP-75-A report, has been effective in managing IGSCC in BWR reactor 

coolant pressure-retaining components and 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, 2009.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2009.

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, 2004 edition as approved in 10 CFR 50.55a, The 

American Society of Mechanical Engineers, New York, NY.

BWRVIP-14-A (EPRI 1016569), BWR Vessel and Internals Project, Evaluation of Crack Growth 

in BWR Stainless Steel RPV Internals, Final Safety Evaluation Report by the Office of 

Nuclear Reactor Regulation, September 2008. 

BWRVIP-59-A, (EPRI 1014874), BWR Vessel and Internals Project, Evaluation of Crack Growth 

in BWR Nickel-Base Austenitic Alloys in RPV Internals, Final Report by the Office of Nuclear 

Reactor Regulation, May 2007.

BWRVIP-60-A (EPRI 108871), BWR Vessel and Internals Project, Evaluation of Stress 

Corrosion Crack Growth in Low Alloy Steel Vessel Materials in the BWR Environment, Final 

Safety Evaluation Report by the Office of Nuclear Reactor Regulation, June 2003.

BWRVIP-61 (EPRI 112076), BWR Vessel and Internals Induction Heating Stress Improvement 

Effectiveness on Crack Growth in Operating Reactors, Final Safety Evaluation Report by the 

Office of Nuclear Reactor Regulation, January 29, 1999.

BWRVIP-62 (EPRI 108705), BWR Vessel and Internals Project, Technical Basis for Inspection 

Relief for BWR Internal Components with Hydrogen Injection, Final Safety Evaluation Report 

by the Office of Nuclear Reactor Regulation, March 7, 2000.

BWRVIP-75-A (EPRI 1012621), BWR Vessel and Internals Project, Technical Basis for 

Revisions to Generic Letter 88-01 Inspection Schedules (NUREG-0313), Final Safety 

Evaluation Report by the Office of Nuclear Reactor Regulation, October 2005.

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.
NUREG-1801, Rev. 2 XI M7-4 December 2010

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.

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.

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.
December 2010 XI M8-1 NUREG-1801, Rev. 2

XI.M8 BWR PENETRATIONS

Program Description

The program for boiling water reactor (BWR) vessel instrumentation penetrations, control rod 

drive (CRD) housing and incore-monitoring housing (ICMH) penetrations and standby liquid 

control (SLC) nozzles/Core ΔP nozzles includes inspection and flaw evaluation in conformance 

with the guidelines of staff-approved boiling water reactor vessel and internals project 

(BWRVIP) Topical Reports BWRVIP-49-A, BWRVIP-47-A and BWRVIP-27-A. The inspection 

and evaluation guidelines of BWRVIP-49-A, BWRVIP-47-A and BWRVIP-27-A contain generic 

guidelines intended to present appropriate inspection recommendations to assure safety 

function integrity. The guidelines of BWRVIP-49-A 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-47-A provide information on 

components located in the lower plenum region of BWRs, evaluate their susceptibility and 

consequences of failure, and define the inspection strategy to assure safe operation. The 

guidelines of BWRVIP-27-A 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 ∆P monitoring system). The BWRVIP-27-A guidelines address the region where 

the ∆P 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 BWRVIP57-A for instrumentation penetrations and BWRVIP-53-A for SLC line.

Although this is a condition monitoring program, control of water chemistry helps prevent stress 

corrosion cracking (SCC) and intergranular stress corrosion cracking (IGSCC). The water 

chemistry program for BWRs relies on monitoring and control of reactor water chemistry based 

on industry guidelines, such BWRVIP-190 (Electric Power Research Institute [EPRI] 1016579) 

or later revisions. BWRVIP-190 has three sets of guidelines: one for primary water, one for 

condensate and feedwater, and one for control rod drive (CRD) mechanism cooling water. 

Adequate aging management activities for these components provide reasonable assurance 

that the long-term integrity and safe operation of BWR vessel instrumentation nozzles, CRD 

housing and incore-monitoring housing (ICMH) penetrations and SLC nozzles/Core ΔP nozzles.

Evaluation and Technical Basis

1. Scope of Program: The scope of this program is applicable to BWR instrumentation 

penetrations, CRD housing and incore-monitoring housing (ICMH) penetrations and BWR 

SLC nozzles/Core ΔP nozzles. The program manages cracking due to cyclic loading or SCC 

and IGSCC using inspection and flaw evaluation in accordance with the guidelines of staffapproved BWRVIP-49-A, BWRVIP-47-A and BWRVIP-27-A. 

2. Preventive Actions: This program is a condition monitoring program and has no preventive 

actions. However, maintaining high water purity reduces susceptibility to SCC or IGSCC. 

The program description, evaluation and technical basis of water chemistry are presented in 

GALL AMP XI.M2, “Water Chemistry.”

3. Parameters Monitored/Inspected: The program manages the effects of cracking due to 

SCC/IGSCC on the intended function of the BWR instrumentation nozzles, CRD housing 

and incore-monitoring housing (ICMH) penetrations, and BWR SLC nozzles/Core ΔP 

nozzles. The program accomplishes this by inspection for cracks in accordance with the 
NUREG-1801, Rev. 2 XI M8-2 December 2010

guidelines of approved BWRVIP-49-A, BWRVIP-47-A or BWRVIP-27-A and the 

requirements of the ASME Code, Section XI, Table IWB 2500-1 (2004 edition8

4. Detection of Aging Effects: The evaluation guidelines of BWRVIP-49-A, BWRVIP-47-A 

and BWRVIP-27-A provide that the existing inspection requirements in ASME Code, Section 

XI, Table IWB-2500-1, are sufficient to monitor for indications of cracking in BWR 

instrumentation nozzles, CRD housing and incore-monitoring housing (ICMH) penetrations 

and BWR SLC nozzles/Core ΔP nozzles, and should continue to be followed for the period 

of extended operation. The extent and schedule of the inspection and test techniques 

prescribed by the ASME Code, Section XI program are designed to maintain structural 

integrity and ensure that aging effects are discovered and repaired before the loss of 

intended function of the component. 

).

Instrument penetrations, CRD housing and incore-monitoring housing (ICMH) penetrations 

and SLC system nozzles or housings are inspected in accordance with the requirements in 

the ASME Code, Section XI. These examination categories include volumetric examination 

methods (ultrasonic testing or radiography testing), surface examination methods (liquid 

penetrant testing or magnetic particle testing), and VT-2 visual examination methods. 

5. Monitoring and Trending: Inspections scheduled in accordance with ASME Code, Section 

XI, IWB-2400 and approved BWRVIP-49-A, BWRVIP-47-A, or BWRVIP-27-A provides 

timely detection of cracks. The scope of examination and reinspection is expanded beyond 

the baseline inspection if flaws are detected. Any indication detected is evaluated in 

accordance with ASME Code, Section XI or other acceptable flaw evaluation criteria, such 

as the staff-approved BWRVIP-49-A, BWRVIP-47-A, or BWRVIP-27-A guidelines. 

Applicable and approved BWRVIP-14-A, BWRVIP-59-A, and BWRVIP-60-A documents 

provide additional guidelines for the evaluation of crack growth in stainless steels (SSs), 

nickel alloys, and low-alloy steels, respectively.

6. Acceptance Criteria: Acceptance criteria are given in BWRVIP-49-A for instrumentation 

nozzles, BWRVIP-47-A for CRD housing and incore-monitoring housing (ICMH) 

penetrations, and BWRVIP-27A for BWR SLC nozzles/Core ΔP nozzles.

7. Corrective Actions: Repair and replacement procedures in staff-approved BWRVIP-57-A 

and BWRVIP-53-A are equivalent to those required in ASME Code, Section XI. Guidelines 

for repair design criteria are provided in BWRVIP-57-A for instrumentation penetrations and 

BWRVIP-53-A for SLC line. As discussed in the Appendix for GALL, the staff finds that 

licensee implementation of the guidelines in BWRVIP-49-A, BWRVIP-47-A, and BWRVIP27-A provides an acceptable level of quality in accordance with 10 CFR Part 50, Appendix B 

corrective actions. However, any repair in accordance with ASME Code is acceptable.

8. Confirmation Process: Site quality assurance 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 for GALL, the staff finds that licensee 

implementation of the guidelines in BWRVIP-49-A, BWRVIP-47-A, and BWRVIP-27A, as 

modified, provides 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.

 

8 Refer to the GALL Report, Chapter I, for applicability of other editions of the ASME Code, Section XI. 
December 2010 XI M8-3 NUREG-1801, Rev. 2

9. Administrative Controls: As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B acceptable to address the administrative 

controls.

10. Operating Experience: Cracking due to SCC or IGSCC has occurred in BWR components 

made of austenitic SSs 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 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, 2009.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2009.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, The 

ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 50.55a, The 

American Society of Mechanical Engineers, New York, NY.

BWRVIP-14-A (EPRI 1016569), BWR Vessel and Internals Project, Evaluation of Crack Growth 

in BWR Stainless Steel RPV Internals, Final Safety Evaluation Report by the Office of 

Nuclear Reactor Regulation, September 2008. 

BWRVIP-27-A (EPRI 1007279), BWR Vessel and Internals Project, BWR Standby Liquid 

Control System/Core Plate ∆P Inspection and Flaw Evaluation Guidelines, Final Safety 

Evaluation Report by the Office of Nuclear Reactor Regulation, August 2003.

BWRVIP-47-A (EPRI 1009947), BWR Vessel and Internals Project, BWR Lower Plenum 

Inspection and Flaw Evaluation Guidelines, Final Safety Evaluation Report by the Office of 

Nuclear Reactor Regulation, November 2004.

BWRVIP-49-A (EPRI 1006602), BWR Vessel and Internals Project, Instrument Penetration 

Inspection and Flaw Evaluation Guidelines, Final Safety Evaluation Report by the Office of 

Nuclear Reactor Regulation.

BWRVIP-53-A (EPRI 1012120), BWR Vessel and Internals Project, Standby Liquid Control Line 

Repair Design Criteria Final Safety Evaluation Report by the Office of Nuclear Reactor 

Regulation, September 2005.

BWRVIP-57-A (EPRI 1012111), BWR Vessel and Internals Project, Instrument Penetration 

Repair Design Criteria, Final Safety Evaluation Report by the Office of Nuclear Reactor 

Regulation, September 2005.
NUREG-1801, Rev. 2 XI M8-4 December 2010

BWRVIP-59-A (EPRI 1014874), BWR Vessel and Internals Project, Evaluation of Crack Growth 

in BWR Nickel-Base Austenitic Alloys in RPV Internals, Final Safety Evaluation Report by 

the Office of Nuclear Reactor Regulation, May 2007.

BWRVIP-60-A (EPRI 1008871), BWR Vessel and Internals Project, Evaluation of Stress 

Corrosion Crack Growth in Low Alloy Steel Vessel Materials in the BWR Environment, Final 

Safety Evaluation Report by the Office of Nuclear Reactor Regulation, June 2003.

BWRVIP-190 (EPRI 1016579), BWR Vessel and Internals Project, BWR Water Chemistry 

Guidelines-2008 Revision, Final Safety Evaluation Report by the Office of Nuclear Reactor 

Regulation, October 2008.
December 2010 XI M9-1 NUREG-1801, Rev. 2

XI.M9 BWR VESSEL INTERNALS

Program Description

The program includes inspection and flaw evaluations in conformance with the guidelines of 

applicable and staff-approved boiling water reactor vessel and internals project (BWRVIP) 

documents to provide reasonable assurance of the long-term integrity and safe operation of 

boiling water reactor (BWR) vessel internal components.

The BWRVIP documents provide generic guidelines intended to present the applicable 

inspection recommendations to assure safety function integrity of the subject safety-related 

reactor pressure vessel internal components. The guidelines provide 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.

In addition, this program provides screening criteria to determine the susceptibility of cast 

austenitic stainless steels (CASS) components to thermal aging on the basis of casting method, 

molybdenum content, and percent ferrite, in accordance with 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 steels (SA-351 Grades CF3, CF3A, CF8, CF8A, or other 

steels with ≤0.5 wt.% molybdenum), 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 

steels (SA-351 Grades CF3M, CF3MA, CF8M or other steels with 2.0 to 3.0 wt.% molybdenum), 

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 staff approved method for calculating delta 

ferrite in CASS materials.

The screening criteria are applicable to all cast stainless steel primary pressure boundary and 

reactor vessel internal components 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 considers loss of fracture toughness due to neutron embrittlement or

thermal aging embrittlement.

This AMP addresses aging degradation of X-750 alloy-, and precipitation-hardened (PH) 

martensitic stainless steel (e.g., 15-5 and 17-4 PH steel) materials and martensitic stainless 

steel (e.g., 403, 410, 431 steel) that are used in BWR vessel internal components. When 

exposed to a BWR reactor temperature of 550°F, these materials can experience neutron 

embrittlement and a decrease in fracture toughness. PH-martensitic stainless steels and 

martensitic stainless steels are also susceptible to thermal embrittlement. Effects of thermal and 

neutron embrittlement can cause failure of these materials in vessel internal components. In 

addition, X-750 alloy in a BWR environment is susceptible to intergranular stress corrosion 

cracking (IGSCC).
NUREG-1801, Rev. 2 XI M9-2 December 2010

Evaluation and Technical Basis

1. Scope of Program: The program is focused on managing the effects of cracking due to 

stress corrosion cracking (SCC), IGSCC, or irradiation-assisted stress corrosion cracking 

(IASCC), cracking due to fatigue and loss of material due to wear. This program also 

includes loss of toughness due to neutron and thermal embrittlement. The program applies 

to wrought and cast reactor vessel internal components. The program contains in-service 

inspection (ISI) to monitor the effects of cracking on the intended function of the 

components, uses NRC-approved BWRVIP reports as the basis for inspection, evaluation, 

repair and/or replacement, as needed, and evaluates the susceptibility of CASS, X-750 

alloy, precipitation-hardened (PH) martensitic stainless steel (e.g., 15-5 and 17-4 PH steel), 

and martensitic stainless steel (e.g., 403, 410, 431 steel) components to neutron and/or 

thermal embrittlement.

The scope of the program includes the following BWR reactor vessel (RV) and RV internal 

components as subject to the following NRC-approved applicable BWRVIP guidelines:

Core shroud: BWRVIP-76-A provides guidelines for inspection and evaluation; 

BWRVIP-02-A, Rev. 2, provides guidelines for repair design criteria.

Core plate: BWRVIP-25 provides guidelines for inspection and evaluation; BWRVIP-50-A 

provides guidelines for repair design criteria.

Core spray: BWRVIP-18-A provides guidelines for inspection and evaluation; BWRVIP-16-A 

and 19A provides guidelines for replacement and repair design criteria, respectively.

Shroud support: BWRVIP-38 provides guidelines for inspection and evaluation; 

BWRVIP-52-A provides guidelines for repair design criteria.

Jet pump assembly: BWRVIP-41 provides guidelines for inspection and evaluation; 

BWRVIP-51-A provides guidelines for repair design criteria.

Low-pressure coolant injection (LPCI) coupling: BWRVIP-42-A provides guidelines for 

inspection and evaluation; BWRVIP-56-A provides guidelines for repair design criteria.

Top guide: BWRVIP-26-A and BWRVIP-183 provide guidelines for inspection and 

evaluation; BWRVIP-50-A provides guidelines for repair design criteria. 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. 

Reinspection Criteria:

BWR/2-5 - Inspect 10% of the grid beam cells containing control rod drives/blades every 

twelve years with at least 5% to be performed within six years. 

BWR/6 - Inspect the rim areas containing the weld and heat affected zone (HAZ) from the 

top surface of the top guide and two cells in the same plane/axis as the weld every six 

years.
December 2010 XI M9-3 NUREG-1801, Rev. 2

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-to-beam 

crevice slots.

Control rod drive (CRD) housing: BWRVIP-47-A provides guidelines for inspection and 

evaluation; BWRVIP-58-A provides guidelines for repair design criteria.

Lower plenum components: BWRVIP-47-A provides guidelines for inspection and 

evaluation; BWRVIP-57-A provides guidelines for repair design criteria for instrument 

penetrations.

Steam Dryer: BWRVIP-139 provides guidelines for inspection and evaluation for the steam 

dryer components.

Although BWRVIP repair design criteria provide criteria for repairs, aging management 

strategies for repairs are provided by the repair designer, not the BWRVIP.

2. Preventive Actions: The BWR Vessel Internals Program is a condition monitoring program 

and has no preventive actions. Maintaining high water purity reduces susceptibility to SCC 

or IGSCC. Reactor coolant water chemistry is monitored and maintained in accordance with 

the Water Chemistry Program. The program description, evaluation and technical basis of 

water chemistry are presented in GALL AMP XI.M2, “Water Chemistry.” In addition, for core 

shroud repairs or other IGSCC repairs, the program maintains operating tensile stresses 

below a threshold limit that precludes IGSCC of X-750 material.

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 (2004 edition9

Loss of fracture toughness due to neutron embrittlement in CASS materials can occur with a 

neutron fluence greater than 1x1017 n/cm2 (E>1 MeV). Loss fracture toughness of CASS 

material due to thermal embrittlement is dependent on the material’s casting method, 

molybdenum content, and ferrite content. The program does not directly monitor for loss of 

fracture toughness that is induced by thermal aging or neutron irradiation embrittlement. The 

impact of loss of fracture toughness on component integrity is indirectly managed by using 

visual or volumetric examination techniques to monitor for cracking in the components. 

). 

Neutron embrittlement of X-750 alloys, PH-martensitic stainless steels, and martensitic 

stainless steels cannot be identified by typical in-service inspection activities. However, by 

performing visual or other inspections, applicants can identify cracks that could lead to 

failure of a potentially embrittled component prior to component failure. Applicants can thus 

indirectly manage the effects of embrittlement in the PH steels, martensitic stainless steels, 

and X-750 components by identifying aging degradation (i.e., cracks), implementing early 

corrective actions, and monitoring and trending age-related degradation.

 

9 Refer to the GALL Report, Chapter I, for applicability of other editions of the ASME Code, Section XI. 
NUREG-1801, Rev. 2 XI M9-4 December 2010

4. Detection of Aging Effects: The extent and schedule of the inspection and test techniques 

prescribed by the applicable and NRC-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 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. BWRVIP program requirements provide for inspection of BWR 

reactor internals to manage loss of material and cracking using appropriate examination 

techniques such as visual examinations (e.g., EVT-1, VT-1) and volumetric examinations 

(e.g., UT).

The applicable and NRC-approved BWRVIP guidelines recommend more stringent 

inspections, such as EVT-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.

Thermal and/or neutron embrittlement in susceptible CASS, PH-martensitic steels, 

martensitic stainless steels, and X-750 components are indirectly managed by performing 

periodic visual inspections capable of detecting cracks in the component. The 10-year ISI 

program during the renewal period may include a supplemental inspection covering portions 

of the susceptible components determined to be limiting from the standpoint of thermal 

aging susceptibility, 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 VT-1 examination of ASME Code, Section XI, 

IWA-2210. The initial inspection is performed either prior to or within 5 years after entering 

the period of extended operation. If cracking is detected after the initial inspection, the 

frequency of re-inspection should be justified by the applicant based on fracture toughness 

properties appropriate for the condition of the component. The sample size is 100% of the 

accessible component population, excluding components that may be in compression during 

normal operations.

5. Monitoring and Trending: Inspections are scheduled in accordance with the applicable 

and approved BWRVIP guidelines provide timely detection of cracks. Each BWRVIP

guideline recommends baseline inspections that are used as part of data collection towards 

trending. The BWRVIP guidelines provide recommendations for expanding the sample 

scope and re-inspecting the components if flaws are detected. Any indication detected is 

evaluated in accordance with ASME Code, Section XI or the applicable BWRVIP guidelines. 

BWRVIP-14-A, BWRVIP-59-A, BWRVIP-60-A, BWRVIP-80NP-A and BWRVIP-99-A 

documents provide additional guidelines for evaluation of crack growth in stainless steels 

(SSs), nickel alloys, and low-alloy steels, respectively.
December 2010 XI M9-5 NUREG-1801, Rev. 2

Inspections scheduled in accordance with ASME Code, Section XI, IWB-2400 and reliable 

examination methods provide timely detection of cracks. The fracture toughness of PHmartensitic steels, martensitic stainless steels, and X-750 alloys susceptible to thermal 

and/or neutron embrittlement need to be assessed on a case-by-case basis.

6. Acceptance Criteria: Acceptance criteria are given in the applicable BWRVIP documents 

or ASME Code, Section XI. Flaws detected in CASS components are evaluated in 

accordance with the applicable procedures of ASME Code, Section XI, IWB-3500. Flaw 

tolerance evaluation for components with ferrite content up to 25% is performed according 

to the principles associated with ASME Code, Section XI, IWB-3640 procedures for SAWs, 

disregarding the ASME Code restriction of 20% ferrite. 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 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. 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 susceptible to thermal aging embrittlement and those that are not. 

Extensive research data indicate that for non-susceptible CASS materials, the saturated 

lower-bound fracture toughness is greater than 255 kJ/m2 (NUREG/CR-4513, Rev. 1).

Acceptance criteria for the assessment of PH-martensitic steels, martensitic stainless steels, 

and X-750 alloys susceptible to thermal aging and/or neutron embrittlement are assessed 

on a case-by-case basis.

7. Corrective Actions: Repair and replacement procedures are equivalent to those 

requirements in ASME Code Section XI. Repair and replacement is performed in 

conformance with the applicable and NRC-approved BWRVIP guidelines listed above. For 

top guides where cracking is observed, sample size and inspection frequencies are 

increased. As discussed in the Appendix for GALL, the staff finds that licensee 

implementation of the corrective action guidelines in the staff-approved BWRVIP reports will 

provide an acceptable level of quality accordance with 10 CFR Part 50, Appendix B. 

8. Confirmation Process: Site quality assurance 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 for GALL, 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: As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B acceptable to address the administrative 

controls.

10. Operating Experience: There is documentation of cracking in both the circumferential and 

axial core shroud welds, and in shroud supports. Extensive cracking of circumferential core 

shroud welds has been documented in NRC Generic Letter 94-03 and extensive cracking in 

vertical core shroud welds has been documented in NRC Information Notice 97-17. 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 
NUREG-1801, Rev. 2 XI M9-6 December 2010

the welds or the high residual stresses in 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) have been 

observed in the shroud support access hole covers that are made from Alloy 600. Instances 

of cracking in core spray spargers have been reviewed in NRC Bulletin 80-13, and cracking 

in core spray pipe has been reviewed in BWRVIP-18.

Cracking of the core plate has not been reported, but the creviced regions beneath the plate 

are difficult to inspect. BWRVIP-06R1-A and BWRVIP-25 address the safety significance 

and inspection requirements for the core plate assembly. Only inspection of core plate bolts 

(for plants without retaining wedges) or inspection of the retaining wedges is required. 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.

Two CRDM lead screw male couplings were fractured in a pressurized-water reactor (PWR), 

designed by Babcock and Wilcox (B&W), at Oconee Nuclear Station (ONS), Unit 3. The 

fracture was due to thermal embrittlement of 17-4 PH material (NRC IN 2007-02). While this 

occurred at a PWR, it also needs to be considered for BWRs.

IGSCC in the X-750 materials of a tie rod coupling and jet pump hold-down beam was 

observed in a domestic plant.

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, 2009.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2009.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, The 

ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 50.55a, The 

American Society of Mechanical Engineers, New York, NY.
December 2010 XI M9-7 NUREG-1801, Rev. 2

BWRVIP-02-A (EPRI 1012837), BWR Vessel and Internals Project, BWR Core Shroud Repair 

Design Criteria, Final Safety Evaluation Report by the Office of Nuclear Reactor Regulation, 

October 2005.

BWRVIP-03 (EPRI 105696 R1, March 30, 1999), BWR Vessel and Internals Project, Reactor 

Pressure Vessel and Internals Examination Guidelines, Final Safety Evaluation Report by 

the Office of Nuclear Reactor Regulation, July 15, 1999.

BWRVIP-14-A (EPRI 1016569), BWR Vessel and Internals Project, Evaluation of Crack Growth 

in BWR Stainless Steel RPV Internals, Final Safety Evaluation Report by the Office of 

Nuclear Reactor Regulation, September 2008.

BWRVIP-16-A (EPRI 1012113), BWR Vessel and Internals Project, Internal Core Spray Piping 

and Sparger Replacement Design Criteria, Final Safety Evaluation Report by the Office of 

Nuclear Reactor Regulation, September 2005.

BWRVIP-18-A (EPRI 1011469), BWR Vessel and Internals Project, BWR Core Spray Internals 

Inspection and Flaw Evaluation Guidelines, Final Safety Evaluation Report by the Office of 

Nuclear Reactor Regulation, February 2005. 

BWRVIP-19-A (EPRI 1012114), BWR Vessel and Internals Project, Internal Core Spray Piping 

and Sparger Repair Design Criteria, Final Safety Evaluation Report by the Office of Nuclear 

Reactor Regulation, September 2005.

BWRVIP-25 (EPRI 107284), BWR Vessel and Internals Project, BWR Core Plate Inspection 

and Flaw Evaluation Guidelines, 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-A (EPRI 1009946), BWR Vessel and Internals Project, BWR Top Guide Inspection 

and Flaw Evaluation Guidelines, Final Safety Evaluation Report by the Office of Nuclear 

Reactor Regulation, November 2004.

BWRVIP-38 (EPRI 108823), BWR Vessel and Internals Project, BWR Shroud Support 

Inspection and Flaw Evaluation Guidelines, 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 (EPRI 108728), BWR Vessel and Internals Project, BWR Jet Pump Assembly 

Inspection and Flaw Evaluation Guidelines, 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-A (EPRI 1011470), BWR Vessel and Internals Project, BWR LPCI Coupling 

Inspection and Flaw Evaluation Guidelines, Final Safety Evaluation Report by the Office of 

Nuclear Reactor Regulation, February 2005.

BWRVIP-44-A (EPRI 1014352), BWR Vessel and Internals Project, Underwater Weld Repair of 

Nickel Alloy Reactor Vessel Internals, Final Safety Evaluation Report by the Office of 

Nuclear Reactor Regulation, August 2006.
NUREG-1801, Rev. 2 XI M9-8 December 2010

BWRVIP-45 (EPRI 108707), BWR Vessel and Internals Project, Weldability of Irradiated LWR 

Structural Components, Final Safety Evaluation Report by the Office of Nuclear Reactor 

Regulation, June 14, 2000.

BWRVIP-47-A (EPRI 1009947), BWR Vessel and Internals Project, BWR Lower Plenum 

Inspection and Flaw Evaluation Guidelines, Final Safety Evaluation Report by the Office of 

Nuclear Reactor Regulation, November 2004.

BWRVIP-50-A (EPRI 1012110), BWR Vessel and Internals Project, Top Guide/Core Plate 

Repair Design Criteria, Final Safety Evaluation Report by the Office of Nuclear Reactor 

Regulation, September 2005.

BWRVIP-51-A (EPRI 1012116), BWR Vessel and Internals Project, Jet Pump Repair Design 

Criteria, Final Safety Evaluation Report by the Office of Nuclear Reactor Regulation, 

September 2005.

BWRVIP-52-A (EPRI 1012119), BWR Vessel and Internals Project, Shroud Support and Vessel 

Bracket Repair Design Criteria, Final Safety Evaluation Report by the Office of Nuclear 

Reactor Regulation, September 2005.

BWRVIP-56-A (EPRI 1012118), BWR Vessel and Internals Project, LPCI Coupling Repair 

Design Criteria, Final Safety Evaluation Report by the Office of Nuclear Reactor Regulation, 

September 2005.

BWRVIP-57-A (EPRI 1012111), BWR Vessel and Internals Project, Instrument Penetration 

Repair Design Criteria, Final Safety Evaluation Report by the Office of Nuclear Reactor 

Regulation, September 2005.

BWRVIP-58-A (EPRI 1012618), BWR Vessel and Internals Project, CRD Internal Access Weld 

Repair, Final Safety Evaluation Report by the Office of Nuclear Reactor Regulation, October 

2005.

BWRVIP-59-A (EPRI 1014874), BWR Vessel and Internals Project, Evaluation of Crack Growth 

in BWR Nickel-Base Austenitic Alloys in RPV Internals, Final Safety Evaluation Report by 

the Office of Nuclear Reactor Regulation, May 2007.

BWRVIP-60-A (EPRI 1008871), BWR Vessel and Internals Project, Evaluation of Stress 

Corrosion Crack Growth in Low Alloy Steel Vessel Materials in the BWR Environment, Final 

Safety Evaluation Report by the Office of Nuclear Reactor Regulation, June 2003.

BWRVIP-62 (EPRI 108705), BWR Vessel and Internals Project, Technical Basis for Inspection 

Relief for BWR Internal Components with Hydrogen Injection, March 7, 2000.

BWRVIP-76-A (EPRI 1019057), BWR Vessel and Internals Project, BWR Core Shroud 

Inspection and Flaw Evaluation Guidelines, December 2009.

BWRVIP-80NP-A, (EPRI 1015457NP), BWR Vessel and Internals Project, Evaluation of Crack 

Growth in BWR Shroud Vertical Welds, October 2007.

BWRVIP 99 A, (EPRI 1016566), BWR Vessel and Internals Project, Crack Growth Rates in 

Irradiated Stainless Steels in BWR Internal Components, Final Report, October 2008.
December 2010 XI M9-9 NUREG-1801, Rev. 2

BWRVIP-139 (EPRI 1011463), BWR Vessel and Internals Project, Steam Dryer Inspection and 

Flaw Evaluation Guidelines, Final Safety Evaluation Report by the Office of Nuclear Reactor 

Regulation, April 2005.

BWRVIP-167NP (EPRI 1018111) Rev. 1: BWR Vessel and Internals Project Boiling Water 

Reactor Issue Management Tables, Final Report, September 2008.

BWRVIP-181 (EPRI 1013403), BWR Vessel and Internals Project, Steam Dryer Repair Design 

Criteria, Final Safety Evaluation Report by the Office of Nuclear Reactor Regulation, 

November 2007. 

BWRVIP-183 (EPRI 1013401), BWR Vessel and Internals Project, Top Guide Beam Inspection 

and Flaw Evaluation Guidelines, December 2007.

BWRVIP-190 (EPRI 1016579), BWR Vessel and Internals Project: BWR Water Chemistry 

Guidelines—2008 Revision, October 2008.

EPRI 1016486, Primary System Corrosion Research Program, EPRI Materials Degradation 

Matrix, Rev. 1, Final Report, May 2008. 

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)

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.

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 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.
NUREG-1801, Rev. 2 XI M9-10 December 2010

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.

NRC Information Notice 2007-02, Failure of Control Rod Drive Mechanism Lead Screw Male 

Coupling at Babcock and Wilcox-Designed Facility. (ADAMS Accession No. ML070100459)

NUREG-1544, Status Report: Intergranular Stress Corrosion Cracking of BWR Core Shrouds 

and Other Internal Components, U.S. Nuclear Regulatory Commission, March 1996.

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/CR-6923, P. L. Andresen, F. P. Ford, K. Gott, R. L. Jones, P. M. Scott, T. Shoji, R. W. 

Staehle, and R. L. Tapping, Expert Panel Report on Proactive Materials Degradation 

Assessment, U.S. Nuclear Regulatory Commission, Washington, DC, 3895 pp. March 2007.

Xu, H. and Fyfitch, S., Fracture of Type 17-4 PH CRDM Lead Screw Male Coupling Tangs. The 

11th International Conference on Environmental Degradation of Materials in Nuclear Power 

Systems-Water Reactors, ANS: Stevenson, WA (2003).
December 2010 XI M10-1 NUREG-1801, Rev. 2

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 because 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 NRC GL 88-05 may affect structures and components that are 

subject to aging management review (AMR). Therefore, the scope of the monitoring and 

inspections of this program includes all components that contain borated water and that are in 

proximity to structures and components that are subject to AMR. 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 through 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. The effects of 

boric acid corrosion on reactor coolant pressure boundary materials in the vicinity of nickel alloy 

components are managed by GALL AMP XI.M11B, “Cracking of Nickel-Alloy Components and 

Loss of Material Due to Boric Acid-induced Corrosion in Reactor Coolant Pressure Boundary

Components.”

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, copper alloy >15% zinc, and aluminum) and electrical 

components onto which borated reactor water may leak. The program includes provisions in 

response to the recommendations of NRC GL 88-05. 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) examinations 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: This program is a condition monitoring program; thus, there are no 

preventive actions. However, 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. 

3. Parameters Monitored/Inspected: The aging management program monitors the aging 

effects of loss of material due to boric acid corrosion on the intended function of an affected 
NUREG-1801, Rev. 2 XI M10-2 December 2010

structure and component by detection of borated water leakage. Borated water leakage 

results in deposits of white boric acid crystals and the presence of moisture that can be 

observed by visual examination. Boric acid deposits, borated water leakage, or the presence 

of moisture that could lead to the identification of loss of material can be monitored through 

visual examination.

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. However, for 

leakage examinations of components with external insulation surfaces and joints under 

insulation or not visible for direct visual examination, the surrounding area (including the 

floor, equipment surfaces, and other areas where leakage may be channeled) is examined 

for evidence of component leakage. Discoloration, staining, boric acid residue, and other 

evidence of leakage on insulation surfaces and the surrounding area are given particular 

consideration as evidence of component leakage. If evidence of leakage is found, removal 

of insulation to determine the exact source may be required. 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 assures 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, white or discolored crystal 

buildup, or rust-colored deposits are 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: The NRC finds that the requirements of 10 CFR Part 50, Appendix B, 

with additional consideration of the guidance in NRC GL 88-05, are acceptable to implement 

the corrective actions related to this program. Borated water leakage and areas of resulting 

boric acid corrosion are evaluated and corrected in accordance 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.

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 for GALL, the 
December 2010 XI M10-3 NUREG-1801, Rev. 2

staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: The administrative controls for this program provide for a formal 

review and approval of corrective actions. The administrative controls for this program are 

implemented through the site's QA program in accordance with the requirements of 10 CFR 

Part 50, Appendix B.

10. Operating Experience: Boric acid corrosion has been observed in nuclear power plants 

(NRC Information Notice [IN] 86-108 [and supplements 1 through 3] and NRC IN 2003-02) 

and has resulted in significant impairment of component-intended functions in areas that are 

difficult to access/observe (NRC Bulletin 2002-01). 

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2009.

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, 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-1823, U.S. Plant Experience with Alloy 600 Cracking and Boric Acid Corrosion of LightWater Reactor Pressure Vessel Materials, U.S. Nuclear Regulatory Commission, April 2005.

December 2010 XI M11B-1 NUREG-1801, Rev. 2

XI.M11B CRACKING OF NICKEL-ALLOY COMPONENTS AND LOSS OF MATERIAL DUE

TO BORIC ACID-INDUCED CORROSION IN REACTOR COOLANT PRESSURE 

BOUNDARY COMPONENTS (PWRs ONLY)

Program Description

This program replaces AMPs XI.M11, “Nickel-Alloy Nozzles and Penetrations” and XI.M11A, 

“Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of 

Pressurized Water Reactors.” It addresses the issue of cracking of nickel-alloy components and 

loss of material due to boric acid-induced corrosion in susceptible, safety-related components in 

the vicinity of nickel-alloy reactor coolant pressure boundary components. A final rule 

(September 2008) updating 10 CFR 50.55a requires the following American Society of 

Mechanical Engineer (ASME) Boiler and Pressure Vessel (B&PV) Code Cases: (a) N-722, 

“Additional Examinations for PWR Pressure Retaining Welds in Class 1 Components Fabricated 

with Alloy 600/82/182 Materials, Section XI, Division 1” to establish long-term inspection 

requirements for the pressurized water reactor (PWR) vessel, steam generator, pressurizer 

components and piping if they contain the primary water stress corrosion cracking (PWSCC) 

susceptible materials designated alloys 600/82/182; and (b) N-729-1, “Alternative Examination 

Requirements for PWR Reactor Vessel Upper Heads With Nozzles Having Pressure-Retaining 

Partial-Penetration Welds, Section XI, Division 1” to establish new requirements for the longterm inspection of reactor pressure vessel upper heads. 

In addition, dissimilar metal welds need additional examinations to provide reasonable 

assurance of structural integrity. The U.S. Nuclear Regulatory Commission (NRC) issued 

Regulatory Information Summary (RIS) 2008-25, “Regulatory Approach for Primary Water 

Stress Corrosion Cracking (PWSCC) of Dissimilar Metal Butt Welds in Pressurized Water 

Reactor Primary Coolant System Piping” (October 2008) which stated the regulatory approach 

for addressing PWSCC of dissimilar metal butt welds. The RIS documents the NRC’s approach 

to ensuring the integrity of primary coolant system piping containing dissimilar metal butt welds 

in PWRs and, in conjunction with the mandated inspections of ASME Code Case N-722, 

ensures that augmented in-service inspections (ISI) of all nickel-based alloy components and 

welds in the reactor coolant system (RCS) continue to perform their intended functions. 

As stated in this RIS, the NRC has found that MRP-139, “Primary System Piping Butt Weld 

Inspection and Evaluation Guideline” (2005), and MRP interim guidance letters provide 

adequate protection of public health and safety for addressing PWSCC in dissimilar metal butt 

welds pending the incorporation of ASME Code Case N-770, containing comprehensive 

inspection requirements, into 10 CFR 50.55a. It is the intention of the NRC to replace MRP-139 

by incorporating the requirements of ASME Code Case N-770 into 10 CFR 50.55a. 

The impacts of boric acid leakage from non-nickel alloy reactor coolant pressure boundary 

components are addressed in AMP XI.M10, “Boric Acid Corrosion.” The Water Chemistry 

program for PWRs relies on monitoring and control of reactor water chemistry based on industry 

guidelines as described in AMP XI.M2, “Water Chemistry.”

Evaluation and Technical Basis

1. Scope of Program: The program is focused on managing the effects of cracking due to 

PWSCC of all susceptible nickel alloy-based components of the reactor coolant pressure 

boundary (including nickel-alloy welds). The program also manages the loss of material due 

to boric acid corrosion in susceptible components in the vicinity of nickel-alloy components. 
NUREG-1801, Rev. 2 XI M11B-2 December 2010

These components could include, but are not limited to, the reactor vessel components 

(reactor pressure vessel upper head), steam generator components (nozzle-to-pipe 

connections, instrument connections, and drain tube penetrations), pressurizer components 

(nozzle-to-pipe connections, instrument connections, and heater penetrations), and reactor 

coolant system piping (instrument connections and full penetration welds). 

2. Preventive Actions: This program is a condition monitoring program and does not include 

preventive or mitigative measures. However, maintaining high water purity reduces 

susceptibility to PWSCC. Reactor coolant water chemistry is monitored and maintained in 

accordance with the Water Chemistry program. The program description and the evaluation 

and technical basis of monitoring and maintaining reactor water chemistry are presented in 

GALL AMP XI.M2, “Water Chemistry.” 

At the discretion of the applicant, preventive actions to mitigate PWSCC may be addressed 

by various measures (e.g., weld overlays, replacement of components with more PWSCCresistant materials, etc.). 

3. Parameters Monitored/Inspected: This is a condition monitoring program that monitors 

cracking/PWSCC for nickel-alloy components and loss of material by boric acid corrosion for 

potentially affected steel component. Reactor coolant pressure boundary cracking and 

leakage are monitored by the applicant’s in-service inspection program in accordance with 

10 CFR 50.55a and industry guidelines (e.g., MRP-139). Boric acid deposits, borated water 

leakage, or the presence of moisture that could lead to the identification of cracking or loss 

of material can be monitored through visual examination.

4. Detection of Aging Effects: The program detects the effect of aging by various methods, 

including non-destructive examination techniques. Reactor coolant pressure boundary 

leakage can be monitored through the use of radiation air monitoring and other general area 

radiation monitoring, and technical specifications for reactor coolant pressure boundary 

leakage. The specific types of non-destructive examinations are dependent on the 

component’s susceptibility to PWSCC and its accessibility to inspection. Inspection 

methods, schedules, and frequencies for the susceptible components are implemented in 

accordance with 10 CFR 50.55a and industry guidelines (e.g., MRP-139). 

5. Monitoring and Trending: Reactor coolant pressure boundary leakage is calculated and 

trended on a routine basis in accordance with technical specification to detect changes in 

the leakage rates. Flaw evaluation through 10 CFR 50.55a is a means to monitor cracking.

6. Acceptance Criteria: Acceptance criteria for all indications of cracking and loss of material 

due to boric acid-induced corrosion are defined in 10 CFR 50.55a and industry guidelines 

(e.g., MRP-139).

7. Corrective Actions: Relevant flaw indications of susceptible components within the scope 

of this program found to be unacceptable for further services are corrected through 

implementation of appropriate repair or replacement as dictated by 10 CFR 50.55a and 

industry guidelines (e.g., MRP-139). In addition, detection of leakage or evidence of 

cracking in susceptible components within the scope of this program require scope 

expansion of current inspection and increased inspection frequencies of some components, 

as required by 10 CFR 50.55a and industry guidelines (e.g., MRP-139).
December 2010 XI M11B-3 NUREG-1801, Rev. 2

Repair and replacement procedures and activities must either comply with ASME Section 

XI, as incorporated in 10 CFR 50.55a or conform to applicable ASME Code Cases that have 

been endorsed in 10 CFR 50.55a by referencing the latest version of NRC Regulatory Guide 

1.147. 

As discussed in the Appendix for GALL, 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 and review and approval 

processes are implemented in accordance with the requirements of 10 CFR Part 50, 

Appendix B. As discussed in the Appendix for GALL, 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: This new program addresses reviews of related operating 

experience, including plant-specific information, generic industry findings, and international 

data. Within the current regulatory requirements, as necessary, the applicant maintains a 

record of operating experience through the required update of the facility’s inservice 

inspection program in accordance with 10 CFR 50.55a. Additionally, the applicant follows 

mandated industry guidelines developed to address operating experience in accordance 

with NEI-03-08, “Guideline for the Management of Materials Issues.”

Cracking of Alloy 600 has occurred in domestic and foreign PWRs (NRC Information Notice 

[IN] 90-10). Furthermore, ingress of demineralizer resins also has occurred in operating 

plants (NRC IN 96-11). The Water Chemistry program, AMP XI.M2, manages the effects of 

such excursions through monitoring and control of primary water chemistry. NRC GL 97-01 

is effective in managing the effect of PWSCC. PWSCC also is occurring in the vessel head 

penetration (VHP) nozzle of U.S. PWRs as described in NRC Bulletins 2001-01, 2002-01 

and 2002-02. 

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009. 

10 CFR Part 50.55a, Codes and Standards, Office of the Federal Register, National Archives 

and Records Administration, 2009. 

ASME Code Case N-722, Additional Examinations for PWR Pressure Retaining Welds in Class 

1 Components Fabricated with Alloy 600/82/182 Materials, July 5, 2005.

ASME Code Case N-729-1, Alternative Examination Requirements for PWR Reactor Vessel 

Upper Heads with Nozzles Having Pressure-Retaining Partial-Penetration Welds, March 28, 

2006.

ASME Code Case N-770, Alternative Examination Requirements and Acceptance Standards for 

Class 1 PWR Piping and Vessel Nozzle Butt Welds Fabricated with UNS N06082 or UNS 
NUREG-1801, Rev. 2 XI M11B-4 December 2010

W86182 Weld Filler Material With or Without Application of Listed Mitigation Activities, 

January 26, 2009.

MRP-139, Revision 1, Primary System Piping Butt Weld Inspection and Evaluation Guideline, 

Materials Reliability Program, December 16, 2008.

NEI-03-08, Guideline for the Management of Materials Issues, Nuclear Energy Institute, 

May 2003.

NRC Bulletin 2001-01, Circumferential Cracking of Reactor Pressure Vessel Head Penetration 

Nozzles, U.S. Nuclear Regulatory Commission, August 3, 2001. 

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 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 90-10, Primary Water Stress Corrosion Cracking (PWSCC) of Inconel 

600, U.S. Nuclear Regulatory Commission, February 23, 1990.

NRC Information Notice 96-11, Ingress of Demineralizer Resins Increases Potential for Stress 

Corrosion Cracking of Control Rod Drive Mechanism Penetrations, U.S. Nuclear Regulatory 

Commission, February 14, 1996.

NRC Inspection Manual, Inspection Procedure 71111.08, Inservice Inspection Activities, March 

23, 2009.

NRC Inspection Manual, Temporary Instruction 2515/172, Reactor Coolant System Dissimilar 

Metal Butt Welds, February 21, 2008.

NRC Regulatory Guide 1.147, Revision 15, Inservice Inspection Code Case Acceptability, 

ASME Section XI, Division 1, U.S. Nuclear Regulatory Commission, January 2004.

NRC Regulatory Information Summary 2008-25, Regulatory Approach for Primary Water Stress 

Corrosion Cracking of Dissimilar Metal Butt Welds in Pressurized Water Reactor Primary 

Coolant System Piping, U.S. Nuclear Regulatory Commission, October 22, 2008.

NUREG-1823, U.S. Plant Experience with Alloy 600 Cracking and Boric Acid Corrosion of LightWater Reactor Pressure Vessel Materials, U.S. Nuclear Regulatory Commission, April 2005.
December 2010 XI M12-1 NUREG-1801, Rev. 2

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) piping components except for pump 

casings and valve bodies. This aging management program (AMP) includes determination of

the susceptibility of CASS components to thermal aging embrittlement based on casting 

method, molybdenum (Mo) content, and percent ferrite. For “potentially susceptible” 

components, as defined below, aging management is accomplished through either (a) qualified 

visual inspections, such as enhanced visual examination (EVT-1); (b) a qualified ultrasonic 

testing (UT) methodology; or (c) a component-specific flaw tolerance evaluation in accordance 

with the ASME Code, Section XI, 2004 edition.

10

For pump casings and valve bodies, based on the results of the assessment documented in the 

letter dated May 19, 2000, from Christopher Grimes, Nuclear Regulatory Commission (NRC), to 

Douglas Walters, Nuclear Energy Institute (NEI) (May 19, 2000 NRC letter), screening for 

susceptibility to thermal aging embrittlement is not required. The existing ASME Code, 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. 

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.

Aging management of CASS reactor internal components of pressurized water reactors (PWRs) 

are discussed in AMP XI.M16A and of CASS reactor internal components of boiling water 

reactors (BWRs) in AMP XI.M9.

Evaluation and Technical Basis

1. Scope of Program: This program manages loss of fracture toughness in potentially 

susceptible ASME Code Class 1 piping components made from CASS. 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 components constructed from cast austenitic 

stainless steel with service conditions above 250o

C (482oF). 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.

Based on the criteria set forth in the May 19, 2000, NRC letter, the susceptibility to thermal 

aging embrittlement of CASS materials is determined in terms of casting method, 

molybdenum content, and ferrite content. For low-molybdenum content steels (SA-351 

Grades CF3, CF3A, CF8, CF8A or other steels with ≤ 0.5 weight percent [wt.%] Mo), 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 lowmolybdenum steels are not susceptible. For high-molybdenum content steels (SA-351 

Grades CF3M, CF3MA, and CF8M or other steels with 2.0 to 3.0 wt.% Mo), static-cast 

 

10 Refer to the GALL Report, Chapter I, for applicability of other editions of ASME Code, Section XI.
NUREG-1801, Rev. 2 XI M12-2 December 2010

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 staff-approved method for calculating 

delta ferrite in CASS materials. A fracture toughness value of 255 kilojoules per square 

meter (kJ/m2

) (1,450 inches-pounds per square inch) at a crack depth of 2.5 millimeters 

(0.1 inch) is used to differentiate between CASS materials that are not susceptible and 

those that are potentially susceptible to thermal aging embrittlement. Extensive research 

data indicate that for CASS materials not susceptible to thermal aging embrittlement, 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 needed (and thus there are no aging management review line items). 

For all pump casings and valve bodies greater than a nominal pipe size (NPS) of 4 inches, 

the existing ASME Code, Section XI inspection requirements, including the alternative 

requirements of ASME Code Case N-481 for pump casings, are adequate. ASME Code, 

Section XI, Subsection IWB requires only surface examination of valve bodies less than a 

NPS of 4 inches. For these valve bodies less than a NPS of 4 inches, the adequacy of 

inservice inspection (ISI) according to ASME Code, Section XI has been demonstrated by 

an NRC-performed bounding integrity analysis (May 19, 2000 letter). 

2. Preventive Actions: This program is a condition monitoring program and does not mitigate 

thermal aging embrittlement.

3. Parameters Monitored/Inspected: The program 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. 

The program does not directly monitor for loss of fracture toughness that is induced by 

thermal aging; instead, the impact of loss of fracture toughness on component integrity is 

indirectly managed by using visual or volumetric examination techniques to monitor for 

cracking in the components. 

4. Detection of Aging Effects: For pump casings, valve bodies, and other “not susceptible” 

CASS piping components, no additional inspection or evaluations are needed to 

demonstrate that the material has adequate fracture toughness. 

For “potentially susceptible” piping components, the AMP provides for qualified inspections 

of the base metal, such as enhanced visual examination (EVT-1) or a qualified UT 

methodology, 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 Code, Section XI, 

Appendix VIII are acceptable. Alternatively, a plant-specific or component-specific flaw 

tolerance evaluation, using specific geometry, stress information, material properties, and 

ASME Code, Section XI can be used to demonstrate that the thermally-embrittled material 

has adequate toughness. Current UT methodology cannot detect and size cracks; thus, 

EVT-1 is used until qualified UT methodology for CASS can be established. A description of 

EVT-1 is found in Boiling Water Reactor Vessel and Internals Project (BWRVIP)-03 

(Revision 6) and Materials Reliability Program (MRP)-228 for PWRs. 
December 2010 XI M12-3 NUREG-1801, Rev. 2

5. Monitoring and Trending: Inspection schedules in accordance with ASME Code, Section 

XI, IWB-2400 or IWC-2400, reliable examination methods, and qualified inspection 

personnel provide timely and reliable detection of cracks. If flaws are detected, the period of 

acceptability is determined from analysis of the flaw, depending on the crack growth rate 

and mechanism. 

6. Acceptance Criteria: Flaws detected in CASS components are evaluated in accordance 

with the applicable procedures of ASME Code, Section XI, IWB-3500 or ASME Code, 

Section XI, IWC-3500. Flaw tolerance evaluation for components with ferrite content up to 

25% is performed according to the principles associated with ASME Code, Section XI, IWB3640 procedures for SAWs, disregarding the ASME Code restriction of 20% ferrite. 

Extensive research data indicates that the lower-bound 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 tolerance evaluation for piping with >25% ferrite is performed on a caseby-case basis by using the applicant’s fracture toughness data.

7. Corrective Actions: Repair and replacement are performed in accordance with ASME 

Code, Section XI, IWA-4000. As discussed in the Appendix for GALL, 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 10 CFR 

Part 50, Appendix B. As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B acceptable to address the confirmation 

process and administrative controls.

9. Administrative Controls: The administrative controls for this program provide for a formal

review and approval of corrective actions. The administrative controls for this program are 

implemented through the site's QA program in accordance with the requirements of 10 CFR 

Part 50, Appendix B.

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 will be 

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, 2009. 

10 CFR Part 50.55a, Codes and Standards, Office of the Federal Register, National Archives 

and Records Administration, 2009. 

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, The 

ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 50.55a, The 

American Society of Mechanical Engineers, New York, NY.

ASME Code Case N-481, Alternative Examination Requirements for Cast Austenitic Pump 

Casings, Section XI, Division 1.
NUREG-1801, Rev. 2 XI M12-4 December 2010

BWRVIP-03, Rev. 6, BWR Vessel and Internals Project: Reactor Pressure Vessel and Internals 

Examination Guidelines (EPRI TR-105696).

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. Vessel 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)

Letter from Mark J. Maxin, to Rick Libra (BWRVIP Chairman), Safety Evaluation for Electric 

Power Research Institute (EPRI) Boiling Water Reactor Vessel and Internals project 

(BWRVIP) Report TR-105696-R6 (BWRVIP-03), Revision 6, BWR Vessel and Internals 

Examination Guidelines (TAC No MC2293),” June 30, 2008 (ADAMS Accession No 

ML081500814)

MRP-228, Materials Reliability Program: Inspection Standard for PWR Internals, 2009.

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.
December 2010 XI M16A-1 NUREG-1801, Rev. 2

XI.M16A PWR VESSEL INTERNALS

Program Description 

This program relies on implementation of the Electric Power Research Institute (EPRI) Report 

No. 1016596 (MRP-227) and EPRI Report No. 1016609 (MRP-228) to manage the aging effects 

on the reactor vessel internal (RVI) components.

This program is used to manage the effects of age-related degradation mechanisms that are 

applicable in general to the PWR RVI components at the facility. These aging effects include (a) 

various forms of cracking, including stress corrosion cracking (SCC), which also encompasses 

primary water stress corrosion cracking (PWSCC), irradiation-assisted stress corrosion cracking 

(IASCC), or cracking due to fatigue/cyclical loading; (b) loss of material induced by wear; (c) 

loss of fracture toughness due to either thermal aging or neutron irradiation embrittlement; (d) 

changes in dimension due to void swelling; and (e) loss of preload due to thermal and 

irradiation-enhanced stress relaxation or creep. 

The program applies the guidance in MRP-227 for inspecting, evaluating, and, if applicable, 

dispositioning non-conforming RVI components at the facility. The program conforms to the 

definition of a sampling-based condition monitoring program, as defined by the Branch 

Technical Position RSLB-1, with periodic examinations and other inspections of highly-affected 

internals locations. These examinations provide reasonable assurance that the effects of agerelated degradation mechanisms will be managed during the period of extended operation. The 

program includes expanding periodic examinations and other inspections if the extent of the 

degradation effects exceeds the expected levels.

The MRP-227 guidance for selecting RVI components for inclusion in the inspection sample is 

based on a four-step ranking process. Through this process, the reactor internals for all three 

PWR designs were assigned to one of the following four groups: Primary, Expansion, Existing 

Programs, and No Additional Measures components. Definitions of each group are provided in 

GALL Chapter IX.B.

The result of this four-step sample selection process is a set of Primary Internals Component 

locations for each of the three plant designs that are expected to show the leading indications of 

the degradation effects, with another set of Expansion Internals Component locations that are 

specified to expand the sample should the indications be more severe than anticipated. The 

degradation effects in a third set of internals locations are deemed to be adequately managed 

by Existing Programs, such as ASME Code, Section XI,

11

 

11 Refer to the GALL Report, Chapter I, for applicability of various editions of the ASME Code, Section XI.

Examination Category B-N-3 

examinations of core support structures. A fourth set of internals locations are deemed to 

require no additional measures. As a result, the program typically identifies 5 to 15% of the RVI 

locations as Primary Component locations for inspections, with another 7 to 10% of the RVI 

locations to be inspected as Expansion Components, as warranted by the evaluation of the 

inspection results. Another 5 to 15% of the internals locations are covered by Existing 

Programs, with the remainder requiring no additional measures. This process thus uses 

appropriate component functionality criteria, age-related degradation susceptibility criteria, and 

failure consequence criteria to identify the components that will be inspected under the program 

in a manner that conforms to the sampling criteria for sampling-based condition monitoring 

programs in Section A.1.2.3.4 of NRC Branch Position RLSB-1. Consequently, the sample 
NUREG-1801, Rev. 2 XI M16A-2 December 2010

selection process is adequate to assure that the intended function(s) of the PWR reactor 

internal components are maintained during the period of extended operation.

The program’s use of visual examination methods in MRP-227 for detection of relevant 

conditions (and the absence of relevant conditions as a visual examination acceptance criterion) 

is consistent with the ASME Code, Section XI rules for visual examination. However, the 

program’s adoption of the MRP-227 guidance for visual examinations goes beyond the ASME 

Code, Section XI visual examination criteria because additional guidance is incorporated into 

MRP-227 to clarify how the particular visual examination methods will be used to detect relevant 

conditions and describes in more detail how the visual techniques relate to the specific RVI 

components and how to detect their applicable age-related degradation effects. 

The technical basis for detecting relevant conditions using volumetric ultrasonic testing (UT) 

inspection techniques can be found in MRP-228, where the review of existing bolting UT 

examination technical justifications has demonstrated the indication detection capability of at 

least two vendors, and where vendor technical justification is a requirement prior to any 

additional bolting examinations. Specifically, the capability of program’s UT volumetric methods 

to detect loss of integrity of PWR internals bolts, pins, and fasteners, such as baffle-former 

bolting in B&W and Westinghouse units, has been well demonstrated by operating experience. 

In addition, the program’s adoption of the MRP-227 guidance and process incorporates the UT 

criteria in MRP-228, which calls for the technical justifications that are needed for volumetric 

examination method demonstrations, required by the ASME Code, Section V. 

The program also includes future industry operating experience as incorporated in periodic 

revisions to MRP-227. The program thus provides reasonable assurance for the long-term 

integrity and safe operation of reactor internals in all commercial operating U.S. PWR nuclear 

power plants.

Age-related degradation in the reactor internals is managed through an integrated program. 

Specific features of the integrated program are listed in the following ten program elements. 

Degradation due to changes in material properties (e.g., loss of fracture toughness) was 

considered in the determination of inspection recommendations and is managed by the 

requirement to use appropriately degraded properties in the evaluation of identified defects. The 

integrated program is implemented by the applicant through an inspection plan that is submitted 

to the NRC for review and approval with the application for license renewal.

Evaluation and Technical Basis

1. Scope of Program: The scope of the program includes all RVI components at the [as an 

administrative action item for the AMP, the applicant to fill in the name of the applicant’s 

nuclear facility, including applicable units], which [is/are] built to a [applicant to fill in 

Westinghouse, CE, or B&W, as applicable] NSSS design. The scope of the program applies 

the methodology and guidance in the most recently NRC-endorsed version of MRP-227, 

which provides augmented inspection and flaw evaluation methodology for assuring the 

functional integrity of safety-related internals in commercial operating U.S. PWR nuclear 

power plants designed by B&W, CE, and Westinghouse. The scope of components 

considered for inspection under MRP-227 guidance includes core support structures 

(typically denoted as Examination Category B-N-3 by the ASME Code, Section XI), those 

RVI components that serve an intended license renewal safety function pursuant to criteria 

in 10 CFR 54.4(a)(1), and other RVI components whose failure could prevent satisfactory 

accomplishment of any of the functions identified in 10 CFR 54.4(a)(1)(i), (ii), or (iii). The 
December 2010 XI M16A-3 NUREG-1801, Rev. 2

scope of the program does not include consumable items, such as fuel assemblies, 

reactivity control assemblies, and nuclear instrumentation, because these components are 

not typically within the scope of the components that are required to be subject to an aging 

management review (AMR), as defined by the criteria set in 10 CFR 54.21(a)(1). The scope 

of the program also does not include welded attachments to the internal surface of the 

reactor vessel because these components are considered to be ASME Code Class 1 

appurtenances to the reactor vessel and are adequately managed in accordance with an 

applicant’s AMP that corresponds to GALL AMP XI.M1, “ASME Code, Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD.” 

The scope of the program includes the response bases to applicable license renewal 

applicant action items (LRAAIs) on the MRP-227 methodology, and any additional 

programs, actions, or activities that are discussed in these LRAAI responses and credited 

for aging management of the applicant’s RVI components. The LRAAIs are identified in the 

staff’s safety evaluation on MRP-227 and include applicable action items on meeting those 

assumptions that formed the basis of the MRP’s augmented inspection and flaw evaluation 

methodology (as discussed in Section 2.4 of MRP-227), and NSSS vendor-specific or plantspecific LRAAIs as well. The responses to the LRAAIs on MRP-227 are provided in 

Appendix C of the LRA.

The guidance in MRP-227 specifies applicability limitations to base-loaded plants and the 

fuel loading management assumptions upon which the functionality analyses were based. 

These limitations and assumptions require a determination of applicability by the applicant 

for each reactor and are covered in Section 2.4 of MRP-227.

2. Preventive Actions: The guidance in MRP-227 relies on PWR water chemistry control to 

prevent or mitigate aging effects that can be induced by corrosive aging mechanisms (e.g., 

loss of material induced by general, pitting corrosion, crevice corrosion, or stress corrosion 

cracking or any of its forms [SCC, PWSCC, or IASCC]). Reactor coolant water chemistry is 

monitored and maintained in accordance with the Water Chemistry Program. The program 

description, evaluation, and technical basis of water chemistry are presented in GALL AMP

XI.M2, “Water Chemistry.” 

3. Parameters Monitored/Inspected: The program manages the following age-related 

degradation effects and mechanisms that are applicable in general to the RVI components 

at the facility: (a) cracking induced by SCC, PWSCC, IASCC, or fatigue/cyclical loading; (b) 

loss of material induced by wear; (c) loss of fracture toughness induced by either thermal 

aging or neutron irradiation embrittlement; (d) changes in dimension due to void swelling 

and irradiation growth, distortion, or deflection; and (e) loss of preload caused by thermal 

and irradiation-enhanced stress relaxation or creep. For the management of cracking, the 

program monitors for evidence of surface breaking linear discontinuities if a visual inspection 

technique is used as the non-destruction examination (NDE) method, or for relevant flaw 

presentation signals if a volumetric UT method is used as the NDE method. For the 

management of loss of material, the program monitors for gross or abnormal surface 

conditions that may be indicative of loss of material occurring in the components. For the 

management of loss of preload, the program monitors for gross surface conditions that may 

be indicative of loosening in applicable bolted, fastened, keyed, or pinned connections. The 

program does not directly monitor for loss of fracture toughness that is induced by thermal 

aging or neutron irradiation embrittlement, or by void swelling and irradiation growth; 

instead, the impact of loss of fracture toughness on component integrity is indirectly 

managed by using visual or volumetric examination techniques to monitor for cracking in the 
NUREG-1801, Rev. 2 XI M16A-4 December 2010

components and by applying applicable reduced fracture toughness properties in the flaw 

evaluations if cracking is detected in the components and is extensive enough to warrant a 

supplemental flaw growth or flaw tolerance evaluation under the MRP-227 guidance or 

ASME Code, Section XI requirements. The program uses physical measurements to monitor 

for any dimensional changes due to void swelling, irradiation growth, distortion, or deflection.

Specifically, the program implements the parameters monitored/inspected criteria for [as an 

administrative action item for the AMP, applicant is to select one of the following to finish the 

sentence, as applicable to its NSSS vendor for its internals: “for B&W designed Primary 

Components in Table 4-1 of MRP-227”; “for CE designed Primary Components in Table 4-2 

of MRP-227”; and “for Westinghouse designed Primary Components in Table 4-3 of MRP227”]. Additionally, the program implements the parameters monitored/inspected criteria for 

[as an administrative action item for the AMP, applicant is to select one of the following to 

finish the sentence, as applicable to its NSSS vendor for its internals: “for B&W designed 

Expansion Components in Table 4-4 of MRP-227”; “for CE designed Expansion 

Components in Table 4-5 of MRP-227”; and “for Westinghouse designed Expansion 

Components in Table 4-6 of MRP-227”]. The parameters monitored/inspected for Existing 

Program Components follow the bases for referenced Existing Programs, such as the 

requirements for ASME Code Class RVI components in ASME Code, Section XI, Table 

IWB-2500-1, Examination Categories B-N-3, as implemented through the applicant’s ASME 

Code, Section XI program, or the recommended program for inspecting Westinghousedesigned flux thimble tubes in GALL AMP XI.M37, “Flux Thimble Tube Inspection.” No 

inspections, except for those specified in ASME Code, Section XI, are required for 

components that are identified as requiring “No Additional Measures,” in accordance with 

the analyses reported in MRP-227. 

4. Detection of Aging Effects: The detection of aging effects is covered in two places: (a) the 

guidance in Section 4 of MRP-227 provides an introductory discussion and justification of 

the examination methods selected for detecting the aging effects of interest; and (b) 

standards for examination methods, procedures, and personnel are provided in a 

companion document, MRP-228. In all cases, well-established methods were selected. 

These methods include volumetric UT examination methods for detecting flaws in bolting, 

physical measurements for detecting changes in dimension, and various visual (VT-3, VT-1, 

and EVT-1) examinations for detecting effects ranging from general conditions to detection 

and sizing of surface-breaking discontinuities. Surface examinations may also be used as 

an alternative to visual examinations for detection and sizing of surface-breaking 

discontinuities.

Cracking caused by SCC, IASCC, and fatigue is monitored/inspected by either VT-1 or EVT1 examination (for internals other than bolting) or by volumetric UT examination (bolting). 

The VT-3 visual methods may be applied for the detection of cracking only when the flaw 

tolerance of the component or affected assembly, as evaluated for reduced fracture 

toughness properties, is known and has been shown to be tolerant of easily detected large 

flaws, even under reduced fracture toughness conditions. In addition, VT-3 examinations are 

used to monitor/inspect for loss of material induced by wear and for general aging 

conditions, such as gross distortion caused by void swelling and irradiation growth or by 

gross effects of loss of preload caused by thermal and irradiation-enhanced stress 

relaxation and creep. 

In addition, the program adopts the recommended guidance in MRP-227 for defining the 

Expansion criteria that need to be applied to inspections of Primary Components and 
December 2010 XI M16A-5 NUREG-1801, Rev. 2

Existing Requirement Components and for expanding the examinations to include additional 

Expansion Components. As a result, inspections performed on the RVI components are 

performed consistent with the inspection frequency and sampling bases for Primary 

Components, Existing Requirement Components, and Expansion Components in MRP-227, 

which have been demonstrated to be in conformance with the inspection criteria, sampling 

basis criteria, and sample Expansion criteria in Section A.1.2.3.4 of NRC Branch Position 

RLSB-1.

Specifically, the program implements the parameters monitored/inspected criteria and bases 

for inspecting the relevant parameter conditions for [as an administrative action item for the 

AMP, applicant is to select one of the following to finish the sentence, as applicable to its 

NSSS vendor for its internals: “B&W designed Primary Components in Table 4-1 of MRP227”; “CE designed Primary Components in Table 4-2 of MRP-227;” or “Westinghouse 

designed Primary Components in Table 4-3 of MRP-227”] and for [as an administrative 

action item for the AMP, applicant is to select one of the following to finish the sentence, as 

applicable to its NSSS vendor for its internals: “for B&W designed Expansion Components 

in Table 4-4 of MRP-227;” “for CE designed expansion components in Table 4-5 of MRP227;” and “for Westinghouse designed Expansion Components in Table 4-6 of MRP-227”]. 

The program is supplemented by the following plant-specific Primary Component and 

Expansion Component inspections for the program (as applicable): [As a relevant license 

renewal applicant action item, the applicant is to list (using criteria in MRP-227) each 

additional RVI component that needs to be inspected as an additional plant-specific Primary 

Component for the applicant’s program and each additional RVI component that needs to be 

inspected as an additional plant-specific Expansion Component for the applicant’s program. 

For each plant specific component added as an additional primary or Expansion 

Component, the list should include the applicable aging effects that will be monitored for, the 

inspection method or methods used for monitoring, and the sample size and frequencies for 

the examinations].

In addition, in some cases (as defined in MRP-227), physical measurements are used as 

supplemental techniques to manage for the gross effects of wear, loss of preload due to 

stress relaxation, or for changes in dimension due to void swelling, deflection or distortion. 

The physical measurements methods applied in accordance with this program include 

[Applicant to input physical measure methods identified by the MRP in response to NRC RAI 

No. 11 in the NRC’s Request for Additional Information to Mr. Christen B. Larson, EPRI 

MRP on Topical Report MRP-227 dated November 12, 2009].

5. Monitoring and Trending: The methods for monitoring, recording, evaluating, and trending 

the data that result from the program’s inspections are given in Section 6 of MRP-227 and 

its subsections. The evaluation methods include recommendations for flaw depth sizing and 

for crack growth determinations as well for performing applicable limit load, linear elastic and 

elastic-plastic fracture analyses of relevant flaw indications. The examinations and reexaminations required by the MRP-227 guidance, together with the requirements specified 

in MRP-228 for inspection methodologies, inspection procedures, and inspection personnel, 

provide timely detection, reporting, and corrective actions with respect to the effects of the 

age-related degradation mechanisms within the scope of the program. The extent of the 

examinations, beginning with the sample of susceptible PWR internals component locations 

identified as Primary Component locations, with the potential for inclusion of Expansion 

Component locations if the effects are greater than anticipated, plus the continuation of the 

Existing Programs activities, such as the ASME Code, Section XI, Examination Category B-
NUREG-1801, Rev. 2 XI M16A-6 December 2010

N-3 examinations for core support structures, provides a high degree of confidence in the 

total program. 

6. Acceptance Criteria: Section 5 of MRP-227 provides specific examination acceptance 

criteria for the Primary and Expansion Component examinations. For components 

addressed by examinations referenced to ASME Code, Section XI, the IWB-3500 

acceptance criteria apply. For other components covered by Existing Programs, the 

examination acceptance criteria are described within the Existing Program reference 

document. 

The guidance in MRP-227 contains three types of examination acceptance criteria:

 For visual examination (and surface examination as an alternative to visual 

examination), the examination acceptance criterion is the absence of any of the specific, 

descriptive relevant conditions; in addition, there are requirements to record and 

disposition surface breaking indications that are detected and sized for length by VT1/EVT-1 examinations;

 For volumetric examination, the examination acceptance criterion is the capability for 

reliable detection of indications in bolting, as demonstrated in the examination Technical 

Justification; in addition, there are requirements for system-level assessment of bolted or 

pinned assemblies with unacceptable volumetric (UT) examination indications that 

exceed specified limits; and 

 For physical measurements, the examination acceptance criterion for the acceptable 

tolerance in the measured differential height from the top of the plenum rib pads to the 

vessel seating surface in B&W plants are given in Table 5-1 of MRP-227. The 

acceptance criterion for physical measurements performed on the height limits of the 

Westinghouse-designed hold-down springs are [The incorporation of this sentence is a 

license renewal applicant action item for Westinghouse PWR applicants only – insert the 

applicable sentence incorporating the specified physical measurement criteria only if the 

applicant’s facility is based on a Westinghouse NSSS design: the Westinghouse 

applicant is to incorporate the applicable language and then specify the fit up limits on 

the hold down springs, as established on a plant-specific basis for the design of the holddown springs at the applicant’s Westinghouse-designed facility].

7. Corrective Actions: Corrective actions following the detection of unacceptable conditions 

are fundamentally provided for in each plant’s corrective action program. Any detected 

conditions that do not satisfy the examination acceptance criteria are required to be 

dispositioned through the plant corrective action program, which may require repair, 

replacement, or analytical evaluation for continued service until the next inspection. The 

disposition will ensure that design basis functions of the reactor internals components will 

continue to be fulfilled for all licensing basis loads and events. Examples of methodologies 

that can be used to analytically disposition unacceptable conditions are found in the ASME 

Code, Section XI or in Section 6 of MRP-227. Section 6 of MRP-227 describes the options 

that are available for disposition of detected conditions that exceed the examination 

acceptance criteria of Section 5 of the report. These include engineering evaluation 

methods, as well as supplementary examinations to further characterize the detected 

condition, or the alternative of component repair and replacement procedures. The latter are 

subject to the requirements of the ASME Code, Section XI. The implementation of the 

guidance in MRP-227, plus the implementation of any ASME Code requirements, provides 
December 2010 XI M16A-7 NUREG-1801, Rev. 2

an acceptable level of aging management of safety-related components addressed in 

accordance with the corrective actions of 10 CFR Part 50, Appendix B or its equivalent, as 

applicable. 

Other alternative corrective action bases may be used to disposition relevant conditions if 

they have been previously approved or endorsed by the NRC. Examples of previously NRCendorsed alternative corrective actions bases include those corrective actions bases for 

Westinghouse-design RVI components that are defined in Tables 4-1, 4-2, 4-3, 4-4, 4-5, 4-6, 

4-7 and 4-8 of Westinghouse Report No. WCAP-14577-Rev. 1-A, or for B&W-designed RVI 

components in B&W Report No. BAW-2248. Westinghouse Report No. WCAP-14577-Rev. 

1-A was endorsed for use in an NRC SE to the Westinghouse Owners Group, dated 

February 10, 2001. B&W Report No. BAW-2248 was endorsed for use in an SE to 

Framatome Technologies on behalf of the B&W Owners Group, dated December 9, 1999. 

Alternative corrective action bases not approved or endorsed by the NRC will be submitted 

for NRC approval prior to their implementation. 

8. Confirmation Process: Site quality assurance procedures, review and approval processes, 

and administrative controls are implemented in accordance with the requirements of 10 CFR 

Part 50, Appendix B, or their equivalent, as applicable. It is expected that the 

implementation of the guidance in MRP-227 will provide an acceptable level of quality for 

inspection, flaw evaluation, and other elements of aging management of the PWR internals 

that are addressed in accordance with the 10 CFR Part 50, Appendix B, or their equivalent 

(as applicable), confirmation process, and administrative controls.

9. Administrative Controls: The administrative controls for such programs, including their 

implementing procedures and review and approval processes, are under existing site 10 

CFR 50 Appendix B Quality Assurance Programs, or their equivalent, as applicable. Such a 

program is thus expected to be established with a sufficient level of documentation and 

administrative controls to ensure effective long-term implementation.

10. Operating Experience: Relatively few incidents of PWR internals aging degradation have 

been reported in operating U.S. commercial PWR plants. A summary of observations to date 

is provided in Appendix A of MRP-227-A. The applicant is expected to review subsequent 

operating experience for impact on its program or to participate in industry initiatives that 

perform this function.

The application of the MRP-227 guidance will establish a considerable amount of operating 

experience over the next few years. Section 7 of MRP-227 describes the reporting 

requirements for these applications, and the plan for evaluating the accumulated additional 

operating experience. 

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

10 CFR Part 50.55a, Codes and Standards, Office of the Federal Register, National Archives 

and Records Administration, 2009.

ASME Boiler & Pressure Vessel Code, Section V, Nondestructive Examination, 2004 Edition, 

American Society of Mechanical Engineers, New York, NY.
NUREG-1801, Rev. 2 XI M16A-8 December 2010

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, The 

ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 50.55a, The 

American Society of Mechanical Engineers, New York, NY.

B&W Report No. BAW-2248, Demonstration of the Management of Aging Effects for the 

Reactor Vessel Internals, Framatome Technologies (now AREVA Technologies), Lynchburg 

VA, July 1997. (NRC Microfiche Accession Number A0076, Microfiche Pages 001 - 108).

EPRI 1014986, PWR Primary Water Chemistry Guidelines, Volume 1, Revision 6, Electric 

Power Research Institute, Palo Alto, CA, December 2007. (Non-publicly available ADAMS 

Accession Number ML081140278). The non-proprietary version of the report may accessed 

by members of the public at ADAMS Accession Number ML081230449

EPRI 1016596, Materials Reliability Program: Pressurized Water Reactor Internals Inspection 

and Evaluation Guidelines (MRP-227-Rev. 0), Electric Power Research Institute, Palo Alto, 

CA: 2008. 

EPRI 1016609, Materials Reliability Program: Inspection Standard for PWR Internals (MRP228), Electric Power Research Institute, Palo Alto, CA, July 2009. (Non-publicly available 

ADAMS Accession Number ML092120574). The non-proprietary version of the report may 

accessed by members of the public at ADAMS Accession Number ML092750569. 

NRC RAI No. 11 in the NRC’s Request for Additional Information to the Mr. Christen B. Larson, 

EPRI MRP on Topical Report MRP-227 dated November 12, 2009.

NRC Safety Evaluation from C. I. Grimes [NRC] to R. A, Newton [Chairman, Westinghouse 

Owners Group], Acceptance for Referencing of Generic License Renewal Program Topical 

Report Entitled “License Renewal Evaluation: Aging Management for Reactor Internals,”

WCAP-14577, Revision 1, February 10, 2001. (ADAMS Accession Number ML010430375).

NRC Safety Evaluation from C. I. Grimes [NRC] to W. R. Gray [Framatome Technologies], 

Acceptance for Referencing of Generic License Renewal Program Topical Report Entitled 

“Demonstration of the Management of Aging Effects for the Reactor Vessel Internals,”

February 10, 2001. (ADAMS Accession Number ML993490288). 

NUREG-1800, Revision 2, Standard Review Plan for Review of License Renewal Applications 

for Nuclear Power Plants, Appendix A.1, “Aging Management Review - Generic (Branch 

Technical Position RLSB-1),” U.S. Nuclear Regulatory Commission, Washington, DC, 2010. 

Westinghouse Non-Proprietary Class 3 Report No. WCAP-14577-Rev. 1-A, License Renewal 

Evaluation: Aging Management for Reactor Internals, Westinghouse Electric Company, 

Pittsburgh, PA [March 2001]. Report was submitted to the NRC Document Control Desk in a 

letter dated April 9, 2001. (ADAMS Accession Number ML011080790).
December 2010 XI M17-1 NUREG-1801, Rev. 2

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 or R3 for an effective flowaccelerated 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. NSAC-202L-R2 or R3 provides general guidelines for the FAC 

program. To provide reasonable assurance 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 or R3 to satisfy the criteria specified 

in 10 CFR Part 50, Appendix B, for development of procedures and control of special 

processes.

Evaluation and Technical Basis

1. Scope of Program: The FAC program, described by the EPRI guidelines in NSAC-202L-R2 

or R3, 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 89-08. 

2. Preventive Actions: The FAC program is an analysis, inspection, and verification program; 

no preventive action has been recommended in this program. 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 monitors the effects of 

loss of material due to wall thinning 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 or R3 consists of identification of 

susceptible locations, as indicated by operating conditions or special considerations. 

Ultrasonic or radiographic testing is used to detect wall thinning. A representative sample of 

components is selected based on the most susceptible locations for wall thickness 

measurements at a frequency in accordance with NSAC 202L guidelines to ensure that 

degradation is identified and mitigated before the component integrity is challenged. The 

extent and schedule of the inspections ensure 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 

acceptable because it provides a bounding analysis for FAC. The analysis is bounding 

because in general the predicted wear rates and component thicknesses are conservative 

when compared to actual field measurements. It is recognized that CHECWORKS is not 
NUREG-1801, Rev. 2 XI M17-2 December 2010

always conservative in predicting component thickness; therefore, when measurements 

show the predictions to be non-conservative, the model must be re-calibrated using the 

latest field data. CHECWORKS was developed and benchmarked by comparing 

CHECWORKS predictions against actual measured component thickness measurements 

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 ensure that the extent of wall thinning is 

adequately determined, that intended function will not be lost, and that corrective actions are 

adequately identified. Previous wear rate predictions due to FAC may change after a power 

uprate is implemented. Wear rates are updated in CHECWORKS according to power uprate 

conditions. Subsequent field measurements are used to calibrate or benchmark the 

predicted wear rates.

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, 

corrective action should be considered.

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. When susceptible 

components are replaced with resistant materials, such as high Cr material, the downstream 

components should be monitored closely to mitigate any increased wear. As discussed in 

the Appendix for GALL, 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 for GALL, the 

staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process.

9. Administrative Controls: 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

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 Notice [IN] 

81-28, IN 92-35, IN 95-11, IN 2006-08) and in two-phase piping in extraction steam lines 

(NRC IN 89-53, IN 97-84) and moisture separation reheater and feedwater heater drains 

(NRC IN 89-53, IN 91-18, IN 93-21, IN 97-84). Observed wall thinning may be due to 

mechanisms other than FAC, which require alternate materials to resolve the issue 

(Licensee Event Report 50-237/2007-003-00). Operating experience shows that the present 

program, when properly implemented, is effective in managing FAC in high-energy carbon 

steel piping and components.
December 2010 XI M17-3 NUREG-1801, Rev. 2

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

10 CFR Part 50.55a, Codes and Standards, Office of the Federal Register, National Archives 

and Records Administration, 2009.

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.

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.

NRC Information Notice 99-19, Rupture of the Shell Side of a Feedwater Heater at the Point

Beach Nuclear Plant, U.S. Nuclear Regulatory Commission, June 23, 1999.

NSAC-202L-R2, Recommendations for an Effective Flow Accelerated Corrosion Program, 

Electric Power Research Institute, Nuclear Safety Analysis Center, Palo Alto, CA, April 8, 

1999.

NSAC-202L-R3, Recommendations for an Effective Flow Accelerated Corrosion Program, 

(1011838), Electric Power Research Institute, Nuclear Safety Analysis Center, Palo Alto, 

CA, May 2006.

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. 2 XI M17-4 December 2010

NRC Information Notice 2006-08, Secondary Piping Rupture at the Mihama Power Station in 

Japan, U.S. Nuclear Regulatory Commission, March 16, 2006.

NRC Licensee Event Report 50‐ 237/2007‐ 003‐ 00, Unit 2 High Pressure Coolant Injection 

System Declared Inoperable, U.S. Nuclear Regulatory Commission, September 24, 2007.

NRC Licensee Event Report 1999-003-01, Manual Reactor Trip due to Heater Drain System 

Pipe Rupture Caused by Flow Accelerated Corrosion, U.S. Nuclear Regulatory Commission, 

May 1, 2000.
December 2010 XI M18-1 NUREG-1801, Rev. 2

XI.M18 BOLTING INTEGRITY

Program Description

The program manages aging of closure bolting for pressure retaining components. The program 

relies on recommendations for a comprehensive bolting integrity program, as delineated in 

NUREG-1339, and industry recommendations, as delineated in the following documents:

 NUREG-1339, “Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in 

Nuclear Power Plants.”

 Electric Power Research Institute (EPRI) NP-5769, “Degradation and Failure of Bolting 

in Nuclear Power Plants” (with the exceptions noted in NUREG-1339 for safety-related 

bolting). 

 EPRI TR-104213, “Bolted Joint Maintenance and Application Guide.” 

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. 

Aging management program (AMP) XI.M1, “ASME Section XI Inservice Inspection, Subsections 

IWB, IWC, and IWD,” includes inspection of safety-related and non-safety-related closure 

bolting and supplements this bolting integrity program. AMPs XI.S1, “ASME Section XI, 

Subsection IWE”; XI.S3, “ASME Section XI, Subsection IWF”; XI.S6, “Structures Monitoring”; 

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

Plants”; and XI.M23, “Inspection of Overhead Heavy Load and Light Load (Related to Refueling) 

Handling Systems,” manage inspection of safety-related and non-safety related structural 

bolting. 

Evaluation and Technical Basis

1. Scope of Program: This program manages aging of closure bolting for pressure retaining 

components within the scope of license renewal, including both safety-related and nonsafety-related bolting. This program does not manage aging of reactor head closure stud 

bolting (AMP XI.M3) or structural bolting (AMPs XI.S1, XI.S3, XI.S6, XI.S7, and XI.M23).

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. 

NUREG-1339 takes exception to certain items in EPRI NP-5769 and recommends 

additional measures with regard to them. Of particular note, use of molybdenum disulfide 

(MoS2) as a lubricant has been shown to be a potential contributor to stress corrosion 

cracking (SCC) and should not be used. Preventive measures also include using bolting 

material that has an actual measured yield strength limited to less than 1,034 megapascals 

(MPa) (150 kilo-pounds per square inch [ksi]). 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 guidance 

in EPRI documents, manufacturer recommendations, or engineering evaluation. 
NUREG-1801, Rev. 2 XI M18-2 December 2010

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. 

High strength closure bolting (actual yield strength greater than or equal to 1,034 MPa 

[150 ksi]), if used, should be monitored for cracking.

4. Detection of Aging Effects: The American Society of Mechanical Engineers (ASME) 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program implements 

inspection of Class 1, Class 2, and Class 3 pressure retaining bolting in accordance with 

requirements of ASME Code Section XI,

12

Degradation of pressure boundary closure bolting due to crack initiation, loss of preload, or 

loss of material may result in leakage from the mating surfaces or joint connections of 

pressure boundary components. Periodic inspection of pressure boundary components for 

signs of leakage ensures that age-related degradation of closure bolting is detected and 

corrected before component leakage becomes excessive. Accordingly, pressure retaining 

bolted connections should be inspected at least once per refueling cycle. The inspections 

may be performed as part of ASME Code Section XI leakage tests or as part of other 

periodic inspection activities, such as system walkdowns or an external surfaces monitoring 

program.

Tables IWB-2500-1, IWC-2500-1, and IWD-2500-

1. These include volumetric and visual (VT-1) examinations, as appropriate. In addition, for 

both ASME Code class bolting and non-ASME Code class bolting, periodic system 

walkdowns and inspections (at least once per refueling cycle) ensure detection of leakage at 

bolted joints before the leakage becomes excessive. Bolting inspections should include 

consideration of the guidance applicable for pressure boundary bolting in NUREG-1339 and 

in EPRI NP-5769 and EPRI TR-104213.

High strength closure bolting (actual yield strength greater than or equal to 1,034 MPa (150 

ksi) may be subject to stress corrosion cracking. For high strength closure bolts (regardless 

of code classification), volumetric examination in accordance to that of ASME Code Section 

XI, Table IWB-2500-1, Examination Category B-G-1, should be performed. 

5. Monitoring and Trending: The inspection schedules of ASME Section XI components are 

effective and ensure timely detection of applicable aging effects. If a bolting connection for 

pressure retaining components not covered by ASME Section XI is reported to be leaking, it 

may be inspected daily or in accordance with the corrective action process. If the leak rate is 

increasing, more frequent inspections may be warranted. 

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, indications of aging should be dispositioned in accordance with the 

corrective action process. 

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-ASME code class bolting) is performed in accordance 

with the guidelines and recommendations of EPRI TR-104213. As discussed in the 

 

12 Refer to the GALL Report, Chapter I, for applicability of other editions of the ASME Code, Section XI.
December 2010 XI M18-3 NUREG-1801, Rev. 2

Appendix for GALL, 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 10 CFR 

Part 50, Appendix B. As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process and administrative controls.

9. Administrative Controls: As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls. 

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 (U.S. Nuclear Regulatory Commission [NRC] IE Bulletin 82-02, NRC Generic Letter 

91-17). SCC has occurred in high strength bolts used for nuclear steam supply system 

component supports (EPRI NP-5769). The bolting integrity program developed and 

implemented in accordance with the applicant’s docketed responses to NRC 

communications on bolting events have provided an effective means of ensuring bolting 

reliability. These programs are documented in EPRI NP-5769 and TR-104213 and represent 

industry consensus.

Degradation related failures have occurred in downcomer Tee-quencher bolting in boiling 

water reactors (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, 2009. 

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2009. 

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, The 

ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 50.55a, The 

American Society of Mechanical Engineers, New York, NY.

EPRI NP-5769, Degradation and Failure of Bolting in Nuclear Power Plants, Volumes 1 and 2, 

Electric Power Research Institute, April 1988. 

EPRI TR-104213, Bolted Joint Maintenance & Application Guide, Electric Power Research 

Institute, December 1995.

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. 
NUREG-1801, Rev. 2 XI M18-4 December 2010

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. 

NRC Morning Report, Failure of Safety/Relief Valve Tee-Quencher Support Bolts, March 14, 

2005. (ADAMS Accession Number ML050730347)

NUREG-1339, Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear 

Power Plants, U.S. Nuclear Regulatory Commission, June 1990.
December 2010 XI M19-1 NUREG-1801, Rev. 2

XI.M19 STEAM GENERATORS

Program Description

The Steam Generator program is applicable to managing the aging of steam generator tubes, 

plugs, sleeves, and secondary side components that are contained within the steam generator 

(i.e., secondary side internals).

The establishment of a steam generator program for ensuring steam generator tube integrity is 

required by plant technical specifications. The steam generator tube integrity portion of the 

technical specifications at each PWR contains the same fundamental requirements as outlined 

in the standard technical specifications of NUREG-1430, Volume 1, Rev. 3, for Babcock & 

Wilcox pressurized water reactors (PWRs); NUREG-1431, Volume 1, Rev. 3, for Westinghouse 

PWRs; and NUREG-1432, Volume 1, Rev. 3, for Combustion Engineering PWRs. The 

requirements pertaining to steam generators in these three versions of the standard technical 

specifications are essentially identical. The technical specifications require tube integrity to be 

maintained and specify performance criteria, condition monitoring requirements, inspection 

scope and frequency, acceptance criteria for the plugging or repair of flawed tubes, acceptable 

tube repair methods, and leakage monitoring requirements.

The nondestructive examination techniques used to inspect tubes, plugs, sleeves, and 

secondary side internals are intended to identify components (e.g., tubes, plugs) with 

degradation that may need to be removed from service or repaired.

The Steam Generator program at PWRs is modeled after Nuclear Energy Institute (NEI) 97-06, 

Revision 2, “Steam Generator Program Guidelines.” This program references a number of 

industry guidelines (e.g., the EPRI PWR Steam Generator Examination Guidelines, PWR 

Primary-to-Secondary Leak Guidelines, PWR Primary Water Chemistry Guidelines, PWR 

Secondary Water Chemistry Guidelines, Steam Generator Integrity Assessment Guidelines, 

Steam Generator In Situ Pressure Test Guidelines) and incorporates a balance of prevention, 

mitigation, 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 steam generator plugs, sleeves, and secondary side 

internals. Therefore, all of these components are addressed by this aging management program 

(AMP). The NEI 97-06 program has been effective at managing the aging effects associated 

with steam generator tubes, plugs, sleeves, and secondary side internals.

Evaluation and Technical Basis

1. Scope of Program: This program addresses degradation associated with steam generator 

tubes, plugs, sleeves, and secondary side components that are contained within the steam 

generator (i.e., secondary side internals). It does not cover degradation associated with the 

steam generator shell, channelhead, nozzles, or welds associated with these components.

2. Preventive Actions: This program includes preventive and mitigative actions for addressing 

degradation. Preventive and mitigative measures that are part of the Steam Generator 

program include foreign material exclusion programs, and other primary and secondary side 

maintenance activities. The program includes foreign material exclusion as a means to 
NUREG-1801, Rev. 2 XI M19-2 December 2010

inhibit wear degradation and secondary side maintenance activities, such as sludge lancing, 

for removing deposits that may contribute to degradation. Guidance on foreign material 

exclusion is provided in NEI 97-06. Guidance on maintenance of secondary side integrity is 

provided in the EPRI Steam Generator Integrity Assessment Guidelines. Primary side 

preventive maintenance activities include replacing plugs made with corrosion susceptible 

materials with more corrosion resistant materials and preventively plugging tubes 

susceptible to degradation.

Extensive deposit buildup in the steam generators could affect tube integrity. The EPRI 

Steam Generator Integrity Assessment Guidelines, which are referenced in NEI 97-06, 

provide guidance on maintenance on the secondary side of the steam generator, including 

secondary side cleaning. Secondary side water chemistry plays an important role in 

controlling the introduction of impurities into the steam generator and potentially limiting their 

deposition on the tubes. Maintaining high water purity reduces susceptibility to SCC or 

IGSCC. Water chemistry is monitored and maintained in accordance with the Water 

Chemistry program. The program description and evaluation and technical basis of 

monitoring and maintaining water chemistry are addressed in GALL AMP XI.M2, “Water 

Chemistry.”

3. Parameters Monitored/Inspected: There are currently three types of steam generator 

tubing used in the United States: mill annealed Alloy 600, thermally treated Alloy 600, and 

thermally treated Alloy 690. Mill annealed Alloy 600 steam generator tubes have 

experienced degradation due to corrosion (e.g., primary water stress corrosion cracking, 

outside diameter stress corrosion cracking, intergranular attack, pitting, and wastage) and 

mechanically induced phenomena (e.g., denting, wear, impingement damage, and fatigue). 

Thermally treated Alloy 600 steam generator tubes have experienced degradation due to 

corrosion (primarily cracking) and mechanically induced phenomena (primarily wear). 

Thermally treated Alloy 690 tubes have only experienced tube degradation due to 

mechanically induced phenomena (primarily wear). Degradation of tube plugs, sleeves, and 

secondary side internals have also been observed, depending, in part, on the material of 

construction of the specific component.

The program includes an assessment of the forms of degradation to which a component is 

susceptible and implementation of inspection techniques capable of detecting those forms of 

degradation. The parameter monitored is specific to the component and the acceptance 

criteria for the inspection. For example, the severity of tube degradation may be evaluated in 

terms of the depth of degradation or measured voltage, dependent on whether a depthbased or voltage-based tube repair criteria (acceptance criteria) is being implemented for 

that specific degradation mechanism. Other parameters monitored include signals of 

excessive deposit buildup (e.g., steam generator water level oscillations), which may result 

in fatigue failure of tubes or corrosion of the tubes; water chemistry parameters, which may 

indicate unacceptable levels of impurities; primary-to-secondary leakage, which may 

indicate excessive tube, plug, or sleeve degradation; and the presence of loose parts or 

foreign objects on the primary and secondary side of the steam generator, which may result 

in tube damage.

Water chemistry parameters are also monitored as discussed in AMP XI.M2. The EPRI 

PWR Steam Generator Primary-to-Secondary Leakage Guidelines (EPRI 1008219) provides 

guidance on monitoring primary-to-secondary leakage. The EPRI Steam Generator Integrity 

Assessment Guidelines (EPRI 1012987) provide guidance on secondary side activities.
December 2010 XI M19-3 NUREG-1801, Rev. 2

In summary, the NEI 97-06 program provides guidance on parameters to be monitored or 

inspected.

4. Detection of Aging Effects: The technical specifications require that a Steam Generator 

program be established and implemented to ensure that steam generator tube integrity is 

maintained. This requirement ensures that components that could compromise tube integrity 

are properly evaluated or monitored (e.g., degradation of a secondary side component that 

could result in a loss of tube integrity is managed by this program). The inspection 

requirements in the technical specifications are intended to detect degradation (i.e., aging 

effects), if they should occur.

The technical specifications are performance-based, and the actual scope of the inspection 

and the expansion of sample inspections are justified based on the results of the 

inspections. The goal is to perform inspections at a frequency sufficient to provide 

reasonable assurance of steam generator tube integrity for the period of time between 

inspections. 

The general condition of some components (e.g., plugs and secondary side components) 

may be monitored visually, and, subsequently, more detailed inspections may be performed 

if degradation is detected. 

NEI 97-06 provides additional guidance on inspection programs to detect degradation of 

tubes, sleeves, plugs, and secondary side internals. The frequencies of the inspections are 

based on technical assessments. Guidance on performing these technical assessments is 

contained in NEI 97-06 and the associated industry guidelines.

The inspections and monitoring are performed by qualified personnel using qualified 

techniques in accordance with approved licensee procedures. The EPRI PWR Steam 

Generator Examination Guidelines (EPRI 1013706) contains guidance on the qualification of 

steam generator tube inspection techniques.

The primary-to-secondary leakage monitoring program provides a potential indicator of a 

loss of steam generator tube integrity. NEI 97-06 and the associated EPRI guidelines 

provide information pertaining to an effective leakage monitoring program.

5. Monitoring and Trending: Condition monitoring assessments are performed to determine 

whether the structural- and accident-induced leakage performance criteria were satisfied 

during the prior operating interval. Operational assessments are performed to verify that 

structural and leakage integrity will be maintained for the planned operating interval before 

the next inspection. If tube integrity cannot be maintained for the planned operating interval 

before the next inspection, corrective actions are taken in accordance with the plant’s 

corrective action program. Comparisons of the results of the condition monitoring 

assessment to the predictions of the previous operational assessment are performed to 

evaluate the adequacy of the previous operational assessment methodology. If the 

operational assessment was not conservative in terms of the number and/or severity of the 

condition, corrective actions are taken in accordance with the plant’s corrective action 

program.

The technical specifications require condition monitoring and operational assessments to be 

performed (although the technical specifications do not explicitly require operational 

assessments, these assessments are necessary to ensure that the tube integrity will be 
NUREG-1801, Rev. 2 XI M19-4 December 2010

maintained until the next inspection). Condition monitoring and operational assessments are 

done in accordance with the technical specification requirements and guidance in NEI 97-06 

and the EPRI Steam Generator Integrity Assessment Guidelines.

The goal of the inspection program for all components covered by this AMP is to ensure that 

the components continue to function consistent with the design and licensing basis of the 

facility (including regulatory safety margins).

Assessments of the degradation of steam generator secondary side internals are performed 

in accordance with the guidance in the EPRI Steam Generator Integrity Assessment 

Guidelines to ensure the component continues to function consistent with the design and 

licensing basis and to ensure technical specification requirements are satisfied.

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 steam generator tubes and sleeves are based on U.S. 

Nuclear Regulatory Commission (NRC) Regulatory Guide 1.121 and are incorporated into 

plant technical specifications. Guidance on assessing the acceptability of flaws is also 

provided in NEI 97-06 and the associated EPRI guidelines, including the EPRI Steam 

Generator In-Situ Pressure Test Guidelines and EPRI Steam Generator Integrity 

Assessment Guidelines.

Degraded plugs, degraded secondary side internals, and leaving a loose part or a foreign 

object in the steam generator are evaluated for continued acceptability on a case-by-case 

basis. NEI 97-06 and the associated EPRI guidelines provide guidance on the performance 

of these evaluations. The intent of these evaluations is to ensure that the components 

affected by parts or objects have adequate integrity consistent with the design and licensing 

basis of the facility. 

Guidance on the acceptability of primary-to-secondary leakage and water chemistry 

parameters also are discussed in NEI 97-06 and the associated EPRI guidelines.

7. Corrective Actions: For degradation of steam generator tubes and sleeves (if applicable), 

the technical specifications provide requirements on the actions to be taken when the 

acceptance criteria are not met. For degradation of other components, the appropriate 

corrective action is evaluated per NEI 97-06 and the associated EPRI guidelines, the 

American Society of Mechanical Engineers (ASME) Code Section XI (2004 Edition),

13

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and site quality assurance 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process and administrative controls. 

10 

CFR 50.65, and 10 CFR Part 50, Appendix B, as appropriate. As discussed in the Appendix 

for GALL, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable for 

ensuring effective corrective actions.

 

13 Refer to the GALL Report, Chapter 1, for applicability of other editions of the ASME Code.
December 2010 XI M19-5 NUREG-1801, Rev. 2

In addition, the adequacy of the preventive measures in the Steam Generator program is 

confirmed through periodic inspections.

9. Administrative Controls: As discussed in the Appendix for GALL, the staff finds the

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: Several generic communications have been issued by the NRC 

related to the steam generator programs implemented at plants. The reference section lists 

many of these generic communications. In addition, NEI 97-06 provides guidance to the 

industry for routinely sharing pertinent steam generator operating experience and for 

incorporating lessons learned from plant operation into guidelines referenced in NEI 97-06. 

The latter includes providing interim guidance to the industry, when needed.

The NEI 97-06 program has been effective at managing the aging effects associated with 

steam generator tubes, plugs, sleeves, and secondary side components that are contained 

within the steam generator (i.e., secondary side internals), such that the steam generators 

can perform their intended safety function.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009. 

10 CFR Part 50.55a, Codes and Standards, Office of the Federal Register, National Archives 

and Records Administration, 2009. 

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, 2009.

EPRI 1008219, PWR Primary-to-Secondary Leak Guidelines: Revision 3, Electric Power 

Research Institute, Palo Alto, CA, December 2004. 

EPRI 1012987, Steam Generator Integrity Assessment Guidelines: Revision 2, Electric Power 

Research Institute, Palo Alto, CA, July 2006.

EPRI 1013706, PWR Steam Generator Examination Guidelines: Revision 7, Electric Power 

Research Institute, Palo Alto, CA, October 2007.

EPRI 1014983, Steam Generator In-Situ Pressure Test Guidelines: Revision 3, Electric Power 

Research Institute, Palo Alto, CA, August 2007.

EPRI 1014986, Pressurized Water Reactor Primary Water Chemistry Guidelines: Revision 6, 

Electric Power Research Institute, Palo Alto, CA, December 2007.

EPRI 1016555, Pressurized Water Reactor Secondary Water Chemistry Guidelines: Revision 7, 

Electric Power Research Institute, Palo Alto, CA, February 2009.NEI 97-06, Rev. 2, Steam 

Generator Program Guidelines, Nuclear Energy Institute, September 2005.

NRC Bulletin 88-02, Rapidly Propagating Cracks in Steam Generator Tubes, U.S. Nuclear 

Regulatory Commission, February 5, 1988.
NUREG-1801, Rev. 2 XI M19-6 December 2010

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, 1990.

NRC Bulletin 89-01, Supplement 2, Failure of Westinghouse Steam Generator Tube Mechanical 

Plugs, U.S. Nuclear Regulatory Commission, June 28, 1991.

NRC Draft Regulatory Guide DG-1074, Steam Generator Tube Integrity, U.S. Nuclear 

Regulatory Commission, December 1998.

NRC Regulatory Guide, 1.121, Bases for Plugging Degraded PWR Steam Generator Tubes, 

U.S. Nuclear Regulatory Commission, August 1976.

NRC Generic Letter 95-03, Circumferential Cracking of Steam Generator Tubes, U.S. Nuclear 

Regulatory Commission, April 28, 1995.

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 97-05, Steam Generator Tube Inspection Techniques, U.S. Nuclear 

Regulatory Commission, December 17, 1997.

NRC Generic Letter 97-06, Degradation of Steam Generator Internals, U.S. Nuclear Regulatory 

Commission, December 30, 1997.

NRC Generic Letter 2004-01, Requirements for Steam Generator Tube Inspections, U.S. 

Nuclear Regulatory Commission, August 30, 2004.

NRC Generic Letter 2006-01, Steam Generator Tube Integrity and Associated Technical 

Specifications, U.S. Nuclear Regulatory Commission, January 20, 2006.

NRC Information Notice 85-37, Chemical Cleaning of Steam Generators at Millstone 2, U.S. 

Nuclear Regulatory Commission, May 14, 1985.

NRC Information Notice 88-06, Foreign Objects in Steam Generators, U.S. Nuclear Regulatory 

Commission, February 29, 1988.

NRC Information Notice 88-99, Detection and Monitoring of Sudden and/or Rapidly Increasing 

Primary-to-Secondary Leakage, U.S. Nuclear Regulatory Commission, December 20, 1988.

NRC Information Notice 89-65, Potential for Stress Corrosion Cracking in Steam Generator 

Tube Plugs Supplied by Babcock and Wilcox, U.S. Nuclear Regulatory Commission, 

September 8, 1989.

NRC Information Notice 90-49, Stress Corrosion Cracking in PWR Steam Generator Tubes, 

U.S. Nuclear Regulatory Commission, August 6, 1990.

NRC Information Notice 91-19, Steam Generator Feedwater Distribution Piping Damage, US 

Nuclear Regulatory Commission, March 12, 1991.
December 2010 XI M19-7 NUREG-1801, Rev. 2

NRC Information Notice 91-43, Recent Incidents Involving Rapid Increases in Primary-toSecondary Leak Rate, U.S. Nuclear Regulatory Commission, July 5, 1991.

NRC Information Notice 91-67, Problems with the Reliable Detection of Intergranular Attack 

(IGA) of Steam Generator Tubing, U.S. Nuclear Regulatory Commission, October 21, 1991.

NRC Information Notice 92-80, Operation with Steam Generator Tubes Seriously Degraded, 

U.S. Nuclear Regulatory Commission, December 7, 1992.

NRC Information Notice 93-52, Draft NUREG-1477, Voltage-Based Interim Plugging Criteria for 

Steam Generator Tubes, U.S. Nuclear Regulatory Commission, July 14, 1993.

NRC Information Notice 93-56, Weaknesses in Emergency Operating Procedures Found as a 

Result of Steam Generator Tube Rupture, U.S. Nuclear Regulatory Commission, July 22, 

1993.

NRC Information Notice 94-05, Potential Failure of Steam Generator Tubes Sleeved With 

Kinetically Welded Sleeves, U.S. Nuclear Regulatory Commission, January 19, 1994.

NRC Information Notice 94-43, Determination of Primary-to-Secondary Steam Generator Leak 

Rate, U.S. Nuclear Regulatory Commission, June 10, 1994.

NRC Information Notice 94-62, Operational Experience on Steam Generator Tube Leaks and 

Tube Ruptures, 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 94-88, Inservice Inspection Deficiencies Result in Severely Degraded 

Steam Generator Tubes, U.S. Nuclear Regulatory Commission, December 23, 1994.

NRC Information Notice 95-40, Supplemental Information to Generic Letter 95-03, 

Circumferential Cracking of Steam Generator Tubes, U.S. Nuclear Regulatory Commission, 

September 20, 1995.

NRC Information Notice 96-09, Damage in Foreign Steam Generator Internals, U.S. Nuclear 

Regulatory Commission, February 12, 1996.

NRC Information Notice 96-09, Supplement 1, Damage in Foreign Steam Generator Internals, 

U.S. Nuclear Regulatory Commission, July 10, 1996.

NRC Information Notice 96-38, Results of Steam Generator Tube Examinations, U.S. Nuclear 

Regulatory Commission, June 21, 1996.

NRC Information Notice 97-26, Degradation in Small-Radius U-Bend Regions of Steam 

Generator Tubes, U.S. Nuclear Regulatory Commission, May 19, 1997.

NRC Information Notice 97-49, B&W Once-Through Steam Generator Tube Inspection 

Findings, U.S. Nuclear Regulatory Commission, July 10, 1997.
NUREG-1801, Rev. 2 XI M19-8 December 2010

NRC Information Notice 97-79, Potential Inconsistency in the Assessment of the Radiological 

Consequences of a Main Steam Line Break Associated with the Implementation of Steam 

Generator Tube Voltage-Based Repair Criteria, U.S. Nuclear Regulatory Commission, 

November 20, 1997.

NRC Information Notice 97-88, Experiences During Recent Steam Generator Inspections, U.S. 

Nuclear Regulatory Commission, December 16, 1997.

NRC Information Notice 98-27, Steam Generator Tube End Cracking, U.S. Nuclear Regulatory 

Commission, July 24, 1998.

NRC Information Notice 2000-09, Steam Generator Tube Failure at Indian Point Unit 2, U.S. 

Nuclear Regulatory Commission, June 28, 2000.

NRC Information Notice 2001-16, Recent Foreign and Domestic Experience with Degradation of 

Steam Generator Tubes and Internals, U.S. Nuclear Regulatory Commission, October 31, 

2001.

NRC Information Notice 2002-02, Recent Experience with Plugged Steam Generator Tubes, 

U.S. Nuclear Regulatory Commission, January 8, 2002.

NRC Information Notice 2002-02, Supplement 1, Recent Experience with Plugged Steam 

Generator Tubes, U.S. Nuclear Regulatory Commission, July 17, 2002.

NRC Information Notice 2002-21, Axial Outside-Diameter Cracking Affecting Thermally Treated 

Alloy 600 Steam Generator Tubing, U.S. Nuclear Regulatory Commission, June 25, 2002.

NRC Information Notice 2002-21, Supplement 1, Axial Outside-Diameter Cracking Affecting 

Thermally Treated Alloy 600 Steam Generator Tubing, U.S. Nuclear Regulatory 

Commission, April 1, 2003.

NRC Information Notice 2003-05, Failure to Detect Freespan Cracks in PWR Steam Generator 

Tubes, U.S. Nuclear Regulatory Commission, June 5, 2003.

NRC Information Notice 2003-13, Steam Generator Tube Degradation at Diablo Canyon, U.S. 

Nuclear Regulatory Commission, August 28, 2003.

NRC Information Notice 2004-10, Loose Parts in Steam Generators, U.S. Nuclear Regulatory 

Commission, May 4, 2004.

NRC Information Notice 2004-16, Tube Leakage Due to a Fabrication Flaw in a Replacement 

Steam Generator, U.S. Nuclear Regulatory Commission, August 3, 2004.

NRC Information Notice 2004-17, Loose Part Detection and Computerized Eddy Current Data 

Analysis in Steam Generators, U.S. Nuclear Regulatory Commission, August 25, 2004.

NRC Information Notice 2005-09, Indications in Thermally Treated Alloy 600 Steam Generator 

Tubes and Tube-to-Tubesheet Welds, U.S. Nuclear Regulatory Commission, April 7, 2005.

NRC Information Notice 2005-29, Steam Generator Tube and Support Configuration, U.S. 

Nuclear Regulatory Commission, October 27, 2005.
December 2010 XI M19-9 NUREG-1801, Rev. 2

NRC Information Notice 2007-37, Buildup of Deposits in Steam Generators, U.S. Nuclear 

Regulatory Commission, November 23, 2007.

NRC Information Notice 2008-07, Cracking Indications in Thermally Treated Alloy 600 Steam 

Generator Tubes, U.S. Nuclear Regulatory Commission, April 24, 2008.

NRC Information Notice 2010-05, Management of Steam Generator Loose Parts and 

Automated Eddy Current Data Analysis, U.S. Nuclear Regulatory Commission, February 3, 

2010.

NRC Regulatory Issue Summary 2000-22, Issues Stemming from NRC Staff Review of Recent 

Difficulties Experienced in Maintaining Steam Generator Tube Integrity, U.S. Nuclear 

Regulatory Commission, November 3, 2000.

NRC Regulatory Issue Summary 2007-20, Implementation of Primary-to-Secondary Leakage 

Performance Criteria, U.S. Nuclear Regulatory Commission, August 23, 2007.

NRC Regulatory Issue Summary 2009-04, Steam Generator Tube Inspection Requirements, 

U.S. Nuclear Regulatory Commission, April 3, 2009.

NUREG-1430, Volume 1, Rev. 3, Standard Technical Specifications for Babcock and Wilcox 

Pressurized Water Reactors, U.S. Nuclear Regulatory Commission, December 2005.

NUREG-1431, Volume 1, Rev. 3, Standard Technical Specifications for Westinghouse 

Pressurized Water Reactors, U.S. Nuclear Regulatory Commission, December 2005.

NUREG-1432, Volume 1, Rev. 3, Standard Technical Specifications for Combustion 

Engineering Pressurized Water Reactors, U.S. Nuclear Regulatory Commission, December 

2005.

December 2010 XI M20-1 NUREG-1801, Rev. 2

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 period of 

extended operation. NRC GL 89-13 defines the OCCW system as a system or systems that 

transfer heat from safety-related structures, systems, and components (SSCs) to the ultimate 

heat sink (UHS). The guidelines of NRC GL 89-13 for managing an OCCW include

(a) surveillance and control of biofouling (see Chapter IX of NUREG-1801); (b) a test program to 

verify heat transfer capabilities; (c) routine inspection and a maintenance program to ensure that 

corrosion, erosion, protective coating failure, sediment deposition (silting), and biofouling cannot 

degrade the performance of safety-related systems serviced by OCCW; (d) a system walkdown 

inspection to ensure compliance with the licensing basis; and (e) a review of maintenance, 

operating, and training practices and procedures.

In accordance with guidance of NRC GL 89-13, the OCCW aging management program 

manages aging effects of components in raw water systems, such as the service water or river 

water, by using a combination of preventive, condition, and performance monitoring activities. 

These include (a) 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; (b) inspection of critical components 

for signs of corrosion, erosion, and biofouling; and (c) testing of the heat transfer capability of 

heat exchangers that remove heat from components important to safety. 

For buried OCCW piping, the aging effects on the external surfaces are managed by XI.M41, 

but the internal surfaces are managed by this program. The aging management of closed-cycle 

cooling water (CCCW) systems is described in XI.M21A, “Closed Treated Water Systems,” and 

is not included as part of this program. The OCCW System program applies to components 

constructed of various materials, including steel, stainless steel, aluminum, copper alloys, 

titanium, polymeric materials, and concrete. Piping may be lined with internal coatings or 

unlined.

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 generally found in 

OCCW systems and OCCW steel piping components with or without protective coating as 

described in the applicant’s response to NRC GL 89-13. OCCW systems, as defined by 

NRC GL 89-13, include the service water system and any other cooling system exposed to 

raw water that transfers heat from safety-related SSCs to the UHS. The OCCW System 

program applies to components constructed of various materials, including steel, stainless 

steel, aluminum, copper alloys, titanium, polymeric materials, and concrete. Piping may be 

lined with internal coatings or unlined.

2. Preventive Actions: Preventive actions begin with the use of appropriate material for 

construction. Steel piping system components are typically lined or coated to protect the 

underlying metal surfaces from exposure to corrosive cooling water environments. 

Implementation of NRC GL 89-13 includes control or preventive measures, such as 

chemical treatment whenever the potential for biological fouling exists or flushing of 
NUREG-1801, Rev. 2 XI M20-2 December 2010

infrequently used systems. Treatment with chemicals mitigates microbiologically-influenced 

corrosion (MIC) and buildup of macroscopic biological fouling debris from biota, such as 

blue mussels, oysters, or clams. Periodic flushing of the system removes accumulations of 

biofouling agents, corrosion products, and debris or silt.

3. Parameters Monitored/Inspected: This program manages the aging effects, such as loss 

of heat transfer capability, loss of material, and corrosion effects. 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 their 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: Inspection scope, methods (e.g., visual or nondestructive 

examination), and testing frequencies are in accordance with the applicant’s docketed 

response to NRC GL 89-13. Inspections for biofouling, damaged coatings, and degraded 

material condition are conducted. Visual inspections are typically performed to determine 

whether corrosion, erosion, or biofouling are occurring in the system. Examinations of 

polymeric materials should be consistent with the examinations described in AMP XI.M38.

Nondestructive testing, such as ultrasonic testing and eddy current testing, are effective 

methods to measure surface conditions or the extent of wall thinning associated with the 

service water system piping and components.

5. Monitoring and Trending: Heat transfer testing results are documented in plant test 

procedures and are trended in accordance with the applicant’s docketed response to NRC 

GL 89-13. If corrosion buildup or fouling is noted, the system also is evaluated for their 

impact on the heat transfer capability of the system. Evidence of corrosion in these systems 

also is evaluated for its potential impact on the integrity of the piping. For relevant 

indications, inspections or nondestructive testing is used to determine the extent of 

biofouling, the condition of the surface coating, the magnitude of localized pitting, and the 

amount of MIC, if applicable.

6. Acceptance Criteria: The acceptance criteria are in accordance with the applicant’s 

docketed response to NRC GL 89-13. Corrosion, erosion, and biofouling can cause 

significant loss of material in components. Inspected components should exhibit adequate 

design margin regarding design dimensions (e.g., minimum required wall thickness). As 

applicable, coatings or linings should be intact to protect the underlying metal. Heat removal 

capability is within allowable values for the system and components tested, in accordance 

with NRC GL 89-13. 

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 for GALL, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address the corrective actions.
December 2010 XI M20-3 NUREG-1801, Rev. 2

8. Confirmation Process: Site quality assurance 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process controls.

9. Administrative Controls: As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls. 

10. Operating Experience: Significant MIC (NRC Information Notice [IN] 85-30, IN 07-06), 

failure of protective coatings (NRC IN 85-24), and fouling (NRC IN 81-21, IN 86-96, IN 07-

04, IN 07-28) have been observed in a number of heat exchangers. The guidance of NRC 

GL 89-13 has been implemented for more than 20 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, 2009.

EPRI 1016555, PWR Secondary Water Chemistry Guidelines–Revision 7, Electric Power 

Research Institute, Palo Alto, CA, February 2009. 

EPRI 1014986, PWR Primary Water Chemistry Guidelines-Revision 6, Volumes 1 and 2, 

Electric Power Research Institute, Palo Alto, CA, December 2007. 

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.

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.

NRC Information Notice 2004-07, Plugging of Safety Injection Pump Lubrication Oil Coolers 

With Lakeweed, U.S. Nuclear Regulatory Commission, April 7, 2004.
NUREG-1801, Rev. 2 XI M20-4 December 2010

NRC Information Notice 2007-28, Potential Common Cause Vulnerabilities in Essential Service 

Water Systems Due to Inadequate Chemistry Controls, U.S. Nuclear Regulatory 

Commission, September 17, 2007.

NRC Information Notice 2007-06, Potential Common Cause Vulnerabilities in Essential Service 

Water Systems, U.S. Nuclear Regulatory Commission, February 9, 2007.

NUREG-1915, Safety Evaluation Report Related to the License Renewal of Wolf Creek 

Generating Station, U.S. Nuclear Regulatory Commission, October 2008.
December 2010 XI M21A-1 NUREG-1801, Rev. 2

XI.M21A CLOSED TREATED WATER SYSTEMS 

Program Description

Nuclear power plants contain many closed, treated water systems. These systems undergo 

water treatment to control water chemistry and prevent corrosion (i.e., treated water systems). 

These systems are also recirculating systems in which the rate of recirculation is much higher 

than the rate of addition of makeup water (i.e., closed systems). The program includes (a) water 

treatment, including the use of corrosion inhibitors, to modify the chemical composition of the 

water such that the function of the equipment is maintained and such that the effects of 

corrosion are minimized; (b) chemical testing of the water to ensure that the water treatment 

program maintains the water chemistry within acceptable guidelines; and (c) inspections to 

determine the presence or extent of corrosion and/or cracking. Depending on the industry 

standard selected for use in association with this aging management program (AMP) and/or 

plant operating experience, this program also may include corrosion monitoring (e.g., corrosion 

coupon testing) and microbiological testing.

Evaluation and Technical Basis

1. Scope of Program: This program manages the aging effects of reduction of heat transfer 

due to fouling, or the loss of material from and cracking due to corrosion and/or stress 

corrosion cracking of the internal surfaces of piping, piping components, and piping 

elements fabricated from any material and exposed to treated water. Not included are those 

piping systems that are managed by another AMP. Examples of systems managed by this 

AMP include closed-cycle cooling water systems (as defined by U.S. Nuclear Regulatory 

Commission [NRC] Generic Letter [GL] 89-1314

2. Preventive Actions: This program mitigates aging effects of loss of material and cracking 

that are due to corrosion and stress corrosion cracking through water treatment. The water 

treatment program includes corrosion inhibitors and is designed to maintain the function of 

associated equipment and minimize the corrosivity of the water.

); closed portions of heating, ventilation, and 

air conditioning systems; diesel generator cooling water; and auxiliary boiler systems. 

Examples of systems not addressed by this AMP include boiling water reactor (BWR) 

coolant, pressurized water reactor (PWR) primary and secondary water, and PWR/BWR 

condensate systems. Aging in these systems is managed by the water chemistry AMP 

(XI.M2) and American Society of Mechanical Engineers (ASME) Section XI, Inservice 

Inspection, Subsections IWB, IWC, and IWD AMP (XI.M1). Treated fire water systems, if 

present, are also not included in this AMP. The water used in systems covered by this AMP 

may, but need not, be demineralized. The water used in systems covered by this AMP 

receives chemical treatment, including corrosion inhibitors. Untreated water systems are 

addressed using other AMPs, such as Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components (XI.M38).

3. Parameters Monitored/Inspected: This program monitors water chemistry (preventive 

monitoring) and the visual appearance of surfaces exposed to the water (condition 

monitoring). Depending on the industry standard selected for use in association with this 

 

14 NRC GL 89-13 defines a service water system as “the system or systems that transfer heat from safety-related 

structures, systems, or components to the ultimate heat sink.” NRC GL 89-13 further defines a closed-cycle system 

as a part of the service water system that is not subject to significant sources of contamination, one in which water 

chemistry is controlled and in which heat is not directly rejected to an ultimate heat sink.
NUREG-1801, Rev. 2 XI M21A-2 December 2010

AMP and/or plant operating experience, this program may also include corrosion monitoring 

(e.g., corrosion coupon testing) and microbiological testing. These parameters (such as the 

concentration of iron, copper, silica, oxygen; and hardness, alkalinity, specific conductivity, 

and pH) are monitored because maintenance of optimal water chemistry prevents loss of 

material and cracking due to corrosion and stress corrosion cracking. In addition, the visual 

appearance of surfaces provides evidence of the existence of loss of material or cracking. 

The specific water chemistry parameters monitored and the acceptable range of values for 

these parameters are in accordance with industry standard guidance documents produced 

by the Electric Power Research Institute (EPRI), the American Society of Heating 

Refrigeration and Air-Conditioning Engineers, the Cooling Technology Institute, the 

American Boiler Manufacturer’s Association, ASTM standards, water chemistry guidelines 

recommended by the equipment manufacturer, Nalco Water Handbook, or the ASME. For 

closed-cycle cooling water systems as defined in NRC GL 89-13, EPRI 1007820 is used. 

For other systems, the applicant selects an appropriate industry standard document. In all 

cases, the selected industry standard guidance document is used in its entirety for the water 

chemistry control or guidance.

4. Detection of Aging Effects: In this program, aging effects are detected through water 

testing and periodic inspections. Water testing ensures that the water treatment program is 

effective in maintaining acceptable water chemistry. Water testing is conducted in 

accordance with the selected industry standard. The frequency of water testing is in 

accordance with the selected industry standard, but in no case should the testing interval be 

greater than quarterly unless justified with an additional analysis. Because the control of 

water chemistry may not be fully effective in mitigating the aging effects, visual inspections 

are conducted. Inspections are conducted whenever the system boundary is opened. 

Additionally, a representative sample of piping and components is selected based on 

likelihood of corrosion or cracking and inspected at an interval not to exceed once in 10 

years. When required by the ASME Code, inspections are conducted in accordance with the 

applicable code requirements. In the absence of Code inspection requirements, inspections 

are conducted in accordance with the selected industry standard. In the event that the 

selected industry standard does not contain inspection requirements, plant-specific 

inspection and personnel qualification procedures that are capable of detecting corrosion or 

cracking may be used. If visual examination identifies adverse conditions, additional 

examinations, including ultrasonic testing, are conducted. Plant operating experience and/or 

the industry standard program selected for use in association with this AMP may 

recommend corrosion testing and/or microbiological testing. If warranted, these tests are 

conducted in accordance with the industry standard selected or other industry standards 

appropriate for the conduct of corrosion or microbiological testing.

5. Monitoring and Trending: Water chemistry data are evaluated against the standards 

contained in the selected industry standard documents. These data are trended with time, 

so corrective actions are taken, based on trends in water chemistry, prior to loss of intended 

function. Inspection results also are trended with time so that the progression of any 

corrosion or cracking can be evaluated and predicted.

6. Acceptance Criteria: Water chemistry concentrations are maintained within the limits 

specified in the selected industry standard documents. System components should meet 

system design requirements, such as minimum wall thickness.

7. Corrective Actions: Water chemistry concentrations that are not in accordance with the 

selected industry standard document should be returned to an “in specification” condition in 
December 2010 XI M21A-3 NUREG-1801, Rev. 2

accordance with the referenced guidelines. Some industry standard documents have time 

guidelines which govern how rapidly “out of specification” conditions should be corrected. As 

discussed in the Appendix for GALL, the staff finds the requirements of 10 CFR Part 50, 

Appendix B, acceptable to address corrective actions.

8. Confirmation Process: Site quality assurance 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process and administrative controls.

9. Administrative Controls: As discussed in the Generic Aging Lessons Learned (GALL) 

Report, the staff finds the requirements 10 CFR Part 50, Appendix B, acceptable to address 

the administrative controls.

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 LER 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, 2009. 

EPRI 1007820, Closed Cooling Water Chemistry Guideline, Electric Power Research Institute, 

Palo Alto, CA, April 2004. 

Flynn, Daniel. The Nalco Water Handbook, Nalco Company, 2009.

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.

NRC Licensee Event Report 50-280/91-019-00, Loss of Containment Integrity due to Crack in 

Component Cooling Water Piping, October 26, 1991. 

NRC Licensee Event Report 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. 

December 2010 XI M22-1 NUREG-1801, Rev. 2

XI.M22 BORAFLEX MONITORING

Program Description

For Boraflex panels in spent fuel storage racks, gamma irradiation and long-term exposure to 

the wet fuel pool environment causes 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. A monitoring program for the 

Boraflex panels in the spent fuel storage racks is implemented to assure that no unexpected 

degradation of the Boraflex material compromises the criticality analysis in support of the design 

of spent fuel storage racks. This aging management program (AMP) relies on periodic 

inspection, testing, monitoring, and analysis of the criticality design to assure that the required 

5% subcriticality margin is maintained. Therefore, this AMP includes: (a) completing sampling 

and analysis for silica levels in the spent fuel pool water on a regular basis, such as monthly, 

quarterly, or annually (depending on Boraflex panel condition), and trending the results by using 

the EPRI RACKLIFE predictive code or its equivalent; and (b) performing neutron attenuation 

testing or blackness testing to determine gap formation in Boraflex panels or measuring boron 

areal density by techniques such as the BADGER device.

Evaluation and Technical Basis

1. Scope of Program: This program manages the effect of reduction in neutron-absorbing 

capacity due to degradation in sheets of neutron-absorbing material made of Boraflex 

affixed to spent fuel racks.

2. Preventive Actions: This program is a performance monitoring program and does not 

include preventive actions.

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. 

4. Detection of Aging Effects: Aging effects on Boraflex panels are detected by monitoring 

silica levels in the spent fuel storage pool on a regular basis, such as monthly, quarterly, or 

annually (depending on Boraflex panel condition); by performing blackness testing to 

measure gap formation or measuring boron areal density on a frequency determined by the 

material condition of the Boraflex panels, with a minimum frequency of once every 5 years; 

and by applying predictive methods to the measured results. The amount of boron carbide

present in the Boraflex panels is determined through direct measurement of boron areal 

density by blackness testing or by periodic verification of boron loss through areal density 
NUREG-1801, Rev. 2 XI M22-2 December 2010

measurement techniques, such as the BADGER device. Frequent Boraflex testing is 

sufficient to ensure that Boraflex panel degradation does not compromise criticality analysis 

for the spent fuel pool storage racks. Additionally, changes in the level of silica present in 

the spent fuel pool water provide an indication of changes in the rate of degradation of 

Boraflex panels. 

5. Monitoring and Trending: The periodic inspection measurements and analysis are 

compared to values of previous measurements and analysis providing a continuing level of 

data for trend analysis. Sampling and analysis for silica levels in the spent fuel pool water is 

performed on a regular basis, such as monthly, quarterly, or annually (depending on 

Boraflex panel condition), and results are trended using the EPRI RACKLIFE predictive 

code or its equivalent. The frequency to perform blackness testing will be determined by the 

material condition of the Boraflex panels, with a maximum of 5 years.

6. Acceptance Criteria: The 5% subcriticality margin of the spent fuel racks is 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 for GALL, 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, 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 for GALL, the 

staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls. 

10. Operating Experience: NRC IN 87-43 addresses the problems of development of tears and 

gaps (average 1-2 inches, with the largest 4 inches) in Boraflex sheets due to gamma 

radiation-induced shrinkage of the material. NRC IN 93-70, NRC IN 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 provide reasonable assurance that the Boraflex sheets maintain 

their integrity and are effective in performing their intended function. 
December 2010 XI M22-3 NUREG-1801, Rev. 2

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009. 

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 1003413, Guidance and Recommended Procedure for Maintaining and Using RACKLIFE 

Version 1.10, Electric Power Research Institute, Palo Alto, CA, April 2002. 

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.

December 2010 XI M23-1 NUREG-1801, Rev. 2

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. Because only a few cranes operate over safety-related equipment, 

normally fewer than 10 cranes fall within the scope of 10 CFR 54.4. 

Many of the systems and components of these cranes perform an intended function with moving 

parts or with a change in configuration or are 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. 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. The aging 

management activities specified in this program utilize the guidance provided in American 

Society of Mechanical Engineers (ASME) Safety Standard B30.2, “Overhead and Gantry 

Cranes (Top Running Bridge, Single or Multiple Girder, Top Running Trolley Hoist).” 

Evaluation and Technical Basis

1. Scope of Program: The program manages (a) the effects of loss of material due to general 

corrosion on the bridge rails, bridge, and trolley structural components for those cranes that 

are within the scope of 10 CFR 54.4 and (b) the effects of wear on the rails in the rail 

system. The program also manages the effects of loss of preload of bolted connections. 

2. Preventive Actions: This program is a condition monitoring program. No preventive actions 

are identified. 

3. Parameters Monitored/Inspected: Surface condition is monitored by visual inspection to 

ensure that loss of material is not occurring due to corrosion or wear. Bolted connections are 

monitored for loose bolts, missing or loose nuts, and other conditions indicative of loss of 

preload.

4. Detection of Aging Effect: Crane rails and structural components are visually inspected at 

a frequency in accordance ASME B30.2, “Overhead and Gantry Cranes (Top Running 

Bridge, Single or Multiple Girder, Top Running Trolley Hoist),” or other appropriate standard 

in the ASME B30 series. For systems that are infrequently in service, such as containment 

polar cranes, periodic inspections are performed once every refueling cycle just prior to use. 

Bolted connections are visually inspected for loose bolts or missing nuts at the same 

frequency as crane rails and structural components.

5. Monitoring and Trending: Visual inspection activities are performed by personnel qualified 

in accordance with controlled procedures and processes. Deficiencies are documented 

using applicant-approved processes and procedures, such that results can be trended; 

however, the program does not include formal trending. 
NUREG-1801, Rev. 2 XI M23-2 December 2010

6. Acceptance Criteria: Any visual indication of loss of material due to corrosion or wear and 

any visual sign of loss of bolting pre-load is evaluated according to ASME B30.2 or other 

applicable industry standard in the ASME B30 series.

7. Corrective Actions: Repairs are performed as specified in ASME B30.2 or other 

appropriate standard in the ASME B30 series. 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 for GALL, 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: 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process and administrative controls. 

9. Administrative Controls: As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls. 

10. Operating Experience: There has been no history of corrosion-related degradation that 

threatened the ability of a crane to perform its intended function. Likewise, because cranes 

have not been operated beyond their design lifetime, there have been no significant fatiguerelated structural failures. Operating experience indicates that loss of bolt preload has 

occurred, but not to the extent that it has threatened the ability of a crane structure to 

perform its intended function.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009. 

10 CFR 54.4, Scope, Office of the Federal Register, National Archives and Records 

Administration, 2009. 

ASME Safety Standard B30.2, Overhead and Gantry Cranes (Top Running Bridge, Single or 

Multiple Girder, Top Running Trolley Hoist), American Society of Mechanical Engineers, 

2005.

NRC Generic Letter 80-113, Control of Heavy Loads, U.S. Nuclear Regulatory Commission, 

December 22, 1980.

NRC Generic Letter 81-07, Control of Heavy Loads, U.S. Nuclear Regulatory Commission, 

February 3, 1981.

NRC Regulatory Guide 1.160, Rev. 2, Monitoring the Effectiveness of Maintenance at Nuclear 

Power Plants, U.S. Nuclear Regulatory Commission, March 1997.
December 2010 XI M23-3 NUREG-1801, Rev. 2

NUREG-0612, Control of Heavy Loads at Nuclear Power Plants, U.S. Nuclear Regulatory 

Commission, 1980.

December 2010 XI M24-1 NUREG-1801, Rev. 2

XI.M24 COMPRESSED AIR MONITORING

Program Description

The purpose of the compressed air monitoring program is to provide reasonable assurance of

the integrity of the compressed air system. The program consists of monitoring moisture 

content, corrosion, and performance of the compressed air system. This includes (a) preventive 

monitoring of water (moisture) and other potential contaminants to keep within the specified 

limits; and (b) inspection of components for indications of loss of material due to corrosion.

The compressed air monitoring aging management program (AMP) is based on results of the 

plant owner’s response to Nuclear Regulatory Commission (NRC) Generic Letter (GL) 88-14 (as 

applicable to license renewal) and reported in previous NRC Information Notices (IN) 81-38; IN 

87-28; IN 87-28, Supplement 1; and by the Institute of Nuclear Power Operations Significant 

Operating Experience Report (INPO SOER) 88-01. NRC GL 88-14, issued after several years of 

study of problems and failures of instrument air systems, recommends that each holder of an 

operating license perform an extensive design and operations review and verification of its 

instrument air system. NRC GL 88-14 also recommends that the licensees describe their 

program for maintaining proper instrument air quality. This AMP does not include all aspects of 

NRC GL 88-14 because many of the issues in the GL are not relevant to license renewal.

This AMP does not change the applicant’s docketed response to NRC GL 88-14 for the rest of 

its operations. The program utilizes the aging management aspects of the applicant’s response 

to NRC GL 88-14 for license renewal with regard to preventative measures, inspections of 

components, and testing to ensure that the compressed air system will be able to perform its 

intended function for the period of extended operation. The AMP also incorporates the air 

quality provisions provided in the guidance of the Electric Power Research Institute (EPRI) NP7079. EPRI NP-7079 was 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. The American Society of Mechanical Engineers (ASME) operations and 

maintenance standards and guides (ASME OM-S/G-1998, Part 17) provides additional 

guidance for 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 aging effects of loss of material due to 

corrosion in compressed air systems.

2. Preventive Actions: For the purposes of aging management, moisture and other corrosive 

contaminants in the system’s air are maintained below specified limits to ensure that the 

system and components maintain their intended functions. These limits are prepared from 

consideration of manufacturer's recommendations for individual components and guidelines 

based on ASME OM-S/G-1998, Part 17; American National Standards Institute (ANSI)/ISAS7.0.01-1996; EPRI NP-7079; and EPRI TR-108147.

3. Parameters Monitored/Inspected: Maintaining moisture and other corrosive contaminants 

below acceptable limits mitigates loss of material due to corrosion. Periodic air samples are 

taken and analyzed for moisture and other corrosives. Periodic and opportunistic 
NUREG-1801, Rev. 2 XI M24-2 December 2010

inspections of accessible internal surfaces are performed for signs of corrosion and 

abnormal corrosion products that might indicate a loss of material within the system. 

4. Detection of Aging Effects: Moisture and other corrosives increase the potential for loss of 

material due to corrosion. The program periodically samples and tests the air quality in the 

compressed system for moisture in accordance with industry standards, such as ANSI/ISAS7.0.01-1996. Typically, compressed systems have in-line dew point instrumentation that 

either checks continuously using an automatic alarm system or is checked at least daily to 

ensure that moisture content is within specifications. Additionally, periodic visual inspections 

of critical component internal surfaces (compressors, dryers, after-coolers, and filters) are 

performed for signs of loss of material due to corrosion. ASME O/M-S/G-1998, Part 17 

provides guidance for inspection frequency and inspection methods of these components. 

5. Monitoring and Trending: Daily readings of system dew point are recorded and trended. 

Air quality analysis results are reviewed to determine if alert levels or limits have been 

reached or exceeded. This review also checks for unusual trends. ASME O/M-S/G-1998, 

Part 17, provides guidance for monitoring and trending data. Visual inspection results are 

compared to previous results to ascertain if adverse long-term trends exist. The effects of 

corrosion are monitored by visual inspection. Test data are analyzed and compared to data 

from previous tests to provide for the timely detection of aging effects on passive 

components.

6. Acceptance Criteria: Acceptance criteria for air quality moisture limits are established 

based on accepted industry standards, such as ANSI/ISA-S7.0.01-1996. Internal surfaces 

should not show signs of corrosion (general, pitting, and crevice) that could indicate the 

potential loss of function of the component. Manufacturers’ certifications can be used to 

demonstrate that the bottled air meets acceptable quality standards. 

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 for GALL, 

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 for GALL, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address the confirmation process and administrative controls.

9. Administrative Controls: 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address administrative controls.

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, Supplement 1; and 

License Event Report 50-237/94-005-3. Some of the systems that have been significantly 

degraded or that 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 

systems. In 2008, one plant incurred an unplanned reactor trip from a failure of a 

mechanical joint in the instrument air system (NRC IN 2008-06). Nevertheless, as a result of 
December 2010 XI M24-3 NUREG-1801, Rev. 2

NRC GL 88-14 and in consideration of INPO SOER 88-01, EPRI NP-7079, and EPRI TR108147, 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, 2009. 

ANSI/ISA-S7.0.01-1996, Quality Standard for Instrument Air, American National Standards 

Institute (ANSI), 1996.

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, Nuclear Maintenance Application Center, 

Palo Alto, CA, March 1998.

INPO Significant Operating Experience Report 88-01, Instrument Air System Failures, Institute 

of Nuclear Power Operations, 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 Information Notice 2008-06, Instrument Air System Failure Resulting In Manual Reactor 

Trip, U.S. Nuclear Regulatory Commission, April 10, 2008.

NRC Licensee Event Report 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. 

December 2010 XI M25-1 NUREG-1801, Rev. 2

XI.M25 BWR REACTOR WATER CLEANUP SYSTEM

Program Description

This program provides inspection to manage the aging effects of cracking due to stress 

corrosion cracking (SCC) or intergranular stress corrosion cracking (IGSCC) on the intended 

function of austenitic stainless steel (SS) piping outboard of the second primary containment 

isolation valves 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 in NRC Generic Letter (GL) 88-01 and its Supplement 1. The aging management 

review (AMR) Item in the GALL Report that credits this program also credits AMP XI.M2, “Water 

Chemistry,” to provide mitigation of the aging effects. Reactor coolant water chemistry is 

monitored and maintained in accordance with the Water Chemistry program. 

NRC GL 88-01 applies to all boiling water reactor (BWR) piping made of austenitic SS that is 4 

inches or larger in nominal diameter and contains reactor coolant at a temperature above 

93.3o C (200o F) during power operation regardless of code classification. NRC GL 88-01 

requests, in part, that affected licensees implement an ISI program conforming to staff positions 

for austenitic SS piping covered under the scope of the letter. In response to NRC GL 88-01, 

affected licensees undertook ISI in accordance with the scope and schedules described in the 

letter and included affected portions of RWCU piping outboard of the second isolation valves in 

their ISI programs.

The NRC issued GL 88-01, Supplement 1, to provide acceptable alternatives to staff positions 

delineated in NRC GL 88-01. In NRC GL 88-01, Supplement 1, the staff noted, in part, that the 

position stated in NRC GL 88-01 on inspection sample size of RWCU system welds outboard of 

the second isolation valves had created an unnecessary hardship for affected licensees 

because of the very high radiation levels associated with this portion of RWCU piping. The staff 

also noted that affected licensees had requested that they be exempted from NRC GL 88-01 

with regard to inspection of this piping of the RWCU system. Although NRC GL 88-01, 

Supplement 1, does not provide explicit generic guidance with regard to staff criteria for 

reduction or elimination of RWCU weld inspections, it does suggest that the staff would be 

receptive to modifications to a licensee’s original docketed NRC GL 88-01 response for RWCU 

weld inspections, provided all issues of reactor safety were adequately addressed. The staff has 

subsequently allowed individual licensees to modify their docketed responses to GL-88-01 to 

reduce or eliminate their ISI of RWCU welds in the piping outboard of the second isolation 

valves. This AMP is based on the staff-approved screening criteria for the inspection.

Evaluation and Technical Basis

1. Scope of Program: This program provides ISI to manage the aging effects of cracking due 

to SCC or IGSCC in austenitic SS piping outboard of the second containment isolation 

valves in the RWCU system.

The components included in this program are the welds in piping that have a nominal 

diameter of 4 inches or larger and that contain reactor coolant at a temperature above 93°C

(200°F) during power operation, regardless of code classification.

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 
NUREG-1801, Rev. 2 XI M25-2 December 2010

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). 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.

3. Parameters Monitored/Inspected: The aging management program (AMP) monitors SCC 

or IGSCC of austenitic SS piping by detecting and sizing cracks in accordance with the 

requirements of American Society of Mechanical Engineers (ASME) Code, Section XI; the 

guidelines of NUREG-0313, NRC GL 88-01, and NRC GL 88-01, Supplement 1; and the 

NRC screening criteria as described in Element 4 for the RWCU piping outboard of the 

second isolation valves.

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 and GL 88-01, Supplement 1, and subsequent licensing 

correspondence. Consistent with the NRC guidelines and with licensees’ completion of all 

actions requested in NRC GL 89-10, no inspection of the outboard piping is required for (a) 

piping systems that are made of IGSCC-resistant piping materials or (b) piping with no 

IGSCC detected inboard of the second isolation valves (ongoing GL 88-01 inspection) and 

outboard of the second isolation valves (after inspecting a minimum of 10% of susceptible 

piping welds). For piping that includes a non-resistant base or weld material in the scope of 

the program or piping that has experienced IGSCC, either inboard or outboard of the second 

isolation valves, an inspection of at least 2% of the welds or two welds, whichever is greater, 

is performed on the portions of the RWCU system outboard of the second isolation valves 

every refueling outage.

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: NRC GL 88-01 recommends that any indication detected be 

evaluated in accordance with the requirements of ASME Code, Section XI, Subsection IWB3640.

15

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 for GALL, the staff 

finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective 

actions. 

 

15 Refer to the GALL Report, Chapter I, for applicability of other editions of the ASME Code, Section XI.
December 2010 XI M25-3 NUREG-1801, Rev. 2

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with requirements of 

10 CFR Part 50, Appendix B. As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process and administrative controls.

9. Administrative Controls: As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: The IGSCC has occurred in small- and large-diameter boiling water 

reactor (BWR) piping made of austenitic stainless steels. 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, 2009. 

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, The 

ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 50.55a The 

American Society of Mechanical Engineers, New York, NY.

Letter from Joseph W. Shea, U.S. Nuclear Regulatory Commission, to George A. Hunger, 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. (ADAMS Accession Number ML090930466)

Letter from Robert M. Pulsifer, U.S. Nuclear Regulatory Commission, to Michael A Balduzzi, 

Vermont Yankee Nuclear Power Corporation, Review of Request to Discontinue 

Intergranular Stress Corrosion Cracking Inspection of RWCU Piping Welds Outboard of the 

Second Containment Isolation Valves (TAC No. MB0468), March 27, 2001. (ADAMS 

Accession Number ML010780094)

NRC Generic Letter 88-01, NRC Position on IGSCC in BWR Austenitic Stainless Steel Piping,

U.S. Nuclear Regulatory Commission, January 25, 1988.

NRC Generic Letter 88-01, Supplement 1, NRC Position on IGSCC in BWR Austenitic Stainless 

Steel Piping, U.S. Nuclear Regulatory Commission, February 4, 1992.

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.

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.

December 2010 XI M26-1 NUREG-1801, Rev. 2

XI.M26 FIRE PROTECTION

Program Description

For operating plants, the Fire Protection aging management program (AMP) includes a fire 

barrier 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 AMP also includes periodic inspection and testing of the halon/carbon dioxide 

(CO2) fire suppression system. 

Evaluation and Technical Basis

1. Scope of Program: This program manages the effects of loss of material and cracking, 

increased hardness, shrinkage and loss of strength on the intended function of the 

penetration seals; fire barrier walls, ceilings, and floors; other fire resistance materials (e.g., 

flamastic, 3M fire wrapping, spray-on fire proofing material, intumescent coating, etc.) that 

serve a fire barrier function; 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 halon/CO2

fire suppression system. 

2. Preventive Actions: This is a condition monitoring program. However, 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 not less than 10% of each type of 

penetration seal is performed during walkdowns. 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 that are directly caused by increased 

hardness, and shrinkage of seal material due to loss of material. Visual inspection of the fire 

barrier walls, ceilings, and floors and other fire barrier materials detects any sign of 

degradation, such as cracking, spalling, and loss of material caused by freeze-thaw, 

chemical attack, and reaction with aggregates that could affect their intended fire protection 

function. Fire-rated doors are visually inspected to detect any degradation of door surfaces. 

The periodic visual inspection and function test are performed to examine for signs of 

corrosion that may lead to the loss of material of the halon/CO2 fire suppression system. 

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 personnel of not less than 10% of each type of seal in walkdowns 

is performed at a frequency in accordance with an NRC-approved fire protection program 

(e.g., Technical Requirements Manual, Appendix R program, etc.) or at least once every 

refueling outage. 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 personnel of the fire barrier walls, ceilings, floors, doors, and other fire barrier 

materials performed in walkdowns at a frequency in accordance with an NRC-approved fire 

protection program ensure timely detection of concrete cracking, spalling, and loss of 

material. Visual inspection by fire protection qualified personnel detects any sign of 
NUREG-1801, Rev. 2 XI M26-2 December 2010

degradation of the fire doors, 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. 

Visual inspections of the halon/CO2 fire suppression system are performed to detect any 

sign of corrosion. The periodic functional test is performed at least once every 6 months or 

on a schedule in accordance with an NRC-approved fire protection program. Inspections are 

performed to detect degradation of the halon/CO2 fire suppression system before the loss of 

the component intended function. 

5. Monitoring and Trending: The results of inspections of the aging effects of cracking, 

spalling, and loss of material on fire barrier penetration seals, fire barriers, and fire doors are 

used to trend future actions.

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 signs of degradation 

that could result in the loss of the fire protection capability due to loss of material. The 

acceptance criteria include (a) 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; (b) no significant 

indications of concrete cracking, spalling, and loss of material of fire barrier walls, ceilings, 

and floors and in other fire barrier materials; (c) no visual indications of missing parts, holes, 

and wear; and (d) no deficiencies in the functional tests of fire doors. Also, no indications of 

excessive loss of material due to corrosion in the halon/CO2 fire suppression system is 

acceptable. 

7. Corrective Actions: For fire protection structures and components identified 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 corrective action program

is documented in the final safety analysis report supplement in accordance with 10 CFR 

54.21(d). As discussed in the Appendix for GALL, 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: As discussed in the Appendix for GALL, 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: Silicone foam fire barrier penetration seals have experienced splits, 

shrinkage, voids, lack of fill, and other failure modes (U.S. Nuclear Regulatory Commission 

[NRC] Information Notice [IN] 88-56, IN 94-28, and IN 97-70). Degradation of electrical 

raceway fire barrier such as small holes, cracking, and unfilled seals are found on routine 

walkdown (NRC IN 91-47 and NRC Generic Letter 92-08). Fire doors have experienced 

wear of the hinges and handles. 
December 2010 XI M26-3 NUREG-1801, Rev. 2

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009. 

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. 

December 2010 XI M27-1 NUREG-1801, Rev. 2

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, fire pump casings, hydrants, hose stations, 

standpipes, water storage tanks, and aboveground, buried, 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 tested 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. These NFPA sections state “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 water-based fire protection system piping is subjected to required flow testing in 

accordance with guidance in NFPA 25 to verify design pressure or evaluated for wall thickness 

(e.g., non-intrusive 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 

determined by engineering evaluation of the fire protection piping to ensure that degradation is 

detected before the loss of intended function. The purpose of the full flow testing and wall 

thickness evaluations is to ensure that corrosion, microbiologically influenced corrosion (MIC), 

or biofouling is managed such that the system function is maintained.

Chapter XI.M41 describes the aging management program for buried and underground waterbased fire protection system piping and tanks.

Evaluation and Technical Basis

1. Scope of Program: The AMP focuses on managing loss of material due to corrosion, MIC, 

or biofouling of steel components in fire protection systems exposed to water. Fire hose 

stations and standpipes are considered as piping in the AMP. Fire hoses and gaskets can 

be excluded from the scope of license renewal if the standards that are relied upon to 

prescribe replacement of the hose and gaskets are identified in the scoping methodology 

description.

2. Preventive Actions: To ensure that no significant corrosion, MIC, or biofouling has 

occurred in water-based fire protection systems, periodic flushing and system performance 

testing are conducted in accordance with NFPA 25. 

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 
NUREG-1801, Rev. 2 XI M27-2 December 2010

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. Testing of sprinklers ensures that 

degradation is detected in timely manner. 

4. Detection of Aging Effects: The water-based fire protection system testing is performed to 

ensure that the system functions by maintaining required operating pressures. Wall 

thickness evaluations of fire protection piping are performed on system components using 

non-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 are capable of evaluating (a) wall 

thickness to ensure against catastrophic failure and (b) 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 is 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 

that 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 to detect 

degradation before a loss of intended function can occur. Sprinkler heads are tested before 

the end of the 50-year sprinkler head service life and at 10-year intervals thereafter during 

the period of extended 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 nonintrusive or visual inspection is evaluated. 
December 2010 XI M27-3 NUREG-1801, Rev. 2

6. Acceptance Criteria: The acceptance criteria are (a) the water-based fire protection system 

is able to maintain required pressure, (b) no unacceptable signs of degradation are 

observed during non-intrusive or visual inspection of components, (c) minimum design pipe 

wall thickness is maintained, and (d) no biofouling exists in the sprinkler systems that could 

cause corrosion in the sprinklers. 

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 aging 

management review (AMR) for license renewal, the applicant’s 10 CFR Part 50, Appendix B, 

program is used for corrective actions for aging management during the period of extended 

operation. As discussed in the Appendix for GALL, the staff finds the requirements of 10 

CFR Part 50, Appendix B, acceptable to address the corrective actions.

8. Confirmation Process: 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 confirmation process for aging management during the period of 

extended operation. As discussed in the Appendix for GALL, the staff finds the requirements 

of 10 CFR Part 50, Appendix B, acceptable to address the confirmation process. 

9. Administrative Controls: For the water-based 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 administrative controls for aging management 

during the period of extended operation. As discussed in the Appendix for GALL, the staff 

finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

administrative controls. 

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, 2009. 

NFPA 25, Inspection, Testing and Maintenance of Water-Based Fire Protection Systems, 1998 

Edition, National Fire Protection Association.

NFPA 25, Inspection, Testing and Maintenance of Water-Based Fire Protection Systems, 2002 

Edition, National Fire Protection Association.

December 2010 XI M29-1 NUREG-1801, Rev. 2

XI.M29 ABOVEGROUND METALLIC TANKS

Program Description

The Aboveground Metallic Tanks aging management program (AMP) manages the effects of 

loss of material on the outer surfaces of above ground tanks constructed on concrete or soil. If 

the tank exterior is fully visible, the program for inspection of external surfaces may be used 

instead (XI.M36). This program credits the standard industry practice of coating or painting the 

external of steel tanks as a preventive measure to mitigate corrosion. The program relies on 

periodic inspections 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 performed to ensure that significant degradation in inaccessible locations is not 

occurring and that the component intended function is maintained during the period of extended 

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 periodic inspections of metallic tanks (with or 

without coatings) to manage the effects of corrosion on the intended function of these tanks. 

Inspections cover the entire outer surface of the tank. Because lower portions of the tank 

are on concrete or soil, this program includes the bottom of the tank as well. If the tank 

exterior is fully visible, the program for inspection of external surfaces may be used instead 

(AMP XI.M36).

2. Preventive Actions: In accordance with industry practice, tanks may be coated with 

protective paint or coating to mitigate corrosion by protecting the external surface of the tank 

from environmental exposure. Sealant or caulking may be applied at the external interface 

between the tank and concrete or earthen foundation to mitigate corrosion of the bottom 

surface of the tank by minimizing the amount of water and moisture penetrating the 

interface, which would lead to corrosion of the bottom surface.

3. Parameters Monitored/Inspected: The AMP utilizes periodic plant inspections to monitor 

degradation of coatings, sealants, and caulking because it is a condition directly related to 

the potential loss of materials. Additionally, thickness measurements of the bottoms of the 

tanks are made periodically for the tanks monitored by this program as an additional 

measure to ensure that loss of material is not occurring at locations that are inaccessible for 

inspection.

4. Detection of Aging Effects: Degradation of an exterior metallic surface can occur in the 

presence of moisture; therefore, an inspection of the coating is performed to ensure that the 

surface is protected from moisture. Conducting periodic visual inspections at each outage 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. Potential 

corrosion of tank bottoms is determined by taking ultrasonic testing (UT) thickness 

measurements of the tank bottoms whenever the tank is drained and at least once within 5 

years of entering the period of extended operation. Measurements are taken to ensure that 

significant degradation is not occurring and that the component intended function is 

maintained during the period of extended operation. 
NUREG-1801, Rev. 2 XI M29-2 December 2010

5. Monitoring and Trending: The effects of corrosion of the aboveground external surface are 

detectable by visual techniques. Based on operating experience, plant inspections during 

each outage provide for timely detection of aging effects. The effects of corrosion of the 

inaccessible external surface are detectable by UT thickness measurement of the tank 

bottom and are monitored and trended if significant material loss is detected where multiple 

measurements are available.

6. Acceptance Criteria: Any degradation of paints or coatings (cracking, flaking, or peeling) is 

reported and requires further evaluation. Drying, cracking, or missing sealant and caulking 

are unacceptable and need to be evaluated using the corrective action program. The 

evaluation will determine the need to repair the sealant and caulking. UT 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 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions, 

confirmation process, and administrative controls. Flaws in the caulking or sealant are 

repaired. 

8. Confirmation Process: As discussed in the Appendix for GALL, 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: Coating degradation, such as flaking and peeling, has occurred in 

safety-related systems and structures (U.S. Nuclear Regulatory Commission [NRC] Generic 

Letter 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; IN 89-79, 

Supplement 1; IN 86-99; and 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, 2009. 

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.
December 2010 XI M29-3 NUREG-1801, Rev. 2

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.

December 2010 XI M30-1 NUREG-1801, Rev. 2

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 the mitigative actions 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. Guidelines of the 

American Society for Testing Materials (ASTM) Standards, such as ASTM D 0975-04, D 1796-

97, D 2276-00, D 2709-96, D 6217-98, and D 4057-95, also may be used. 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 that the component’s intended function is 

maintained during the period of extended operation. Thickness measurement of tank bottom 

surfaces is an acceptable verification program.

The fuel oil chemistry program is generally effective in removing impurities from intermediate 

and high flow areas. This report identifies those circumstances in which the fuel oil chemistry 

program is to be augmented to manage the effects of aging for license renewal. For example, 

the fuel oil chemistry program may not be effective in low flow or stagnant flow areas. 

Accordingly, in certain cases as identified in this report, verification of the effectiveness of the 

chemistry program is undertaken to ensure that significant degradation is not occurring and that 

the component’s intended function is maintained during the period of extended operation. As 

discussed in this report for these specific cases, an acceptable verification program is a onetime inspection of selected components at susceptible locations in the system.

Evaluation and Technical Basis

1. Scope of Program: Components within the scope of the program are the diesel fuel oil 

storage tanks, piping, and other metal components subject to aging management review 

that are exposed to an environment of diesel fuel oil. The program is focused on managing 

loss of material due to general, pitting, crevice, and microbiologically-influenced corrosion 

(MIC) and fouling that leads to corrosion of the diesel fuel tank internal surfaces. 

2. Preventive Actions: The program reduces the potential for (a) exposure of the storage 

tanks’ internal surface to fuel oil contaminated with water and microbiological organisms, 

reducing the potential for age-related degradation in other components exposed to diesel 

fuel oil; and (b) transport of corrosion products, sludge, or particulates to components 

serviced by the fuel oil storage tanks. Biocides or corrosion inhibitors may be added as a 

preventive measure or are added if periodic testing indicates biological activity or evidence 

of 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 program is focused on managing loss of material 

due to general, pitting, crevice, and MIC, and fouling that leads to corrosion of the diesel fuel 

tank internal surfaces. The aging management program monitors fuel oil quality through 
NUREG-1801, Rev. 2 XI M30-2 December 2010

receipt testing and periodic sampling of stored fuel oil. Parameters monitored include water 

and sediment content, total particulate concentration, and the levels of microbiological 

organisms in the fuel oil. Water and microbiological organisms in the fuel oil storage tank 

increase the potential for corrosion. Sediment and total particulate content may be indicative 

of water intrusion or corrosion.

4. Detection of Aging Effects: Loss of material due to corrosion of the diesel fuel oil tank or 

other components exposed to diesel fuel oil cannot occur without exposure of the tank’s

internal surfaces to contaminants in the fuel oil, such as water and microbiological 

organisms. Periodic multilevel sampling provides assurance that fuel oil contaminants are 

below unacceptable levels. If tank design features do not allow for multilevel sampling, a 

sampling methodology that includes a representative sample from the lowest point in the 

tank may be used.

At least once during the 10-year period prior to the period of extended operation, each diesel 

fuel tank is drained and cleaned, the internal surfaces are visually inspected (if physically 

possible) and volumetrically-inspected if evidence of degradation is observed during visual 

inspection, or if visual inspection is not possible. During the period of extended operation, at 

least once every 10 years, each diesel fuel tank is drained and cleaned, the internal surfaces 

are visually inspected (if physically possible), and, if evidence of degradation is observed 

during inspections, or if visual inspection is not possible, these diesel fuel tanks are 

volumetrically inspected.

Prior to the period of extended operation, a one-time inspection (i.e., AMP XI.M32) of 

selected components exposed to diesel fuel oil is performed to verify the effectiveness of the 

Fuel Oil Chemistry program. 

5. Monitoring and Trending: Water, biological activity, and particulate contamination 

concentrations are monitored and trended in accordance with the plant’s technical 

specifications or at least quarterly. 

6. Acceptance Criteria: Acceptance criteria for fuel oil quality parameters are as invoked or 

referenced in a plant’s technical specifications. Additional acceptance criteria may be 

implemented using guidance from industry standards and equipment manufacturer or fuel oil 

supplier recommendations. ASTM D 0975-04 or other appropriate standards may be used to 

develop fuel oil quality acceptance criteria. Suspended water concentrations are in 

accordance with the applicable fuel oil quality specifications. Corrective actions are taken if 

microbiological activity is detected.

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. If accumulated water is found in a fuel oil storage tank, 

it is immediately removed. In addition, when the presence of biological activity is confirmed, 

a biocide is added to fuel oil. As discussed in the Appendix for GALL, 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 for GALL, the staff finds the 
December 2010 XI M30-3 NUREG-1801, Rev. 2

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process and administrative controls.

9. Administrative Controls: The administrative controls for this program provide for a formal 

review and approval of corrective actions. The administrative controls for this program are 

implemented through the site's QA program in accordance with the requirements of 10 CFR 

Part 50, Appendix B.

10. Operating Experience: The operating experience at some plants has included identification 

of water in the fuel, particulate contamination, and biological fouling. In addition, when a 

diesel fuel oil storage tank at one plant was cleaned and visually inspected, the inside of the 

tank was found to have unacceptable pitting corrosion (>50% of the wall thickness), which 

was repaired in accordance with American Petroleum Institute (API) 653 standard by 

welding patch plates over the affected area.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009. 

API 653, Tank Inspection, Repair, Alteration, and Reconstruction, American Petroleum Institute, 

April 23, 2009.

ASTM D 0975-04, Standard Specification for Diesel Fuel Oils, American Society for Testing 

Materials, West Conshohocken, PA, 2004.

ASTM D 1796-97,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.

ASTM D 4057-95, Standard Practice for Manual Sampling of Petroleum and Petroleum 

Products, American Society for Testing Materials, West Conshohocken, PA, 2000.

ASTM D 6217-98, Standard Test Method for Particulate Contamination in Middle Distillate Fuels 

by Laboratory Filtration, American Society for Testing Materials, West Conshohocken, PA, 

1998.

NRC Regulatory Guide 1.137, Rev. 1, Fuel-Oil Systems for Standby Diesel Generators, U.S. 

Nuclear Regulatory Commission, October 1979.Safety Evaluation Report Related to the 

License Renewal of Three Mile Island Nuclear Unit 1, Section 3.0.3.2.12, Fuel Oil Chemistry 

– Operating Experience, June 2009.

December 2010 XI M31-1 NUREG-1801, Rev. 2

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 International Standard Practice E 185-82 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 (2009), Paragraph III.C. Additional 

surveillance capsules may also be needed for the period of extended operation for this 

alternative.

The objective of the reactor vessel material surveillance program is to provide sufficient material 

data and dosimetry to (a) monitor irradiation embrittlement at the end of the period of extended 

operation and (b) 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. 

The program is a condition monitoring program that measures the increase in Charpy V-notch 

30 foot-pound (ft-lb) transition temperature and the drop in the upper shelf energy as a function 

of neutron fluence and irradiation temperature. The data from this surveillance program are 

used to monitor neutron irradiation embrittlement and are used in the time-limited aging 

analyses that are described in Section 4.2 of the Standard Review Plan for License Renewal. All 

capsules in the reactor vessel that are removed and tested must meet the test procedures and 

reporting requirements of the 1982 edition of ASTM E 185 (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 possible future insertion. 

Evaluation and Technical Basis

The 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.

1. Scope of Program: The program includes all reactor vessel beltline materials as defined by 

10 CFR 50, Appendix G, Section II.F. Materials originally monitored within the scope of the 

licensee’s existing 10 CFR Part 50, Appendix H, materials surveillance program will continue 

to serve as the basis for the reactor vessel surveillance aging management program unless 

safety considerations for the term of the renewed license would require the monitoring of 

additional or alternative materials. 
NUREG-1801, Rev. 2 XI M31-2 December 2010

2. Preventive Actions: The program is a surveillance program; no preventive actions are 

identified.

3. Parameters Monitored/Inspected: The program monitors reduction of fracture toughness 

of reactor vessel beltline materials due to neutron irradiation embrittlement and monitors 

reactor vessel long term operating conditions (cold leg operating temperature and neutron 

fluence) that could affect neutron irradiation embrittlement of the reactor vessel. The 

program uses two parameters to monitor the effects of neutron irradiation: (a) the increase in 

the Charpy V-notch 30 ft-lb transition temperature and (b) the drop in the Charpy V-notch 

upper shelf energy. The program uses neutron dosimeters to benchmark neutron fluence 

calculations. Low melting point elements or eutectic alloys may be used as a check on peak 

specimen irradiation temperature. Preferably, irradiation temperature will be monitored from 

cold leg operating temperatures. The Charpy V-notch specimens, neutron dosimeters, and 

temperature monitors are placed in capsules that are located within the reactor vessel; the 

capsules are withdrawn periodically to monitor the reduction in fracture toughness due to 

neutron irradiation. 

4. Detection of Aging Effects: Reactor vessel beltline materials will be monitored by a 

surveillance program in which surveillance capsules are withdrawn from the reactor vessel 

and tested in accordance with ASTM E 185-82. This ASTM standard describes the methods 

used to monitor irradiation embrittlement (described in Element 3, above), selection of 

materials, and the withdrawal schedule for capsules. 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 III.C. Additional surveillance capsules may also be needed 

for the period of extended operation for this alternative.

The plant-specific or integrated surveillance program shall have at least one capsule with a 

projected neutron fluence equal to or exceeding the 60-year peak reactor vessel wall 

neutron fluence prior to the end of the period of extended operation. The program withdraws 

one capsule at an outage in which the capsule receives a neutron fluence of between one 

and two times the peak reactor vessel wall neutron fluence at the end of the period of 

extended operation and tests the capsule in accordance with the requirements of ASTM E 

185-82. 

It is recommended that the program retain additional capsules within the reactor vessel to 

support additional testing if, for example, the data from the required surveillance capsule 

turn out to be invalid or in preparation for operation beyond 60 years. If the projected 

neutron fluence for these additional capsules is expected to be excessive if left in the reactor 

vessel, the program may propose to withdraw and place one or more untested capsules in 

storage for future reinsertion and/or testing.

If a plant has ample capsules remaining for future use, all pulled and tested samples or 

capsules placed in storage with reactor vessel neutron fluence less than 50% of the 

projected neutron fluence at the end of the period of extended operation may be discarded. 

Pulled and tested samples, unless discarded before August 31, 2000, and capsules with a 

neutron fluence greater than 50% of the projected reactor vessel neutron fluence at the end 

of the period of extended operation are placed in storage (these specimens and capsules
December 2010 XI M31-3 NUREG-1801, Rev. 2

are saved for future reconstitution and reinsertion use) unless the applicant has gained NRC 

approval to discard the pulled and tested samples or capsules.

If an applicant does not have ample capsules remaining for future use, all pulled and tested 

capsules, unless discarded before August 31, 2000, are placed in storage. (These 

specimens are saved for future reconstitution use, in case the surveillance program is 

reestablished.)

Plant-specific and fleet operating experience should be considered in determining the 

withdrawal schedule for all capsules; the withdrawal schedule shall be submitted as part of a 

license renewal application for NRC review and approval in accordance with 10 CFR Part 

50, Appendix H.

If all surveillance capsules have been removed, a licensee may seek membership in an 

integrated surveillance program unless the integrated surveillance program does not have 

surveillance material representative of its limiting beltline materials or the program can 

propose one of the following:

(a) An Active Surveillance Program with Reinstituted Specimens 

This program consists of (1) capsules from a surveillance program described 

above, (2) reconstitution of specimen from tested capsules, (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.

(b) An Alternative Neutron Monitoring Program

Programs without in-vessel capsules use alternative dosimetry to monitor neutron

fluence during the period of extended operation. 

If all surveillance capsules have been removed, operating restrictions are 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 or more years is 

reviewed and, if deemed appropriate, modifications are made to the Reactor Vessel 

Surveillance program. Any changes to the Reactor Vessel Surveillance program must be 

submitted for NRC review and approval in accordance with 10 CFR Part 50, Appendix H.

5. Monitoring and Trending: The program provides reactor vessel material fracture 

toughness data for the time limited aging analyses (TLAAs) on neutron irradiation 

embrittlement (e.g., upper-shelf energy, pressurized thermal shock and pressuretemperature limits evaluations, etc.) for 60 years. The program is designed to periodically 

remove and test capsules for monitoring and trending purposes. Refer to the Standard 

Review Plan for License Renewal, Section 4.2, for the NRC acceptance criteria and review 

procedures for reviewing TLAAs for neutron irradiation embrittlement. 

The TLAAs are projected in accordance with NRC Regulatory Guide (RG) 1.99, Rev. 2, 

“Radiation Embrittlement of Reactor Vessel Materials,” and the pressurized thermal shock 
NUREG-1801, Rev. 2 XI M31-4 December 2010

rules (10 CFR 50.61 or 10 CFR 50.61a). When using NRC RG 1.99, Rev. 2, or equivalent 

provisions in 10 CFR 50.61, a licensee has a choice of the following:

(a) Neutron Embrittlement Using Chemistry Tables and Upper Shelf Energy Figures

An applicant may use the tables and figures 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 NRC RG 1.99, Rev. 2.

(b) Neutron Embrittlement Using Surveillance Data

When two or more credible surveillance data sets are 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 and extended operating term. A plant-specific program or an integrated 

surveillance program during the period of extended operation provides for the 

collection of additional data.

A program that determines embrittlement by using NRC RG 1.99, Rev. 2, tables and figures 

(item [a]) uses the applicable limitations in Regulatory Position 1.3 of NRC RG 1.99, Rev. 2. 

The limits are based on material properties, temperature, material chemistry, and neutron 

fluence.

The program that determines embrittlement by using surveillance data (item [b]) 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 plantspecific data could be collected within a smaller temperature range than that in NRC RG 

1.99, Rev. 2.

The reactor vessel monitoring program provides that if future plant operations exceed these 

limitations or bounds, 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 is 

evaluated and the NRC is notified. 

6. Acceptance Criteria: The data are used for reactor vessel embrittlement projections to 

comply with 10 CFR Part 50, Appendix G, requirements and 10 CFR 50.61 or 10 CFR 

50.61a limits through the period of extended operation. 

7. Corrective Actions: There are no acceptance criteria that apply to the surveillance data, 

but the results of surveillance capsule testing will be incorporated into site operating 

limitations. The data will be used for reactor vessel embrittlement projections to comply with 

10 CFR Part 50, Appendix G, requirements and 10 CFR 50.61 or 10 CFR 50.61a limits 

through the period of extended operation. 

If a capsule is not withdrawn as scheduled, the NRC is notified and a revised withdrawal 

schedule is submitted to the NRC.

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 
December 2010 XI M31-5 NUREG-1801, Rev. 2

B. As discussed in the Appendix for GALL, 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process, and administrative controls.

9. Administrative Controls: The administrative controls for this program provide for a formal 

review and approval of corrective actions. The administrative controls for this program are 

implemented through the site's QA program in accordance with the requirements of 10 CFR 

Part 50, Appendix B.

10. Operating Experience: The existing reactor vessel material surveillance program provides 

sufficient material data and dosimetry to (a) monitor irradiation embrittlement at the end of 

the period of extended operation and (b) determine the need for operating restrictions on the 

inlet temperature, neutron fluence, and neutron flux.

References

10 CFR Part 50, Appendix G, Fracture Toughness Requirements, Office of the Federal 

Register, National Archives and Records Administration, 2009.

10 CFR Part 50, Appendix H, Reactor Vessel Material Surveillance Program Requirements, 

Office of the Federal Register, National Archives and Records Administration, 2009.

10 CFR 50.61, Fracture Toughness Requirements for Protection Against Pressurized Thermal 

Shock Events, Office of the Federal Register, National Archives and Records Administration, 

January 4, 2010.

10 CFR 50.61a, Alternate Fracture Toughness Requirements for Protection Against Pressurized 

Thermal Shock Events, Office of the Federal Register, National Archives and Records 

Administration, January 4, 2010.

ASTM E 185-82, Standard Practice for Conducting Surveillance Tests of Light-Water Cooled 

Nuclear Power Reactor Vessels, American Society for Testing Materials, Philadelphia, PA. 

(Versions of ASTM E 185 to be used for the various aspects of the reactor vessel 

surveillance program are as specified in 10 CFR Part 50, Appendix H.)

NRC Regulatory Guide 1.99, Rev. 2, Radiation Embrittlement of Reactor Vessel Materials, U.S. 

Nuclear Regulatory Commission, May 1988.

December 2010 XI M32-1 NUREG-1801, Rev. 2

XI.M32 ONE-TIME INSPECTION 

Program Description

A one-time inspection of selected components is used to verify the system-wide effectiveness of 

an aging management program (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 under the XI.M2, “Water Chemistry,” program 

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 verify that unacceptable degradation is not occurring. It also may 

trigger additional actions that ensure the intended functions of affected components are 

maintained during the period of extended operation. 

The program verifies the effectiveness of an AMP and confirms 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 are insufficient to rule it out with reasonable confidence; or (b) 

an aging effect is expected to progress very slowly in the specified environment, but the local 

environment may be more adverse than generally expected. For these cases, confirmation 

demonstrates that either the aging effect is not occurring or that the aging effect is occurring 

very slowly and does not affect the component’s or structure’s intended function during the 

period of extended operation based on prior operating experience data. 

This program does not address Class 1 piping less than nominal pipe size (NPS) 4. That piping 

is addressed in AMP XI.M35, “One Time Inspection of ASME Code Class 1 Small Bore-Piping.” 

The elements of the program include (a) determination of the sample size of components to be 

inspected 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 potential for the aging effect to occur; (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 age-related degradation is found that could 

jeopardize an intended function before the end of the period of extended operation. 

An acceptable (one-time inspection) program to verify system-wide effectiveness of an AMP 

may consist of a one-time inspection of selected components and susceptible locations in the 

selected system. Verification may include a review of routine maintenance, repair, or inspection 

records to confirm that selected components have been inspected for aging degradation and 

that significant aging degradation has not occurred. A one-time inspection program is 

acceptable to verify the effectiveness of AMP XI.M2, “Water Chemistry”; AMP XI.M30, “Fuel Oil 

Chemistry”; and AMP XI.M39, “Lubricating Oil Analysis,” programs or where the environment in 

the period of extended operation is expected to be equivalent to that in the prior 40 years and 

for which no aging effects have been observed. However, one-time inspection for environments 

that do not fall in the above category, or of 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. 2 XI M32-2 December 2010

This program cannot be used for structures or components with known age-related degradation 

mechanisms or when the environment in the period of extended operation is not expected to be 

equivalent to that in the prior 40 years. Periodic inspections should be proposed in these cases.

Evaluation and Technical Basis

1. Scope of Program: The scope of this program includes systems and components that are 

subject to aging management using the GALL AMPs XI.M2, “Water Chemistry”; XI.M30, 

“Fuel Oil Chemistry”; and XI.M39, “Lubricating Oil Analysis,” and for which no aging effects 

have been observed or for which the aging effect is occurring very slowly and does not 

affect the component’s or structure’s intended function during the period of extended 

operation based on prior operating experience data. The scope of this program also may 

include other components and materials where the environment in the period of extended 

operation is expected to be equivalent to that in the prior 40 years and for which no aging 

effects have been observed. 

The program cannot be used for structures or components subjected to known age-related 

degradation mechanisms or when the environment in the period of extended operation is not 

expected to be equivalent to that in the prior 40 years. Periodic inspections should be 

proposed in these cases.

2. Preventive Actions: One-time inspection is a condition monitoring program. It does not 

include methods to mitigate or prevent age-related degradation.

3. Parameters Monitored/Inspected: The program monitors parameters directly related to the 

age-related degradation of a component. Examples of parameters monitored and the related 

aging effect are provided in the table in Element 4, below. Inspection is performed using a 

variety of nondestructive examination (NDE) methods, including visual, volumetric, and 

surface techniques. 

4. Detection of Aging Effects: Elements of the program include (a) determination of the 

sample size of components to be inspected 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 potential for the aging 

effect to occur; and (c) determination of the examination technique, including acceptance 

criteria that would be effective in managing the aging effect for which the component is 

examined. Where practical, the inspection includes a representative sample of the system 

population and focuses on the bounding or lead components most susceptible to aging due 

to time in service, and severity of operating conditions. For components managed by the 

AMP XI.M2, Water Chemistry”; AMP XI.M30, “Fuel Oil Chemistry”; and AMP XI.M39, 

“Lubricating Oil Analysis,” programs, a representative sample size is 20% of the population 

(defined as components having the same material, environment, and aging effect 

combination) or a maximum of 25 components. Otherwise, a technical justification of the 

methodology and sample size used for selecting components for one-time inspection should 

be included as part of the program’s documentation.

The program relies on established NDE techniques, including visual, ultrasonic, and surface 

techniques. Inspections are performed by personnel qualified in accordance with site 

procedures and programs to perform the type of examination specified. For code 

components, examinations should follow procedures consistent with the American Society 
December 2010 XI M32-3 NUREG-1801, Rev. 2

of Mechanical Engineers (ASME) Code16

The inspection and test techniques shall have a demonstrated history of effectiveness in 

detecting the aging effect of concern. Typically, the one-time inspections shall be performed 

as indicated in the following table. 

and 10 CFR Part 50, Appendix B. For non-code 

components, examinations should follow site procedures that include requirements for items 

such as lighting, presence of protective coatings, and cleaning processes that ensure an 

adequate examination. In addition, a description of Enhanced Visual Examination (EVT-1) is 

found in Boiling Water Reactor Vessel and Internals Project (BWRVIP)-03 and Materials 

Reliability Program (MRP)-228.

Examples of Parameters Monitored or Inspected 

and Aging Effect for Specific Structure or Component17

Aging Effect Aging 

Mechanism

Parameter(s) 

Monitored Inspection Method18

Loss of Material Crevice 

Corrosion

Surface Condition, 

Wall Thickness

Visual (VT-1 or equivalent) and/or 

Volumetric (ultrasonic testing [UT])

Loss of Material Galvanic 

Corrosion

Surface Condition, 

Wall Thickness

Visual (VT-3 or equivalent) and/or 

Volumetric (UT)

Loss of Material General 

Corrosion

Surface Condition, 

Wall Thickness

Visual (VT-3 or equivalent) and/or 

Volumetric (UT)

Loss of Material MIC Surface Condition, 

Wall Thickness

Visual (VT-3 or equivalent) and/or 

Volumetric (UT)

Loss of Material Pitting 

Corrosion

Surface Condition, 

Wall Thickness

Visual (VT-1 or equivalent) and/or 

Volumetric (UT)

Loss of Material Erosion Surface Condition, 

Wall Thickness

Visual (VT-3 or equivalent) and/or 

Volumetric (UT)

Reduction of 

Heat Transfer

Fouling Tube Fouling Visual (VT-3 or equivalent)

Cracking SCC or 

Cyclic 

Loading

Surface Condition, 

Cracks

Enhanced Visual (EVT-1 or equivalent) 

or Surface Examination (magnetic 

particle, liquid penetrant) or Volumetric 

(radiographic testing or UT)

With respect to inspection timing, the sample 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 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 

 

16 Refer to the GALL Report, Chapter I, for application of other editions of the ASME Code, Section XI. 17 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. 18 Visual inspection may be used only when the inspection methodology examines the surface potentially 

experiencing the aging effect.
NUREG-1801, Rev. 2 XI M32-4 December 2010

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 operated for at least 

30 years before inspections under this program begin, sufficient time will have elapsed for 

any aging effects to be manifested. 

5. Monitoring and Trending: This is a one-time inspection program. Monitoring and trending 

are not applicable. 

6. Acceptance Criteria: Any indication or relevant conditions of degradation detected are 

evaluated. Acceptance criteria may be based on applicable ASME or other appropriate 

standards, design basis information, or vendor-specified requirements and 

recommendations. For example, ultrasonic thickness measurements are compared to 

predetermined limits. 

7. Corrective Actions: Unacceptable inspection findings are evaluated in accordance with the 

site’s corrective action process to determine appropriate corrective actions and the need for 

subsequent (including periodic) inspections under another AMP. 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 for GALL, 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: Confirmation processes to ensure that preventive actions are 

adequate and that appropriate corrective actions have been completed and are effective are 

implemented through the site QA program in accordance with the requirements of 10 CFR 

Part 50, Appendix B. 

9. Administrative Controls: Administrative controls to provide a formal review and approval 

for corrective actions are implemented through the site QA program in accordance with the 

requirements of 10 CFR Part 50, Appendix B.

10. Operating Experience: The elements that comprise inspections associated with this 

program (the scope of the inspections and inspection techniques) are consistent with 

industry practice. An applicant’s operating experience with detection of aging effects should 

be adequate to demonstrate that the program is capable of detecting the presence or noting 

the absence of aging effects in the components, materials, and environments where onetime inspection is used to confirm system-wide effectiveness of another preventive or 

mitigative AMP.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2009.
December 2010 XI M32-5 NUREG-1801, Rev. 2

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, The 

ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 50.55a, The 

American Society of Mechanical Engineers, New York, NY.

BWRVIP-03 (EPRI 105696- R6), BWR Vessel and Internals Project: Reactor Pressure Vessel 

and Internals Examination Guidelines, January 6, 2004, Final Safety Evaluation Report by 

the Office of Nuclear Reactor Regulation, June 2008.

MRP-228, Materials Reliability Program: Inspection Standard for PWR Internals, 2009.

December 2010 XI M33-1 NUREG-1801, Rev. 2

XI.M33 SELECTIVE LEACHING

Program Description

This program demonstrates the absence of selective leaching. The program for selective 

leaching of materials ensures the integrity of the components made of gray cast iron and copper 

alloys (except for inhibited brass) that contain greater than 15 percent zinc (> 15% Zn) or 

greater than 8 percent aluminum (>8% Al in the case of aluminum-bronze) exposed to a raw 

water, closed cooling water, treated water, or ground water environment that may lead to 

selective leaching of one of the metal components where there has not been previous 

experience of selective leaching. The AMP includes a one-time visual inspection of selected 

components that may be susceptible to selective leaching, coupled with either hardness 

measurements (where feasible, based on form and configuration) or mechanical examination 

techniques. These techniques can determine whether loss of materials due to selective leaching 

is occurring and whether selective leaching will affect the ability of the components to perform 

their intended function 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 a corrosive environment, such as acidic solutions for brasses with high zinc 

content and dissolved oxygen, are conducive to selective leaching.

Although the program does not provide guidance on preventive action, it is noted that 

monitoring of water chemistry to control pH and concentration of corrosive contaminants and 

treatment to minimize dissolved oxygen in water are effective in reducing selective leaching. 

Water chemistry is managed by the Water Chemistry program (AMP XI.M2).

Evaluation and Technical Basis

1. Scope of Program: This program demonstrates the absence of selective leaching. For 

materials and environments where selective leaching is currently occurring or for materials 

in environments where the component has been repaired with the same material, a plantspecific program is required. Components include piping, valve bodies and bonnets, pump 

casings, and heat exchanger components that are susceptible to selective leaching. The 

materials of construction for these components may include gray cast iron and uninhibited 

brass containing greater than 15% zinc. These components may be exposed to raw water, 

treated water, closed cooling water, ground water, water contaminated fuel oil, or watercontaminated lube oil.

2. Preventive Actions: This program is a condition monitoring program and it contains no 

preventive actions.

3. Parameters Monitored/Inspected: This program monitors selective leaching through the 

monitoring of surface hardness and visual appearance (color, porosity, abnormal surface 

conditions).

4. Detection of Aging Effects: The visual inspection and hardness measurement or other 

mechanical examination techniques, such as destructive testing (when the opportunity 

arises), chipping, or scraping, is a one-time inspection conducted within the last 5 years 
NUREG-1801, Rev. 2 XI M33-2 December 2010

prior to entering the period of extended operation. Because selective leaching is a slow 

acting corrosion process, this measurement is performed just prior to the period of extended 

operation. Follow-up of unacceptable inspection findings includes an evaluation using the 

corrective action program and a possible expansion of the inspection sample size and 

location.

Where practical, the inspection includes a representative sample of the system population 

and focuses on the bounding or lead components most susceptible to aging due to time in 

service, severity of operating conditions, and lowest design margin. Twenty percent of the 

population with a maximum sample of 25 constitutes a representative sample size. 

Otherwise, a technical justification of the methodology and sample size used for selecting 

components for one-time inspection should be included as part of the program’s 

documentation. Each group of components with different material/environment combinations 

is considered a separate population. 

Selective leaching generally does not cause changes in dimensions and is difficult to detect 

by visual inspection. However, in certain brasses, it causes plug-type dezincification, which 

can be detected by visual inspection. One acceptable procedure is to visually inspect the 

susceptible components closely and conduct Brinell hardness testing (where feasible, based 

on form and configuration or other industry-accepted mechanical inspection techniques) on 

the inside surfaces of the selected set of components to determine if selective leaching has 

occurred. If selective leaching is apparent, an engineering evaluation is initiated to 

determine acceptability of the affected components for further service.

5. Monitoring and Trending: This is a one-time inspection to determine if selective leaching is 

an issue. Monitoring and trending is not required. 

6. Acceptance Criteria: The acceptance criteria are no visible evidence of selective leaching 

or no more than a 20 percent decrease in hardness. For copper alloys with greater than 15 

percent zinc, the criteria is no noticeable change in color from the normal yellow color to the 

reddish copper color.

7. Corrective Actions: Engineering 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 for GALL, the staff finds 

the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective 

actions. Unacceptable inspection findings result in additional inspection(s) being performed, 

which may be on a periodic basis, or in component repair or replacement.

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 for GALL, the 

staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: The administrative controls for this program provide for a formal 

review and approval of corrective actions. The administrative controls for this program are 

implemented through the site's QA program in accordance with the requirements of 10 CFR 

Part 50, Appendix B.
December 2010 XI M33-3 NUREG-1801, Rev. 2

10. Operating Experience: The elements that comprise these inspections (e.g., the scope of 

the inspections and inspection techniques) are consistent with industry practice and staff 

expectations. Selective leaching has been detected in components constructed from cast 

iron, brass, bronze, and aluminum bronze. Components affected have included valve 

bodies, pump casings, piping, and cast iron fire protection piping buried in soil.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009. 

EPRI TR-107514, Age Related Degradation Inspection Method and Demonstration, Electric 

Power Research Institute, April 1998.

Fontana, M. G., Corrosion Engineering, McGraw Hill, p 86-90, 1986.

NUREG-1705, Safety Evaluation Report Related to the License Renewal of Calvert Cliffs 

Nuclear Power Plant, Units 1 and 2, U.S. Nuclear Regulatory Commission, December 1999.

NUREG-1723, Safety Evaluation Report Related to the License Renewal of Oconee Nuclear 

Station, Units 1, 2, and 3, U.S. Nuclear Regulatory Commission, March 2000.

NUREG-1930, Safety Evaluation Report Related to the License Renewal of Indian Point 

Nuclear Generating Units 2 and 3, U.S. Nuclear Regulatory Commission, November 2009.

Schweitzer, P. A., Encyclopedia of Corrosion Technology 2nd Ed, Marcel Dekker, p 201-202. 

March 17, 2004.

December 2010 XI M35-1 NUREG-1801, Rev. 2

XI.M35 ONE-TIME INSPECTION OF ASME CODE CLASS 1 SMALL-BORE PIPING

Program Description

This program augments the requirements in American Society of Mechanical Engineers (ASME) 

Code, Section XI, 2004 edition19

According to Table IWB-2500-1, Examination Category B-J, Item No. B9.21 and B9.40 of the 

current ASME Code, an external surface examination of small-bore Class 1 piping should be 

included for piping less than NPS 4. Other ASME Code provisions exempt from examination 

piping NPS 1 and smaller. This program is augmented to include piping from NPS 1 to less than 

NPS 4. Also, Examination Category B-P requires system leakage of all Class 1 piping. 

However, the staff believes that for a one-time inspection to detect cracking resulting from 

thermal and mechanical loading or intergranular stress corrosion of full-penetration welds, the 

inspection should be a volumetric examination. For a one-time inspection to detect cracking in 

socket welds, the inspection should be either a volumetric or opportunistic destructive 

examination. (Opportunistic destructive examination is performed when a weld is removed from 

service for other considerations, such as plant modifications. A sampling basis is used if more 

than 1 weld is removed.) These examinations provide additional assurance that either aging of 

small-bore ASME Code Class 1 piping is not occurring or the aging is insignificant, such that a 

plant-specific aging management program (AMP) is not warranted.

, and is applicable to small-bore ASME Code Class 1 piping 

and systems less than 4 inches nominal pipe size (less than NPS 4) and greater than or equal 

to NPS 1. The program includes pipes, fittings, branch connections, and all full and partial 

penetration (socket) welds. 

This program is applicable to systems that have not experienced cracking of ASME Code 

Class 1 small-bore piping. This program can also be used for systems that experienced 

cracking but have implemented design changes to effectively mitigate cracking. (Measure of 

effectiveness includes (1) the one-time inspection sampling is statistically significant;(2) samples 

will be selected as described in Element 5, Monitoring and Trending below; and (3) no repeated 

failures over an extended period of time.) For systems that have experienced cracking and 

operating experience indicates that design changes have not been implemented to effectively 

mitigate cracking, periodic inspection is proposed, as managed by a plant-specific AMP. Should 

evidence of cracking be revealed by a one-time inspection, periodic inspection is implemented 

using a plant-specific AMP.

If small bore piping in a particular plant system has experienced cracking, small bore piping in 

all plant systems are evaluated to determine whether the cause for the cracking affects other 

systems (corrective action program).

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 NPS 4 and greater than or equal to NPS 1. This program includes 

measures to verify that degradation is not occurring, thereby either confirming that there is 

no need to manage age-related degradation or validating the effectiveness of any existing 

AMP for the period of extended operation. The one-time inspection program for ASME Code 

Class 1 small-bore piping includes locations that are susceptible to cracking. 

 

19 Refer to the GALL Report, Chapter I, for applicability of other editions of the ASME Code, Section XI. 
NUREG-1801, Rev. 2 XI M35-2 December 2010

2. Preventive Actions: This program is a condition monitoring 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: This one-time inspection is designed to provide assurance that 

aging of ASME Code Class 1 small-bore piping is not occurring, or that the effects of aging 

are not significant. This inspection does not apply to those plants that have experienced 

cracking due to stress corrosion, cyclical (including thermal, mechanical, and vibration 

fatigue) loading, or thermal stratification and thermal turbulence (MRP 146 and MRP 146S). 

For a one-time inspection to detect cracking in socket welds, the inspection should be either 

a volumetric or opportunistic destructive examination. (Opportunistic destructive examination 

is performed when a weld is removed from service for other considerations, such as plant 

modifications. A sampling basis is used if more than one weld is removed.) For a one-time 

inspection to detect cracking resulting from thermal and mechanical loading or intergranular 

stress corrosion of full penetration welds, the inspection should be a volumetric examination. 

Volumetric examination is performed using demonstrated techniques that are capable of 

detecting the aging effects in the examination volume of interest. This inspection should be 

performed at a sufficient number of locations to ensure an adequate sample. This number, 

or sample size, is based on susceptibility, inspectability, dose considerations, operating 

experience, and limiting locations of the total population of ASME Code Class 1 small-bore 

piping locations.

If an applicant has never experienced a failure in its ASME Code Class 1 piping (a throughwall crack detected in the subject component by evidence of leakage, or through 

nondestructive or destructive examination) and has extensive operating history (more than 

30 years of operation at time of submitting the application), the inspection sample size 

should be at least 3% of the weld population or a maximum of 10 welds of each weld type 

for each operating unit. If the applicant has successfully mitigated any failures in its ASME 

Class 1 piping, the inspection should include 10% of the weld population or a maximum of 

25 welds of each weld type (e.g., full penetration or socket weld) for each operating unit 

using a methodology to select the most susceptible and risk-significant welds. For socket 

welds, opportunistic destructive examination can be performed in lieu of volumetric 

examination. Because more information can be obtained from a destructive examination 

than from nondestructive examination, the applicant may take credit for each weld 

destructively examined equivalent to having volumetrically examined two welds.

The one time inspection should be completed within the six year period prior to the period of 

extended operation.

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, cyclical (including 

thermal, mechanical, and vibration fatigue) loading, or thermal stratification and thermal 

turbulence (MRP 146 and MRP 146S) is an issue. Evaluation of the inspection results may 

indicate the need for additional or periodic examinations (i.e., a plant-specific AMP for Class 

1 small-bore piping using volumetric inspection methods consistent with ASME Code, 

Section XI, Subsection IWB). 

6. Acceptance Criteria: If flaws or indications exceed the acceptance criteria of ASME Code, 

Section XI, Paragraph IWB-3400, they are evaluated in accordance with ASME Code, 
December 2010 XI M35-3 NUREG-1801, Rev. 2

Section XI, Paragraph IWB-3131; additional examinations are performed in accordance with 

ASME Code, Section XI, Paragraph IWB-2430. Evaluation of flaws identified during a 

volumetric examination of socket welds should be in accordance with IWB-3600.

7. Corrective Actions: The site corrective action program, quality assurance 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 for 

GALL, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to 

address the corrective actions, confirmation process, and administrative controls. Should 

evidence of cracking be revealed by a one-time inspection, periodic inspection is 

implemented, as managed by a plant-specific AMP.

8. Confirmation Process: As discussed in the Appendix for GALL, 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

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. 

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2009.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, The 

ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 50.55a, The 

American Society of Mechanical Engineers, New York, NY.

EPRI 1011955, Materials Reliability Program: Management of Thermal Fatigue in Normally 

Stagnant Non-Isolable Reactor Coolant System Branch Lines (MRP-146), June 8, 2005.

EPRI 1018330, Materials Reliability Program: Management of Thermal Fatigue in Normally 

Stagnant Non-Isolable Reactor Coolant System Branch Lines – Supplemental Guidance 

(MRP-146S), December 31, 2008.

NRC Information Notice 97-46, Unisolable Crack in High-Pressure Injection Piping, U.S. Nuclear 

Regulatory Commission, July 9, 1997.

December 2010 XI M36-1 NUREG-1801, Rev. 2

XI.M36 EXTERNAL SURFACES MONITORING OF MECHANICAL COMPONENTS

Program Description

The External Surfaces Monitoring of Mechanical Components program is based on system 

inspections and walkdowns. This program consists of periodic visual inspections of metallic and 

polymeric components, such as piping, piping components, ducting, polymeric components, and 

other components within the scope of license renewal and subject to aging management review 

(AMR) in order to manage aging effects. The program manages aging effects through visual 

inspection of external surfaces for evidence of loss of material, cracking, and change in material 

properties. When appropriate for the component and material, manipulation may be used to 

augment visual inspection to confirm the absence of elastomer hardening and loss of strength. 

Loss of material due to boric acid corrosion is managed by the Boric Acid Corrosion program 

(AMP XI.M10). 

Evaluation and Technical Basis

1. Scope of Program: This program visually inspects the external surface of in-scope 

mechanical components and monitors external surfaces of metallic components in systems 

within the scope of license renewal and subject to AMR for loss of material and leakage. 

Cracking of stainless steel components exposed to an air environment containing halides 

may also be managed. This program also visually inspects and monitors the external 

surfaces of polymeric components in mechanical systems within the scope of license 

renewal and subject to AMR for changes in material properties (such as hardening and loss 

of strength), cracking, and loss of material due to wear. This program manages the effects of 

aging of polymer materials in all environments to which these materials are exposed.

The program may also be credited with managing loss of material from internal surfaces of 

metallic components and with loss of material, cracking, and change in material properties 

from the internal surfaces of polymers, 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 of Mechanical Components program 

is a condition monitoring program that does not include preventive actions.

3. Parameters Monitored/Inspected: The External Surfaces Monitoring of Mechanical 

Components 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, polymeric components, and other components. For metallic 

components, coatings deterioration is an indicator of possible underlying degradation. The 

aging effects for flexible polymeric components may be monitored through a combination of 

visual inspection and manual or physical manipulation of the material. “Manual or physical 

manipulation of the material” means touching, pressing on, flexing, bending, or otherwise 

manually interacting with the material. The purpose of the manual manipulation is to reveal 

changes in material properties, such as hardness, and to make the visual examination 

process more effective in identifying aging effects such as cracking. 

Examples of inspection parameters for metallic components include:
NUREG-1801, Rev. 2 XI M36-2 December 2010

 corrosion and material wastage (loss of material) 

 leakage from or onto external surfaces (loss of material)

 worn, flaking, or oxide-coated surfaces (loss of material)

 corrosion stains on thermal insulation (loss of material)

 protective coating degradation (cracking, flaking, and blistering)

 leakage for detection of cracks on the external surfaces of stainless steel 

components exposed to an air environment containing halides

Examples of inspection parameters for polymers include:

 surface cracking, crazing, scuffing, and dimensional change (e.g., “ballooning” and 

“necking”) 

 discoloration

 exposure of internal reinforcement for reinforced elastomers

 hardening as evidenced by a loss of suppleness during manipulation where the 

component and material are appropriate to manipulation 

4. Detection of Aging Effects: This program manages aging effects of loss of material, 

cracking, and change in material properties using visual inspection. For coated surfaces, 

confirmation of the integrity of the paint or coating is an effective method for managing the 

effects of corrosion on the metallic surface. 

When required by the ASME Code, inspections are conducted in accordance with the 

applicable code requirements. In the absence of applicable code requirements, plantspecific visual inspections are performed of metallic and polymeric component surfaces 

using plant-specific procedures implemented by inspectors qualified through plant-specific 

programs. The inspections are capable of detecting age-related degradation and are 

performed at a frequency not to exceed one refueling cycle. This frequency accommodates 

inspections of components that may be in locations that are normally only accessible during 

outages or access is physically restricted (underground). Surfaces that are not readily visible 

during plant operations and refueling outages are inspected when they are made accessible 

and at such intervals that would ensure the components’ intended functions are maintained. 

The inspections of underground components shall be conducted during each 10-year period 

beginning 10 years prior to entering the period of extended operation. These normally 

underground components should be clearly identified in the program scope and inspection 

intervals provided. Surfaces that are insulated may be inspected when the external surface 

is exposed (i.e., during maintenance) at such intervals that would ensure that the 

components’ intended functions are maintained. The intervals of inspections may be 

adjusted, as necessary, based on plant-specific inspection results and industry operating 

experience.

Visual inspection will identify indirect indicators of flexible polymer hardening and loss of 

strength and include the presence of surface cracking, crazing, discoloration, and, for 
December 2010 XI M36-3 NUREG-1801, Rev. 2

elastomers with internal reinforcement, the exposure of reinforcing fibers, mesh, or 

underlying metal. Visual inspection should be 100% of accessible components. Visual 

inspection will identify direct indicators of loss of material due to wear to include dimensional 

change, scuffing, and for flexible polymeric materials with internal reinforcement, the 

exposure of reinforcing fibers, mesh, or underlying metal. Manual or physical manipulation 

can be used to augment visual inspection to confirm the absence of hardening and loss of 

strength for flexible polymeric materials (e.g., HVAC flexible connectors) where appropriate. 

The sample size for manipulation should be at least 10 percent of available surface area. 

Hardening and loss of strength and loss of material due to wear for flexible polymeric 

materials are expected to be detectable prior to any loss of intended function.

This program is credited with managing the following aging effects.

 loss of material and cracking for external surfaces

 loss of material for internal surfaces exposed to the same environment as the 

external surface 

 cracking and change in material properties (hardening and loss of strength) of 

flexible polymers

5. Monitoring and Trending: Visual inspection and manual or physical manipulation activities 

are performed and associated personnel are qualified in accordance with site controlled 

procedures and processes. The External Surfaces Monitoring of Mechanical Components 

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 Element 4, 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. For metallic surfaces, any indications of relevant degradation detected 

are evaluated. For stainless steel surfaces, a clean, shiny surface is expected. The 

appearance of discoloration may indicate the loss of material on the stainless steel surface. 

For aluminum and copper alloys exposed to marine or industrial environments, any 

indications of relevant degradation that could impact their intended function are evaluated. 

For flexible polymers, a uniform surface texture and uniform color with no unanticipated 

dimensional change is expected. Any abnormal surface condition may be an indication of an 

aging effect for metals and for polymers. For flexible materials, changes in physical 

properties (e.g., the hardness, flexibility, physical dimensions, and color of the material are 

unchanged from when the material was new) should be evaluated for continued service in 

the corrective action program. Cracks should be absent within the material. For rigid 

polymers, surface changes affecting performance, such as erosion, cracking, crazing, 

checking, and chalking, are subject to further investigation. Acceptance criteria include 

design standards, procedural requirements, current licensing basis, industry codes or 

standards, and engineering evaluation.

7. Corrective Actions: Site quality assurance 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 for GALL, the staff finds the 
NUREG-1801, Rev. 2 XI M36-4 December 2010

requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions, 

confirmation process, and administrative controls.

8. Confirmation Process: As discussed in the Appendix for GALL, 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls. 

10. Operating Experience: External surface inspections through system inspections and 

walkdowns have been in effect at many utilities since the mid 1990s 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, 2009.

EPRI Technical Report 1007933, Aging Assessment Field Guide, December 2003.

EPRI Technical Report 1009743, Aging Identification and Assessment Checklist, August 27, 

2004.

INPO Good Practice TS-413, Use of System Engineers, INPO 85-033, May 18, 1988.
December 2010 XI M37-1 NUREG-1801, Rev. 2

XI.M37 FLUX THIMBLE TUBE INSPECTION 

Program Description

The Flux Thimble Tube Inspection is a condition monitoring program used to inspect 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 reactor coolant system (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. A nondestructive examination methodology, such as 

eddy current testing (ECT) or other applicant-justified and U.S. Nuclear Regulatory Commission 

(NRC)-accepted inspection method, is used to monitor for wear of the flux thimble tubes. This 

program implements the recommendations of NRC IE Bulletin 88-09, 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 RCS pressure boundary. The instrument guide tubes are not in 

the scope of this program. Within scope are the licensee responses to IE 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 is 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 is used 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 NRC.

Examination frequency is based upon actual plant-specific wear data and wear predictions 

that have been technically justified as providing conservative estimates of flux thimble tube 

wear. The interval between inspections is 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. Rebaselining of the examination frequency should be justified using plantspecific wear-rate data unless prior plant-specific NRC acceptance for the re-baselining is 

received outside the license renewal process. If design changes are made to use more 

wear-resistant thimble tube materials (e.g., chrome-plated stainless steel), sufficient 

inspections are conducted at an adequate inspection frequency, as described above, for the 

new materials.

5. Monitoring and Trending: Flux thimble tube wall thickness measurements are trended and 

wear rates are calculated based on plant-specific data. Wall thickness is projected using 

plant-specific data and a methodology that includes sufficient conservatism to ensure that 

wall thickness acceptance criteria continue to be met during plant operation between 

scheduled inspections. 
NUREG-1801, Rev. 2 XI M37-2 December 2010

6. Acceptance Criteria: Appropriate acceptance criteria, such as percent through-wall wear, 

are established, and inspection results are evaluated and compared with the acceptance 

criteria. The acceptance criteria are technically justified to provide an adequate margin of 

safety to ensure that the integrity of the reactor coolant system pressure boundary is 

maintained. The acceptance criteria 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 the applicant’s response to IE Bulletin 

88-09 and amendments thereto, as accepted by the NRC, should be justified.

7. Corrective Actions: Flux thimble tubes with wall thickness that do not meet the established 

acceptance criteria are 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 are subject to wear 

due to restriction or other defects, and that cannot be shown by analysis to be satisfactory 

for continued service are removed from service to ensure the integrity of the reactor coolant 

system pressure boundary.

The site corrective actions program, quality assurance 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 for GALL, 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: As discussed in the Appendix for GALL, 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B acceptable to address the administrative 

controls.

10. Operating Experience: In IE Bulletin 88-09 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, 2009.
December 2010 XI M37-3 NUREG-1801, Rev. 2

NRC IE Bulletin 88-09, Thimble Tube Thinning in Westinghouse Reactors, July 26, 1988.

NRC Information Notice No. 87-44, Thimble Tube Thinning in Westinghouse Reactors, 

September 16, 1987.

NRC Information Notice No. 87-44, Supplement 1, Thimble Tube Thinning in Westinghouse 

Reactors, March 28, 1988.

December 2010 XI M38-1 NUREG-1801, Rev. 2

XI.M38 INSPECTION OF INTERNAL SURFACES IN MISCELLANEOUS PIPING AND 

DUCTING COMPONENTS

Program Description

The program consists of inspections of the internal surfaces of metallic piping, piping 

components, ducting, polymeric components, and other components that are exposed to airindoor uncontrolled, air outdoor, condensation, and any water system other than open-cycle 

cooling water system (XI.M20), closed treated water system (XI.M21A), and fire water system 

(XI.M27). 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 ensure that existing 

environmental conditions are not causing material degradation that could result in a loss of 

component intended functions. For certain materials, such as polymers, physical manipulation 

or pressurization (e.g., hydrotesting) to detect hardening or loss of strength should be used to 

augment the visual examinations conducted under this program. If visual inspection of internal 

surfaces is not possible, then the applicant needs to provide a plant-specific program.

This program is not intended for use on piping and ducts where repetitive failures have occurred 

from loss of material that resulted in loss of intended function. If operating experience indicates 

that there have been repetitive failures caused by loss of material, a plant-specific program will 

be required. Following a failure, this program may be used if the failed material is replaced by 

one that is more corrosion-resistant in the environment of interest.

Evaluation and Technical Basis

1. Scope of Program: For metallic components, the program calls for the visual inspection of 

the internal surface of in-scope components that are not included in other aging 

management programs for loss of material. For metallic components with polymeric liners or 

for polymeric and elastomeric components, the program includes visual inspections of the 

internal polymer surfaces when coupled with additional augmented techniques, such as 

manipulation or pressurization. This program also includes metallic piping with or without 

polymeric linings, piping elements, ducting, and components in an internal environment. The 

program also calls for visual inspection and monitors the internal surfaces of polymeric and 

elastomeric components in mechanical systems for hardening and loss of strength, cracking, 

and for loss of material due to wear. The program manages the effects of aging of polymer 

materials in all environments to which these materials are exposed. Inspections are 

performed when the internal surfaces are accessible during the performance of periodic 

surveillances or during maintenance activities or scheduled outages. This program is not 

intended for piping and ducts where failures have occurred from loss of material from 

corrosion.

2. Preventive Actions: This program is a condition monitoring program to detect signs of 

degradation and does not provide guidance for prevention.

3. Parameters Monitored/Inspected: Parameters monitored or inspected include visible 

evidence of loss of material in metallic components.

This program manages loss of material and possible changes in material properties. This 

program monitors for evidence of surface discontinuities. For changes in material properties, 
NUREG-1801, Rev. 2 XI M38-2 December 2010

the visual examinations are supplemented, so changes in the properties are readily 

observable. 

Examples of inspection parameters for metallic components include the following:

 corrosion and material parameters wastage (loss of material)

 leakage from or onto internal surfaces (loss of material)

 worn, flaking, or oxide-coated surfaces (loss of material) 

Examples of inspection parameters for polymers are as follows:

 surface cracking, crazing, scuffing, and dimensional change (e.g., “ballooning” and 

“necking”) 

 discoloration

 exposure of internal reinforcement for reinforced elastomers

 hardening as evidenced by a loss of suppleness during manipulation where the 

component and material are appropriate to manipulation

4. Detection of Aging Effects: Visual and mechanical inspections conducted under this 

program are opportunistic in nature; they are conducted whenever piping or ducting are 

opened for any reason. Visual inspections should include all accessible surfaces. Unless 

otherwise required (e.g., by the ASME code) all inspections should be carried out using 

plant-specific procedures by inspectors qualified through plant specific programs. The 

inspection procedures utilized must be capable of detecting the aging effect(s) under 

consideration. These inspections provide for the detection of aging effects prior to the loss of 

component function. Visual inspection of flexible polymeric components is performed 

whenever the component surface is accessible. Visual inspection can provide indirect 

indicators of the presence of surface cracking, crazing, and discoloration. For elastomers 

with internal reinforcement, visual inspection can detect the exposure of reinforcing fibers, 

mesh, or underlying metal. Visual and tactile inspections are performed when the internal 

surfaces become accessible during the performance of periodic surveillances or during 

maintenance activities or scheduled outages. Visual inspection provides direct indicators of 

loss of material due to wear, including dimensional change, scuffing, and the exposure of 

reinforcing fibers, mesh, or underlying metal for flexible polymeric materials with internal 

reinforcement.

Manual or physical manipulation of flexible polymeric components is used to augment visual 

inspection, where appropriate, to assess loss of material or strength. The sample size for 

manipulation is at least 10 percent of available surface area, including visually identified 

suspect areas. For flexible polymeric materials, hardening, loss of strength, or loss of 

material due to wear is expected to be detectable prior to any loss of intended function.

5. Monitoring and Trending: The Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components program uses standardized monitoring and trending activities to track 

degradation. Deficiencies are documented using approved processes and procedures such 
December 2010 XI M38-3 NUREG-1801, Rev. 2

that results can be trended. However, the program does not include formal trending. 

Inspections are performed at frequencies identified in Element 4, 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 is identified before loss of 

intended functions. For metallic surfaces, any indications of relevant degradation detected 

are evaluated. For stainless steel surfaces, a clean, shiny surface is expected. Discoloration 

may indicate the loss of material on the stainless steel surface. Any abnormal surface 

condition may be an indication of an aging effect for metals. 

For flexible polymers, a uniform surface texture and uniform color with no unanticipated 

dimensional change is expected. Any abnormal surface condition may be an indication of an 

aging effect for metals and for polymers. For flexible materials to be considered acceptable, 

the inspection results should indicate that the flexible polymer material is in “as new” 

condition (e.g., the hardness, flexibility, physical dimensions, and color of the material are 

unchanged from when the material was new). Cracks should be absent within the material. 

For rigid polymers, surface changes affecting performance, such as erosion, cracking, 

crazing, checking, and chalks, are subject to further investigation.

Acceptance criteria include design standards, procedural requirements, current licensing 

basis, industry codes or standards, and engineering evaluation.

7. Corrective Actions: The site corrective actions program, quality assurance 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 for 

GALL, 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: As discussed in the GALL Report, the staff finds the requirements 

10 CFR Part 50, Appendix B, acceptable to address the confirmation process.

9. Administrative Controls: As discussed in the GALL Report, the staff finds the 

requirements 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: Inspections of internal surfaces during the performance of periodic 

surveillance and maintenance activities have been in effect at many utilities in support of 

plant component 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 period of extended operation. The applicant 

evaluates recent operating experience and provides objective evidence to support the 

conclusion that the effects of aging are adequately managed.
NUREG-1801, Rev. 2 XI M38-4 December 2010

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

EPRI Technical Report 1007933, Aging Assessment Field Guide, December 2003.

EPRI Technical Report 1009743, Aging Identification and Assessment Checklist, August 27, 

2004.

INPO Good Practice TS-413, Use of System Engineers, INPO 85-033, May 18, 1988.
December 2010 XI M39-1 NUREG-1801, Rev. 2

XI.M39 LUBRICATING OIL ANALYSIS 

Program Description

The purpose of the Lubricating Oil Analysis program is to ensure that the oil environment in the 

mechanical systems is maintained to the required quality to prevent or mitigate age-related 

degradation of components within the scope of this program. This program maintains oil 

systems contaminants (primarily water and particulates) within acceptable limits, thereby 

preserving an environment that is not conducive to loss of material 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.

Although primarily a sampling program, the lubricating oil analysis program is generally effective 

in monitoring and controlling impurities. This report identifies when the program is to be 

augmented to manage the effects of aging for license renewal. Accordingly, in certain cases 

identified in this report, verification of the effectiveness of the program is undertaken to ensure 

that significant degradation is not occurring and that the component’s intended function is 

maintained during the period of extended operation. 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 manages the aging effects of loss of material due to 

corrosion or reduction of heat transfer due to fouling. Components within the scope of the 

program include piping, piping components, and piping elements; heat exchanger tubes; 

reactor coolant pump elements; and any other plant components subject to aging 

management review that are exposed to an environment of lubricating oil (including nonwater-based hydraulic oils).

2. Preventive Actions: The Lubricating Oil Analysis program maintains oil system 

contaminants (primarily water and particulates) within acceptable limits.

3. Parameters Monitored/Inspected: This program performs a check for water and a particle 

count to detect evidence of contamination by moisture or excessive corrosion. 

4. Detection of Aging Effects: Moisture or corrosion products increase the potential for, or 

may be indicative of, loss of material due to corrosion and reduction of heat transfer due to 

fouling. The program performs periodic sampling and testing of lubricating oil for moisture 

and corrosion particles in accordance with industry standards. The program recommends 

sampling and testing of the old oil following periodic oil changes or on a schedule consistent 

with equipment manufacturer’s recommendations or industry standards (e.g., American 

Society for Testing of Materials [ASTM] D 6224-02). Plant-specific operating experience also 

may be used to augment manufacturer’s recommendations or industry standards in 

determining the schedule for periodic sampling and testing when justified by prior sampling 

results.

In certain cases, as identified by the AMR Items in this report, inspection of selected 

components is to be undertaken to verify the effectiveness of the program and to ensure 
NUREG-1801, Rev. 2 XI M39-2 December 2010

that significant degradation is not occurring and that the component intended function is 

maintained during the period of extended operation.

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: Water and particle concentration should not exceed limits based on 

equipment manufacturer’s recommendations or industry standards. Phase-separated water 

in any amount is not acceptable.

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, corrective maintenance, further laboratory analysis, and 

engineering evaluation of the system. As discussed in the Appendix for GALL, 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process and administrative controls.

9. Administrative Controls: The administrative controls for this program provide for a formal 

review and approval of corrective actions. The administrative controls for this program are 

implemented through the site's QA program in accordance with the requirements of 10 CFR 

Part 50, Appendix B.

10. Operating Experience: The operating experience at some plants has identified (a) water in 

the lubricating oil and (b) 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, 2009.

ASTM D 6224-02, Standard Practice for In-Service Monitoring of Lubricating Oil for Auxiliary 

Power Plant Equipment, American Society of Testing Materials, West Conshohocken, PA, 

2002.
December 2010 XI M40-1 NUREG-1801, Rev. 2

XI.M40 MONITORING OF NEUTRON-ABSORBING MATERIALS OTHER THAN 

BORAFLEX

Program Description

A monitoring program is implemented to assure that degradation of the neutron-absorbing 

material used in spent fuel pools that could compromise the criticality analysis will be detected. 

The applicable aging management program (AMP) relies on periodic inspection, testing, 

monitoring, and analysis of the criticality design to assure that the required 5% sub-criticality 

margin is maintained during the period of license renewal. 

Evaluation and Technical Basis

1. Scope of Program: The AMP manages the effects of aging on neutron-absorbing 

components/materials used in spent fuel racks.

2. Preventive Actions: This AMP is a condition monitoring program, and therefore, there are 

no preventative actions.

3. Parameters Monitored/Inspected: For these materials, gamma irradiation and/or long-term 

exposure to the wet pool environment may cause loss of material and changes in dimension 

(such as gap formation, formation of blisters, pits and bulges) that could result in loss of 

neutron-absorbing capability of the material. The parameters monitored include the physical 

condition of the neutron-absorbing materials, such as in-situ gap formation, geometric 

changes in the material (formation of blisters, pits, and bulges) as observed from coupons or 

in situ, and decreased boron areal density, etc. The parameters monitored are directly 

related to determination of the loss of material or loss of neutron absorption capability of the 

material(s).

4. Detection of Aging Effects: The loss of material and the degradation of the neutronabsorbing material capacity are determined through coupon and/or direct in-situ testing. 

Such testing should include periodic verification of boron loss through areal density 

measurement of coupons or through direct in-situ techniques, which may include 

measurement of boron areal density, geometric changes in the material (blistering, pitting, 

and bulging), and detection of gaps through blackness testing. The frequency of the 

inspection and testing depends on the condition of the neutron-absorbing material and is 

determined and justified with plant-specific operating experience by the licensee, not to 

exceed 10 years.

5. Monitoring and Trending: The measurements from periodic inspections and analysis are 

compared to baseline information or prior measurements and analysis for trend analysis. 

The approach for relating the measurements to the performance of the spent fuel neutron 

absorber materials is specified by the applicant, considering differences in exposure 

conditions, vented/non-vented test samples, and spent fuel racks, etc.

6. Acceptance Criteria: Although the goal is to ensure maintenance of the 5% sub-criticality 

margin for the spent fuel pool, the specific acceptance criteria for the measurements and 

analyses are specified by the applicant.

7. Corrective Actions: Corrective actions are initiated if the results from measurements and 

analysis indicate that the 5% sub-criticality margin cannot be maintained because of 
NUREG-1801, Rev. 2 XI M40-2 December 2010

current or projected future degradation of the neutron-absorbing material. Corrective actions 

may consist of providing additional neutron-absorbing capacity with an alternate material, or 

applying other options, which are available to maintain the sub-criticality margin. As 

discussed in the Appendix for GALL, 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 for GALL, the 

staff finds the requirements of 10 CFR Part 50, Appendix B acceptable to address the 

confirmation process and administrative controls.

9. Administrative Controls: As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address administrative controls.

10. Operating Experience: Applicants for license renewal reference plant-specific operating 

experience and industry experience to provide reasonable assurance that the program is 

able to detect degradation of the neutron absorbing material in the applicant’s spent fuel 

pool. Some of the industry operating experience that should be included is listed below:

1. Loss of material from the neutron absorbing material has been seen at many plants, 

including loss of aluminum, which was detected by monitoring the aluminum 

concentration in the spent fuel pool. One instance of this was documented in the 

Vogtle LRA Water Chemistry Program B.3.28.

2. Blistering has also been noted at many plants. Examples include blistering at 

Seabrook and Beaver Valley.

3. The significant loss of neutron-absorbing capacity of the plate-type carborundum 

material has been reported at Palisades.

The applicant should describe how the monitoring program described above is capable of 

detecting the aforementioned degradation mechanisms. 

References

Interim Staff Guidance LR-ISG-2009-01, Aging Management of Spent Fuel Pool NeutronAbsorbing Materials Other Than Boraflex, 2010.

Letter from Christopher J. Schwarz, Entergy Nuclear Operations, Inc., Palisades Nuclear Plant, 

to the U.S. Nuclear Regulatory Commission, Commitments to Address Degraded Spent Fuel 

Pool Storage Rack Neutron Absorber, August 27, 2008, (ADAMS Accession 

No. ML082410132).

Letter from Kevin L. Ostrowski, FirstEnergy Nuclear Operating Company, to the U.S. Nuclear 

Regulatory Commission, Supplemental Information for the Review of the Beaver Valley 

Power Station, Units 1 and 2, License Renewal Application (TAC Nos. MD6593 and 

MD6594) and License Renewal Application Amendment No. 34, January 19, 2009, (ADAMS 

Accession No. ML090220216).
December 2010 XI M40-3 NUREG-1801, Rev. 2

Letter from Mark E. Warner, FPL Energy Seabrook Station, to the U.S. Nuclear Regulatory 

Commission, Seabrook Station Boral Spent Fuel Pool Test Coupons Report Pursuant to 

10 CFR Part 21.21, October 6, 2003 (ADAMS Accession No. ML032880525).

License Renewal Application Vogtle Electric Generating Plant Units 1 and 2, Southern Nuclear 

Operating Company, Inc., June 30, 2007 (ADAMS Accession No. ML071840360).

NRC Information Notice 2009-26, Degradation of Neutron-Absorbing Materials in the Spent Fuel 

Pool, U.S. Nuclear Regulatory Commission, October 28, 2009.

December 2010 XI M41-1 NUREG-1801, Rev. 2

XI.M41 BURIED AND UNDERGROUND PIPING AND TANKS

Program Description

This is a comprehensive program designed to manage the aging of the external surfaces of 

buried and underground piping and tanks and to augment other programs that manage the 

aging of internal surfaces of buried and underground piping and tanks. It addresses piping and 

tanks composed of any material, including metallic, polymeric, cementitious, and concrete 

materials. This program manages aging through preventive, mitigative, and inspection activities. 

It manages all applicable aging effects such as loss of material, cracking, and changes in 

material properties.

Depending on the material, preventive and mitigative techniques may include the material itself, 

external coatings for external corrosion control, the application of cathodic protection, and the 

quality of backfill utilized. Also, depending on the material, inspection activities may include 

electrochemical verification of the effectiveness of cathodic protection, non-destructive 

evaluation of pipe or tank wall thicknesses, hydrotesting of the pipe, and visual inspections of 

the pipe or tank from the exterior as permitted by opportunistic or directed excavations.

Management of aging of the internal surfaces of buried and underground piping and tanks is 

accomplished through the use of other aging management programs (e.g., Open Cycle Cooling 

Water System (AMP XI.M20), Closed Treated Water System (AMP XI.M21A), Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components (AMP XI.M38), Fuel Oil 

Chemistry (AMP XI.M30), Fire Water System (AMP XI.M27), or Water Chemistry (AMP XI.M2)). 

However, in some cases, this external surface program may be used in conjunction with the 

internal surface aging management programs to manage the aging of the internal surfaces of 

buried and underground piping and tanks. This program does not address selective leaching. 

The Selective Leaching of Materials (AMP XI.M33) is applied in addition to this program for 

applicable materials and environments.

The terms “buried” and “underground” are fully defined in Chapter IX of the GALL Report. 

Briefly, buried piping and tanks are in direct contact with soil or concrete (e.g., a wall 

penetration). Underground piping and tanks are below grade but are contained within a tunnel 

or vault such that they are in contact with air and are located where access for inspection is 

restricted.

Evaluation and Technical Basis

1. Scope of Program: This program is used to manage the effects of aging for buried and 

underground piping and tanks constructed of any material including metallic, polymeric, 

cementitious, and concrete materials. The program addresses aging effects such as loss of 

material, cracking, and changes in material properties. Typical systems in which buried and 

underground piping and tanks may be found include service water piping and components, 

condensate storage transfer lines, fuel oil and lubricating oil lines, fire protection piping and 

piping components (fire hydrants), and storage tanks. Loss of material due to corrosion of 

piping system bolting within the scope of this program is managed using this program. Other 

aging effects associated with piping system bolting are managed through the use of the 

Bolting Integrity Program (AMP XI.M18).
NUREG-1801, Rev. 2 XI M41-2 December 2010

2. Preventive Actions: Preventive actions utilized by this program vary with the material of the 

tank or pipe and the environment (air, soil, or concrete) to which it is exposed. These actions 

are outlined below:

a. Preventive Actions – Buried Piping and Tanks

i. Preventive actions for buried piping and tanks are conducted in accordance with 

Table 2a and its accompanying footnotes.

Table 2a. Preventive Actions for Buried Piping and Tanks

Material1 Coating2 Cathodic Protection4 Backfill Quality

Titanium

Super Austenitic Stainless8 

Stainless Steel X3 X5, 7

Steel X X X5 

Copper X X X5 

Aluminum X X X5 

Cementitious or Concrete X3 X5, 7

Polymer X6 

1. Materials classifications are meant to be broadly interpreted (e.g., all alloys of titanium that are commonly used for buried 

piping are to be included in the titanium category). Material categories are generally aligned with P numbers as found in 

the ASME Code, Section IX. Steel is defined in Chapter IX of this report. Polymer includes polymeric materials as well as 

composite materials such as fiberglass. 

2. When provided, coatings are in accordance with Table 1 of NACE SP0169-2007 or Section 3.4 of NACE RP0285-2002. 

3. Coatings are provided based on environmental conditions (e.g., stainless steel in chloride containing environments). If 

coatings are not provided, a justification is provided in the LRA. 

4. Cathodic protection is in accordance with NACE SP0169-2007 or NACE RP0285-2002. The system should be operated 

so that the cathodic protection criteria and other considerations described in the standards are met at every location in the 

system. The duration of deviations from these criteria should not exceed 90 days. The system monitoring interval 

discussed in section 10.3 of NACE SP0169-2007 may not be extended beyond one year. The equipment used to 

implement cathodic protection need not be qualified in accordance with 10 CFR 50 Appendix B. 

5. Backfill is consistent with SP0169-2007 section 5.2.3. The staff considers backfill that is located within 6 inches of the 

pipe that meets ASTM D 448-08 size number 67 to meet the objectives of SP0169-2007. For materials other than 

aluminum, the staff also considers the use of controlled low strength materials (flowable backfill) to meet the objectives of 

SP0169-2007. Backfill quality may be demonstrated by plant records or by examining the backfill while conducting the 

inspections conducted in program element 4 of this AMP. Backfill not meeting this standard, in either the initial or 

subsequent inspections, is acceptable if the inspections conducted in program element 4 of this AMP do not reveal 

evidence of mechanical damage to pipe coatings due to the backfill. 

6. Backfill is consistent with SP0169-2007 section 5.2.3. The staff considers backfill that is located within 6 inches of the 

pipe that meets ASTM D 448-08 size number 10 to meet the objectives of SP0169-2007. The staff also considers the use 

of controlled low strength materials (flowable backfill) to meet the objectives of SP0169-2007. Backfill quality may be 

demonstrated by plant records or by examining the backfill while conducting the inspections conducted in program 

element 4 of this AMP. Backfill not meeting this standard, in either the initial or subsequent inspections, is acceptable if 

the inspections conducted in program element 4 of this AMP do not reveal evidence of mechanical damage to pipe 

coatings due to the backfill. 

7. Backfill limits apply only if piping is coated. 

8. Super austenitic stainless steel (e.g., Al6XN or 254 SMO).

ii. Fire mains are installed in accordance with National Fire Protection Association 

(NFPA) Standard 24. Preventive actions for fire mains beyond those in NFPA 24 

need not be provided if the system undergoes either a periodic flow test in 

accordance with NFPA 25 or the activity of the jockey pump (or equivalent 

equipment or parameter) is monitored as described in program element 4 of this 

AMP. 
December 2010 XI M41-3 NUREG-1801, Rev. 2

iii. When referenced, NACE SP0169-2007 is to be used in its entirety excepting 

Section 3, Determination of Need for External Corrosion Control. Use of Section 3 of 

the standard constitutes an exception to this AMP. Exceptions to the AMP related to 

the need for external corrosion control should include an analysis of issues such as 

those described in National Cooperative Highway Research Program (NCHRP) 

Report 408, “Corrosion of Steel Piling in Non Marine Applications and American 

Association of State Highway and Transportation Officials (AASHTO) Standard R 

27.” 

b. Preventive Actions – Underground Piping and Tanks

i. Preventive actions for underground piping and tanks are conducted in accordance 

with Table 2b and its accompanying footnotes.

Table 2b. Preventive Actions for Underground Piping and Tanks

Material1 Coating Provided2

Titanium

Super Austenitic Stainless3 

Stainless Steel

Steel X 

Copper X 

Aluminum

Cementitious or Concrete

Polymer

1. Materials classifications are meant to be broadly interpreted (e.g., all alloys of titanium that are commonly used for buried 

piping are to be included in the titanium category). Material categories are generally aligned with P numbers as found in 

the ASME Code, Section IX. Steel is defined in chapter IX of this report. Polymer includes polymeric materials as well as 

composite materials such as fiberglass. 

2. When provided, coatings are in accordance with Table 1 of NACE SP0169-2007 or Section 3.4 of NACE RP0285-2002. A 

broader range of coatings may be used if justification is provided in the LRA. 

3. Super austenitic stainless steel (e.g., Al6XN or 254 SMO).

3. Parameters Monitored/Inspected: The aging effects addressed by this AMP are changes 

in material properties of polymeric materials, loss of material due to all forms of corrosion 

and, potentially, cracking due to stress corrosion cracking. Changes in material properties 

are monitored by manual examinations. Loss of material is monitored by visual appearance 

of the exterior of the piping or tank and wall thickness of the piping or tank. Wall thickness is 

determined by a non-destructive examination technique such as ultrasonic testing (UT). Two 

additional parameters, the pipe-to-soil potential and the cathodic protection current, are 

monitored for steel, copper, and aluminum piping and tanks in contact with soil to determine 

the effectiveness of cathodic protection systems and, thereby, the effectiveness of corrosion 

mitigation.

4. Detection of Aging Effects: Methods and frequencies used for the detection of aging 

effects vary with the material and environment of the buried and underground piping and 

tanks. These methods and frequencies are outlined below.

a. Opportunistic Inspections
NUREG-1801, Rev. 2 XI M41-4 December 2010

i. All buried and underground piping and tanks, regardless of their material of 

construction, are inspected by visual means whenever they become accessible for 

any reason. The information in paragraph f of this program element is applied in the 

event deterioration of piping or tanks is observed. 

b. Directed Inspections – Buried Pipe

i. Directed inspections for buried piping are conducted in accordance with Table 4a 

and its accompanying footnotes. Modifications to this table may be appropriate if 

exceptions to program Element 2, Preventive Actions, are taken or in response to 

plant specific operating experience.

ii. Unless otherwise indicated, directed inspections as indicated in Table 4a will be 

conducted during each 10-year period beginning 10 years prior to the entry into the 

period of extended operation. 

iii. Inspection locations are selected based on risk (based on susceptibility to 

degradation and consequences of failure). Characteristics such as coating type, 

coating condition, cathodic protection efficacy, backfill characteristics, soil resistivity, 

pipe contents, and pipe function are considered. Piping systems that are backfilled 

using controlled low strength material generally experience lower corrosion rates and 

may be more difficult to excavate than piping systems backfilled using compacted 

aggregate fill. As a result, piping systems that are backfilled using compacted 

aggregate should generally be given a higher inspection priority than comparable 

systems that are completely backfilled using controlled low strength material. For 

many piping systems, External Corrosion Direct Assessment (ECDA) as described in 

NACE Standard Practice SP0502-2010 has been demonstrated to be an effective 

method for use in the identification of pipe locations that merit further inspection.

iv. Visual inspections are supplemented with surface and/or volumetric non-destructive 

testing (NDT) if significant indications are observed.

v. Opportunistic examinations of non leaking pipes may be credited toward these direct 

examinations if the location selection criteria in item iii, above, are met.

vi. At multi-unit sites, individual inspections of shared piping may be credited for only 

one unit. 

vii. Visual inspections for polymeric materials are augmented with manual examinations 

to detect hardening, softening, or other changes in material properties.

viii. The use of guided wave ultrasonic or other advanced inspection techniques is 

encouraged for the purpose of determining those piping locations that should be 

inspected but may not be substituted for the inspections listed in the table.

ix. For the purpose of this program element, fire mains will be considered to be code 

class/safety-related piping and inspected as such unless they are subjected to either 

a flow test as described in section 7.3 of NFPA 25 at a frequency of at least one test 

in each 1-year period or the activity of the jockey pump (or equivalent equipment or 

parameter) is monitored on an interval not to exceed 1 month. At a minimum, a flow 

test is conducted by the end of the next refueling outage or as directed by current 
December 2010 XI M41-5 NUREG-1801, Rev. 2

licensing basis, whichever is shorter, when unexplained changes in jockey pump 

activity (or equivalent equipment or parameter) are observed.

x. Inspection as indicated in either (A) or (B) below may be performed in lieu of the 

inspections contained in Table 4a for either code class/safety significant or hazmat 

piping or both:

A. At least 25% of the code class/safety-related or hazmat piping or both 

constructed from the material under consideration is hydrostatically tested in

accordance with 49 CFR 195 subpart E on an interval not to exceed 5 years. 

B. At least 25% of the code class/safety-related or hazmat piping or both 

constructed from the material under consideration is internally inspected by a 

method capable of precisely determining pipe wall thickness. The inspection 

method must be capable of detecting both general and pitting corrosion and 

must be qualified by the applicant and approved by the staff. As of the 

effective date of this document, guided wave ultrasonic examinations do not 

meet this paragraph. Internal inspections are to be conducted at an interval 

not to exceed 5 years. Consideration should be given to NACE SP0169-2007 

sections 6.1.2 and 6.3.3.

Table 4a. Inspections of Buried Pipe

Material1 Preventive 

Actions2 

Inspections3 

Code Class Safety-related4 Hazmat5 

Titanium

Super Austenitic Stainless7 

Stainless Steel 16 16 

HDPE8 A 

B 

16

2 

16

1%

Other Polymer9 A 

B 

16

2 

16

1%

Cementitious or Concrete 16 16 

Steel

C 

D 

E 

F 

16

1 

410

8 

16

2%

5%10

10%

Copper

C 

D 

E 

F 

16

1 

110

2 

16

1%

2%10

5%

Aluminum

C 

D 

E 

16

1 

1 

16

2%

5%
NUREG-1801, Rev. 2 XI M41-6 December 2010

Table 4a. Inspections of Buried Pipe

Material1 Preventive 

Actions2 

Inspections3 

Code Class Safety-related4 Hazmat5 

F 2 10%

1. Materials classifications are meant to be broadly interpreted (e.g., all alloys of titanium that are commonly used for buried 

piping are to be included in the titanium category). Material categories are generally aligned with P numbers as found in 

the ASME Code, Section IX. Steel is defined in chapter IX of this report. Polymer includes polymeric materials as well as 

composite materials such as fiberglass. 

2. Preventive actions are categorized as follows: 

A. Backfill is in accordance with Table 2a of this AMP. 

B. Backfill is not in accordance with Table 2a of this AMP. 

C. External corrosion control is provided in accordance with NACE SP0169-2007. Each cathodic protection system (a) 

was installed at least 5 years prior to the period of extended operation and was operational for 90% of the time during 

that 5-year period or (b) was operational for 90% of the time since the last inspection conducted under this program. 

D. External corrosion control is provided in accordance with NACE SP0169-2007. Each cathodic protection system (a) 

was installed less than 5 years prior to the period of extended operation or was operational for less than 90% of the 

time during that 5-year period or (b) was operational for less than 90% of the time since the last inspection conducted 

under this program. 

E. Coatings and backfill are in accordance with Table 2a of this AMP, but cathodic protection is not provided or is not 

consistent with criteria C or D. This category is provided for use during the 10 years prior to the period of extended 

operation by applicants who are not able to install cathodic protection in accordance with program element 2 prior to 

entry into the period of extended operation. Following entry into the period of extended operation, consistency with 

program element 2 or an approved alternative is expected. 

F. Preventive actions provided do not meet criteria C, D, or E. This category is provided for use during the 10 years prior 

to the period of extended operation by applicants who are not able to install cathodic protection in accordance with 

program element 2 prior to entry into the period of extended operation. Following entry into the period of extended 

operation, consistency with program element 2 or an approved alternative is expected. 

3. Inspections are listed as either a discrete number of visual examinations (excavations) or as a percentage of the linear 

length of piping under consideration. The following guidance related to the extent of inspections is provided: 

A. Each inspection will examine either the entire length of a run of pipe or a minimum of 10 feet. 

B. If the number of inspections times the minimum inspection length (10 feet) exceeds 10% of the length of the piping 

under consideration, only 10% need be inspected.

C. If the total length of in-scope pipe constructed of a given material times the percentage to be inspected is less than 10 

feet, either 10 feet or the total length of pipe present, whichever is less, will be inspected. 

4. Code Class and safety-related pipe that also meets the definition of hazmat pipe will be inspected as hazmat pipe. 

5. Hazmat pipe is pipe that, during normal operation, contains material that, if released, could be detrimental to the 

environment. This includes chemical substances such as diesel fuel and radioisotopes. To be considered hazmat, the 

concentration of radioisotopes within the pipe during normal operation must exceed established standards such as the 

EPA drinking water standard. In the absence of such standards, the concentration of the radioisotope must exceed the 

greater of background or reliable level of detection. For tritium, the EPA drinking water standard (20,000 pCi/L) is used. 

(This approach for defining hazmat is consistent with that used in classifying fluid services in ASME B31.3 appendix M.) 

6. Only one inspection is conducted even if both Code Class/safety-related and hazmat pipe are present. No inspections are 

necessary if all the piping constructed from the material under consideration is fully backfilled using controlled low strength 

material. 

7. Super austenitic stainless steel (e.g., Al6XN or 254 SMO). 

8. High Density Polyethylene (HDPE) pipe includes only HDPE pipe approved for use by the NRC for buried applications. 

9. Other polymer piping includes some HDPE pipe and all other polymeric materials including composite materials such as 

fiberglass. 

10. Inspections may be reduced to one-half the level indicated in the table when performing the indicated inspections 

necessitates excavation of piping that has been fully backfilled using controlled low strength material. In conducting these 

inspections, the backfill may be excavated and the pipe examined, or the soil around the backfill may be excavated and the 

controlled low strength material backfill examined. The corrosion rate of piping that is fully encased within controlled low 

strength material backfill that shows no signs of degradation, particularly cracking, is expected to be minimal. 
December 2010 XI M41-7 NUREG-1801, Rev. 2

c. Directed Inspections – Underground Pipe

i. Directed inspections for underground piping are conducted in accordance with Table 

4b and its accompanying footnotes. 

ii. Unless otherwise indicated, directed inspections as indicated in Table 4b will be 

conducted during each 10-year period beginning 10 years prior to the entry into the 

period of extended operation. 

iii. Inspection locations are selected based on risk (based on susceptibility to 

degradation and consequences of failure). Characteristics such as coating type, 

coating condition, exact external environment, pipe contents, pipe function, and flow 

characteristics within the pipe, are considered.

iv. Underground pipes are inspected visually to detect external corrosion and by a 

volumetric technique such as UT to detect internal corrosion. 

v. Opportunistic examinations may be credited toward these direct examinations if the 

location selection criteria in item iii, above, are met.

vi. At multi-unit sites, individual inspections of shared piping may be credited for only 

one unit. 

vii. When access permits, visual inspections for polymeric materials are augmented with 

manual examinations to detect hardening, softening, or other changes in material 

properties.

viii. The use of guided wave ultrasonic or other advanced inspection techniques is 

encouraged for the purpose of determining those piping locations that should be 

inspected but may not be substituted for the inspections listed in the table.

ix. For the purpose of this program element, fire mains will be considered to be code 

class/safety-related piping and inspected as such unless they are subjected to either 

a flow test as described in section 7.3 of NFPA 25 at an frequency of at least one 

test in each 1-year period or the activity of the jockey pump (or equivalent equipment 

or parameter) is monitored on an interval not to exceed 1 month. At a minimum, a 

flow test is conducted by the end of the next refueling outage or as directed by 

current licensing basis, whichever is shorter, when unexplained changes in jockey 

pump activity (or equivalent equipment or parameter) are observed.
NUREG-1801, Rev. 2 XI M41-8 December 2010

Table 4b. Inspections of Underground Pipe

Material1 Inspections2 

Code Class Safety-related3 Hazmat4 

Titanium

Super Austenitic Stainless6 

Stainless Steel 15 15 

HDPE7 15 15

Other Polymer8 15 15

Cementitious or Concrete 15 15 

Steel 2 2%

Copper 1 1%

Aluminum 1 1%

1. Materials classifications are meant to be broadly interpreted (e.g., all alloys of titanium that are commonly used for buried 

piping are to be included in the titanium category). Material categories are generally aligned with P numbers as found in 

the ASME Code, Section IX. Steel is as defined in chapter IX of this report. Polymer includes polymeric materials as well 

as composite materials such as fiberglass.

2. Inspections are listed as either a discrete number of visual examinations or as a percentage of the linear length of piping 

under consideration. The following guidance related to the extent of inspections is provided: 

A. Each inspection will examine either the entire length of a run of pipe or a minimum of 10 feet. 

B. If the number of inspections times the minimum inspection length (10 feet) exceeds 10% of the length of the piping 

under consideration, only 10% need be inspected.

C. If the total length of in scope pipe constructed of a given material times the percentage to be inspected is less than 10 

feet, either 10 feet or the total length of pipe present, whichever is less, will be inspected. 

3. Code Class and safety-related pipe that also meets the definition of hazmat pipe will be inspected as hazmat pipe. 

4. Hazmat pipe is pipe that, during normal operation, contains material that, if released, could be detrimental to the 

environment. This includes chemical substances such as diesel fuel and radioisotopes. To be considered hazmat, 

concentration of radioisotope within the pipe during normal operation must exceed established standards such as the 

EPA drinking water standard. In the absence of such standards, the concentration of the radioisotope must exceed the 

greater of background or reliable level of detection. For tritium, the EPA drinking water standard (20,000 pCi/L) is used. 

(This approach for defining hazmat is consistent with that used in classifying fluid services in ASME B31.3 appendix M.) 

5. Only one inspection is conducted even if both Code Class/safety-related and hazmat pipe are present. 

6. Super austenitic stainless steel (e.g., Al6XN or 254 SMO). 

7. HDPE pipe includes only HDPE pipe approved for use by the NRC for buried applications. 

8. Other polymer piping includes some HDPE pipe and all other polymeric materials including composite materials such as 

fiberglass.

x. Inspection as indicated in (A), and (B) below may be performed in lieu of the 

inspections contained in Table 4a for either code class/safety significant or hazmat 

piping or both:

A. At least 25% of the code class/safety-related or hazmat piping or both 

constructed from the material under consideration is hydrostatically tested in 

accordance with 49 CFR 195 subpart E on an interval not to exceed 5 years.

B. At least 25% of the code class/safety-related or hazmat piping or both 

constructed from the material under consideration is internally inspected by a 

method capable of precisely determining pipe wall thickness. The inspection 

method must be capable of detecting both general and pitting corrosion and 

must be qualified by the applicant and approved by the staff. As of the 

effective date of this document, guided wave ultrasonic examinations do not 

meet this paragraph. Internal inspections are to be conducted at an interval 
December 2010 XI M41-9 NUREG-1801, Rev. 2

not to exceed 5 years. Consideration should be given to SP0169-2007 

sections 6.1.2 and 6.3.3.

d. Directed Inspections – Buried Tanks

i. Directed inspections for buried tanks are conducted in accordance with Table 4c and 

its accompanying footnotes. Modifications to this table may be appropriate if 

exceptions to program Element 2, preventive actions, are taken or in response to 

plant specific operating experience.

ii. Directed inspections as indicated in Table 4c will be conducted during each 10-year 

period beginning 10 years prior to the entry into the period of extended operation.

iii. Each buried tank is examined if it is Code Class/safety-related or contains hazardous 

materials as defined in footnote 5 to Table 4a and it is constructed from a material for 

which an examination is indicated in Table 4c.

iv. Examinations may be conducted from the external surface of the tank using visual 

techniques or from the internal surface of the tank using volumetric techniques. If the 

tank is inspected from the external surface, a minimum 25% coverage is required. 

This area must include at least some of both the top and bottom of the tank. If the 

tank is inspected internally by UT, at least one measurement is required per square 

foot of tank surface. UT measurements are distributed uniformly over the surface of 

the tank. If the tank is inspected internally by another volumetric technique, at least 

90% of the surface of the tank must be inspected. Double wall tanks may be 

examined by monitoring the annular space for leakage.

v. Visual inspections for polymeric materials are augmented with manual examinations 

to detect hardening, softening, or other changes in material properties.

vi. Opportunistic examinations may be credited toward these direct examinations. 

Table 4c. Inspections of Buried Tanks

Material1 Preventive 

Actions2 Inspections

Titanium

Super Austenitic Stainless3 

Stainless Steel

HDPE4 A 

B X 

Other Polymer5 A 

B X 

Cementitious or Concrete X

Steel

C 

D 

E X 
NUREG-1801, Rev. 2 XI M41-10 December 2010

Table 4c. Inspections of Buried Tanks

Material1 Preventive 

Actions2 Inspections

Copper

C 

D 

E X 

Aluminum

C 

D 

E X 

1. Materials classifications are meant to be broadly interpreted (e.g., all alloys of titanium that are commonly used for buried 

piping are to be included in the titanium category). Material categories are generally aligned with P numbers as found in 

the ASME Code, Section IX. Steel is defined in chapter IX of this report. Polymer includes polymeric materials as well as 

composite materials such as fiberglass. 

2. Preventive actions are categorized as follows: 

A. Backfill is in accordance with Table 2a of this AMP. 

B. Backfill is not in accordance with Table 2a of this AMP. 

C. External corrosion control is provided in accordance with NACE RP0285-2002. Each cathodic protection system (a) 

was installed at least 5 years prior to the period of extended operation and was operational for 90% of the time during 

that 5-year period or (b) was operational for 90% of the time since the last inspection conducted under this program.

D. External corrosion control is provided in accordance with NACE RP0285-2002. Each cathodic protection system (a) 

was installed less than 5 years prior to the period of extended operation or was operational for less than 90% of the 

time during that 5-year period or (b) was operational for less than 90% of the time since the last inspection conducted 

under this program. 

E. Cathodic protection is not provided. This category is provided for use during the 10 years prior to the period of 

extended operation by applicants who are not able to install cathodic protection in accordance with program element 2 

prior to entry into the period of extended operation. Following entry into the period of extended operation, consistency 

with program element 2 or an approved alternative is expected. 

3. Super austenitic stainless steel (e.g., Al6XN or 254 SMO). 

4. HDPE includes only HDPE material approved for use by the NRC for buried applications. 

5. Other polymer includes some HDPE material and all other polymeric materials including composite materials such as 

fiberglass.

e. Directed Inspections – Underground Tanks

i. Directed inspections for underground tanks are conducted in accordance with Table 

4d and its accompanying footnotes.

ii. Directed inspections as indicated in Table 4d will be conducted during each 10-year 

period beginning 10 years prior to the entry into the period of extended operation.

Table 4d. Inspections of Underground Tanks

Material1 Inspections

Titanium

Super Austenitic Stainless2 

Stainless Steel

HDPE3

Other Polymer4

Cementitious or concrete

Steel X 
December 2010 XI M41-11 NUREG-1801, Rev. 2

Table 4d. Inspections of Underground Tanks

Material1 Inspections

Copper

Aluminum

1. Materials classifications are meant to be broadly interpreted (e.g., all alloys of titanium that are commonly used for buried 

piping are to be included in the titanium category). Material categories are generally aligned with P numbers as found in 

the ASME Code, Section IX. Steel is as defined in chapter IX of this report. Polymer includes polymeric materials as well 

as composite materials such as fiberglass. 

2. Super austenitic stainless steel (e.g., Al6XN or 254 SMO). 

3. HDPE includes only HDPE material approved for use by the NRC for buried applications. 

4. Other polymer includes some HDPE material and all other polymeric materials including composite materials such as 

fiberglass.

iii. Each underground tank that is Code Class/safety-related or contains hazardous 

materials as defined in footnote 5 to Table 4a and is constructed from a material for 

which an examination is indicated in Table 4d is examined.

iv. Examinations may be conducted from the external surface of the tank using visual 

techniques or from the internal surface of the tank using volumetric techniques. If the 

tank is inspected from the external surface, a minimum 25% coverage is required. 

This area must include at least some of both the top and bottom of the tank. If the 

tank is inspected internally by UT, at least one measurement is required per square 

foot of tank surface. If the tank is inspected internally by another volumetric 

technique, at least 90% of the surface of the tank must be inspected. Double wall 

tanks may be examined by monitoring the annular space for leakage.

v. Tanks that cannot be examined using volumetric examination techniques are 

examined visually from the outside. 

vi. When access permits, visual inspections for polymeric materials are augmented with 

manual examinations to detect hardening, softening, or other changes in material 

properties.

vii. Opportunistic examinations may be credited toward these direct examinations. 

f. Adverse indications

i. Adverse indications observed during monitoring of cathodic protection systems or 

during inspections are entered into the plant corrective action program. Adverse 

indications that are the result of inspections will result in an expansion of sample size

as described in item iv, below. Adverse indications that are the result of monitoring of 

a cathodic protection system may warrant increased monitoring of the cathodic 

protection system and/or additional inspections. Examples of adverse indications 

resulting from inspections include leaks, material thickness less than minimum, the 

presence of coarse backfill with accompanying coating degradation within 6 inches of 

a coated pipe or tank (see Table 2a Footnotes 5 and 6), and general or local 

degradation of coatings so as to expose the base material. 

ii Adverse indications that fail to meet the acceptance criteria described in program

element 6 of this AMP will result in the repair or replacement of the affected 

component. 
NUREG-1801, Rev. 2 XI M41-12 December 2010

iii. An analysis may be conducted to determine the potential extent of the degradation 

observed. Expansion of sample size may be limited by the extent of piping or tanks 

subject to the observed degradation mechanism. 

iv. If adverse indications are detected, inspection sample sizes within the affected piping 

categories are doubled. If adverse indications are found in the expanded sample, the 

inspection sample size is again doubled. This doubling of the inspection sample size 

continues as necessary. 

5. Monitoring and Trending: For piping and tanks protected by cathodic protection systems,

potential difference and current measurements are trended to identify changes in the 

effectiveness of the systems and/or coatings. If aging of fire mains is managed through 

monitoring jockey pump activity (or similar parameter), jockey pump activity (or similar 

parameter) is trended to identify changes in pump activity that may be the result of 

increased leakage from buried fire main piping.

6. Acceptance Criteria: The principal acceptance criteria associated with the inspections 

contained with this AMP follow:

a. Criteria for soil-to-pipe potential are listed in NACE RP0285-2002 and SP0169-2007. 

b. For coated piping or tanks, there should be either no evidence of coating degradation or 

the type and extent of coating degradation should be insignificant as evaluated by an 

individual possessing a NACE operator qualification or otherwise meeting the 

qualifications to evaluate coatings as contained in 49 CFR 192 and 195. 

c. If coated or uncoated metallic piping or tanks show evidence of corrosion, the remaining 

wall thickness in the affected area is determined to ensure that the minimum wall 

thickness is maintained. This may include different values for large area minimum wall 

thickness, and local area wall thickness. 

d. Cracking or blistering of nonmetallic piping is evaluated. 

e. Cementitious or concrete piping may exhibit minor cracking and spalling provided there 

is no evidence of leakage or exposed rebar or reinforcing “hoop” bands.

f. Backfill is in accordance with specifications described in program element 2 of this AMP. 

g. Flow test results for fire mains are in accordance with NFPA 25 section 7.3.

h. For hydrostatic tests, the condition “without leakage” as required by 49 CFR 195.302 

may be met by demonstrating that the test pressure, as adjusted for temperature, does 

not vary during the test. 

i. Changes in jockey pump activity (or similar parameter) that cannot be attributed to 

causes other than leakage from buried piping are not occurring.

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 
December 2010 XI M41-13 NUREG-1801, Rev. 2

requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions, 

confirmation process, and administrative controls.

8. Confirmation Process: The confirmation process ensures that preventive actions are 

adequate to manage the aging effects and that appropriate corrective actions have been 

completed and are effective. The confirmation process for this program is implemented 

through the site's QA program in accordance with the requirements of 10 CFR Part 50, 

Appendix B.

9. Administrative Controls: The administrative controls for this program provide for a formal 

review and approval of corrective actions. The administrative controls for this program are 

implemented through the site's QA program in accordance with the requirements of 10 CFR 

Part 50, Appendix B.

10. Operating Experience: Operating experience shows that buried and underground piping 

and tanks are subject to corrosion. Corrosion of buried oil, gas, and hazardous materials 

pipelines have been adequately managed through a combination of inspections and 

mitigative techniques, such as those prescribed in NACE SP0169-2007 and NACE RP0285-

2002. Given the differences in piping and tank configurations between transmission 

pipelines and those in nuclear facilities, it is necessary for applicants to evaluate both plantspecific and nuclear industry operating experience and to modify its aging management 

program accordingly. The following industry experience may be of significance to an 

applicant’s program:

a. In February 2005, a leak was detected in a 4-inch condensate storage supply line. The 

cause of the leak was microbiologically influenced corrosion or under deposit corrosion. 

The leak was repaired in accordance with the American Society of Mechanical 

Engineers (ASME) Section XI, “Repair/Replacement Plan.”

b. In September 2005, a service water leak was discovered in a buried service water 

header. The header had been in service for 38 years. The cause of the leak was either 

failure of the external coating or damage caused by improper backfill. The service water 

header was relocated above ground. 

c. In October 2007, degradation of essential service water piping was reported. The riser 

pipe leak was caused by a loss of pipe wall thickness due to external corrosion induced 

by the wet environment surrounding the unprotected carbon steel pipe. The corrosion 

processes that caused this leak affected all eight similar locations on the essential 

service water riser pipes within vault enclosures and had occurred over many years.

d. In February 2009, a leak was discovered on the return line to the condensate storage 

tank. The cause of the leak was coating degradation probably due to the installation 

specification not containing restrictions on the type of backfill allowing rocks in the 

backfill. The leaking piping was also located close to water table.

e. In April 2009, a leak was discovered in an aluminum pipe where it went through a 

concrete wall. The piping was for the condensate transfer system. The failure was 

caused by vibration of the pipe within its steel support system. This vibration led to 

coating failure and eventual galvanic corrosion between the aluminum pipe and the steel 

supports.
NUREG-1801, Rev. 2 XI M41-14 December 2010

f. In June 2009, an active leak was discovered in buried piping associated with the 

condensate storage tank. The leak was discovered because elevated levels of tritium 

were detected. The cause of the through-wall leaks was determined to be the 

degradation of the protective moisture barrier wrap that allowed moisture to come in 

contact with the piping resulting in external corrosion.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

49 CFR 195 subpart E, Transportation of Hazardous Liquids by Pipeline, Pressure Testing. 

Office of the Federal Register, National Archives and Records Administration, 2009.

AASHTO R 27, Standard Practice for Assessment of Corrosion of Steel Piling for Non Marine 

Applications, American Association of State Highway and Transportation Officials, 

Washington DC, 2006.

ASME Boiler and Pressure Vessel Code, Section IX, Welding and Brazing, American Society of 

Mechanical Engineers, 2004.

ASME Standard B31.3, Process Piping, Appendix M, American Society of Mechanical 

Engineers, 2002.

ASTM Standard D 448-08, Standard Classification for Sizes of Aggregate for Road and Bridge 

Construction, 2008. 

J. A. Beavers and C. L. Durr, Corrosion of Steel Piping in Non Marine Applications, NCHRP 

Report 408, Transportation Research Board, National Research Council, Washington DC, 

1998.

NACE Recommended Practice RP0285-2002, Standard Recommended Practice Corrosion 

Control of Underground Storage Tank Systems by Cathodic Protection, revised April 2002.

NACE Recommended Practice RP0502-2010, Pipeline External Corrosion Direct Assessment 

Methodology, 2010. 

NACE Standard Practice SP0169-2007, Control of External Corrosion on Underground or 

Submerged Metallic Piping Systems, 2007.

NFPA Standard 24, Standard for the Installation of Private Fire Service Mains and Their 

Appurtenances, 2010 edition.

NFPA Standard 25, Standard for the Inspection, Testing, and Maintenance of Water-Based Fire 

Protection Systems, 2008 edition.
December 2010 XI S1-1 NUREG-1801, Rev. 2

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 and moisture barriers, and pressure-retaining bolting. This evaluation 

covers the 2004 edition,

20

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 to detect aging effects. IWE 

specifies acceptance criteria, corrective actions, and expansion of the inspection scope when 

degradation exceeding the acceptance criteria is found. 

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.

Subsection IWE requires examination of coatings that are intended to prevent corrosion. AMP 

XI.S8 is a protective coating monitoring and maintenance program that is recommended to 

ensure Emergency Core Cooling System (ECCS) operability, whether or not the AMP XI.S8 is 

credited in AMP XI.S1.

The program attributes are augmented to incorporate aging management activities, 

recommended in the Final Interim Staff Guidance LR-ISG-2006-01, needed to address the 

potential loss of material due to corrosion in the inaccessible areas of the boiling water reactor 

(BWR) Mark I steel containment. 

The attributes also are augmented to require surface examination for detection of cracking 

described in NRC Information Notice (IN) 92-20 and to address recommendations delineated in 

NUREG-1339 and industry recommendations delineated in the Electric Power Research 

Institute (EPRI) NP-5769, NP-5067, and TR-104213 for structural bolting. The program is also 

augmented to require surface examination of dissimilar metal welds of vent line bellows in 

accordance with examination Category E-F, as specified in the 1992 Edition of the ASME Code, 

Section XI, Subsection IWE. If surface examination is not possible, appropriate 10 CFR Part 50

Appendix J test may be conducted for pressure boundary components.

Evaluation and Technical Basis

1. Scope of Program: The scope of this program addresses the components of steel 

containments and steel liners of concrete containments specified in Subsection IWE-1000 

as augmented by LR-ISG-2006-01. 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 moisture barriers, containment pressure-retaining bolting, 

and metal containment surface areas, including welds and base metal. The concrete 

 

20 Refer to the GALL Report, Chapter I, for applicability of other editions of the ASME Code, Section XI.
NUREG-1801, Rev. 2 XI S1-2 December 2010

portions of containments are inspected in accordance with Subsection IWL. Subsection IWE 

requires examination of coatings that are intended to prevent corrosion. XI.S8 is a protective 

coating monitoring and maintenance program that is recommended to ensure ECCS 

operability, whether or not the AMP XI.S8 is credited in AMP XI.S1.

Subsection IWE exempts the following from examination:

(a) Components that are outside the boundaries of the containment, as defined in the 

plant-specific design specification;

(b) Embedded or inaccessible portions of containment components that met the 

requirements of the original construction code of record;

(c) Components that become embedded or inaccessible as a result of containment 

structure (i.e., steel containments [Class MC] and steel liners of concrete 

containments [Class CC]) repair or replacement, provided the requirements of IWE1232 and IWE-5220 are met; and

(d) 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).

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: The ASME Code Section XI, Subsection IWE, is a condition monitoring 

program. The program is augmented to include preventive actions that ensure that moisture 

levels associated with an accelerated corrosion rate do not exist in the exterior portion of the 

BWR Mark I steel containment drywell shell. The actions consist of ensuring that the sand 

pocket area drains and/or the refueling seal drains are clear. The program is also 

augmented to require that the selection of bolting material installation torque or tension and 

the use of lubricants and sealants are in accordance with the guidelines of EPRI NP-5769, 

EPRI TR-104213, and the additional recommendations of NUREG-1339 to prevent or 

mitigate degradation and failure of structural bolting. If the structural bolting consists of 

ASTM A325, ASTM F1852, and/or ASTM A490 bolts, the preventive actions for storage, 

lubricants, and stress corrosion cracking potential discussed in Section 2 of RCSC 

(Research Council for Structural Connections) publication “Specification for Structural Joints 

Using ASTM A325 or A490 Bolts,” need to be considered.

3. Parameters Monitored or Inspected: Table IWE-2500-1 references the applicable sections 

in IWE-2300 and IWE-3500 that identify the parameters examined or monitored. Non-coated 

surfaces are examined for evidence of cracking, discoloration, wear, pitting, excessive 

corrosion, arc strikes, gouges, surface discontinuities, dents, and other signs of surface 

irregularities. Painted or coated surfaces are examined for evidence of flaking, blistering, 

peeling, discoloration, and other signs of distress. Stainless steel penetration sleeves, 

dissimilar metal welds, bellows, and steel components that are subject to cyclic loading but 

have no current licensing basis fatigue analysis are monitored for cracking. The moisture 

barriers are examined for wear, damage, erosion, tear, surface cracks, or other defects that 

permit intrusion of moisture in the inaccessible areas of the pressure retaining surfaces of 
December 2010 XI S1-3 NUREG-1801, Rev. 2

the metal containment shell or liner. Pressure-retaining bolting is examined for loosening 

and material conditions that cause the bolted connection to affect either containment leaktightness or structural integrity.

As recommended in LR-ISG-2006-01, license renewal applicants with BWR Mark I steel 

containments should monitor the sand pocket area drains and/or the refueling seal drains for 

water leakage. The licensees should ensure the drains are clear to prevent moisture levels 

associated with accelerated corrosion rates in the exterior portion of the drywell shell.

4. Detection of Aging Effects: The examination methods, frequency, and scope of 

examination specified in 10 CFR 50.55a and Subsection IWE ensure that aging effects are 

detected before they compromise the design-basis requirements. IWE-2500-1 and the 

requirements of 10 CFR 50.55a provide information regarding the examination categories, 

parts examined, and examination methods to be used to detect aging.

As indicated in IWE-2400, inservice examinations are performed in accordance with one of 

two inspection programs, A or B, on a specified schedule. Under Inspection Program A, 

there 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. 

After 40 years of operation, any future examinations are 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 was 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 as specified in 

Table IWE-2500-1 and the requirements of 10 CFR 50.55a. The acceptability of 

inaccessible areas of the BWR Mark I steel containment drywell is evaluated when 

conditions exist in the adjacent accessible areas that could indicate the presence of 

moisture or could result in degradation to such inaccessible areas. 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. 

The requirements of ASME Section XI, Subsection IWE and 10 CFR 50.55a are augmented 

to require surface examination, in addition to visual examination, to detect cracking in 

stainless steel penetration sleeves, dissimilar metal welds, bellows, and steel components 

that are subject to cyclic loading but have no current licensing basis fatigue analysis. Where 

feasible, Appendix J tests (AMP XI.S4) may be performed in lieu of the surface examination. 

5. Monitoring and Trending: With the exception of inaccessible areas, all surfaces are 

monitored by virtue of the examination requirements on a scheduled basis. 

IWE-2420 specifies that: 
NUREG-1801, Rev. 2 XI S1-4 December 2010

(a) The sequence of component examinations established during the first inspection 

interval shall be repeated.

(b) When examination results require evaluation of flaws or areas of degradation in 

accordance with IWE-3000, and the component is acceptable for continued service, 

the areas containing such flaws or areas of degradation shall be reexamined during 

the next inspection period listed in the schedule of the inspection program of IWE2411 or IWE-2412, in accordance with Table IWE-2500-1, Examination Category EC.

(c) When the reexaminations required by IWE-2420(b) reveal that the flaws or areas of 

degradation remain essentially unchanged for the next inspection period, these 

areas no longer require augmented examination in accordance with Table IWE2500-1 and the regular inspection schedule is continued. 

Applicants for license renewal for plants with BWR Mark I containment should augment IWE 

monitoring and trending requirements to address inaccessible areas of the drywell. The 

applicant should consider the following recommended actions based on plant-specific 

operating experience.

(a) Develop a corrosion rate that can be inferred from past ultrasonic testing (UT) 

examinations or establish a corrosion rate using representative samples in similar 

operating conditions, materials, and environments. If degradation has occurred, 

provide a technical basis using the developed or established corrosion rate to 

demonstrate that the drywell shell will have sufficient wall thickness to perform its 

intended function through the period of extended operation.

(b) Demonstrate that UT measurements performed in response to U.S. Nuclear 

Regulatory Commission (NRC) Generic Letter (GL) 87-05 did not show degradation 

inconsistent with the developed or established corrosion rate.

6. Acceptance Criteria: IWE-3000 provides acceptance standards for components of steel 

containments and liners of concrete containments. IWE-3410 refers to criteria to evaluate 

the acceptability of the containment components for service following the preservice 

examination and each inservice examination. 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 locally exceeding 10% of the nominal 

containment wall thickness or material loss that is projected to locally exceed 10% of the 

nominal containment wall thickness before the next examination are documented. Such 

areas are corrected by repair or replacement in accordance with IWE-3122 or accepted by 

engineering evaluation. Cracking of stainless steel penetration sleeves, dissimilar metal 

welds, bellows, and steel components that are subject to cyclic loading but have no current 

licensing basis fatigue analysis is corrected by repair or replacement or accepted by 

engineering evaluation.

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 

IWE-3500 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 
December 2010 XI S1-5 NUREG-1801, Rev. 2

containment. 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 for GALL, the staff finds the requirements of 10 CFR Part 50, 

Appendix B, acceptable to address the corrective actions.

If moisture has been detected or suspected in the inaccessible area on the exterior of the 

Mark I containment drywell shell or the source of moisture cannot be determined 

subsequent to root cause analysis, then: 

(a) Include in the scope of license renewal any components that are identified as a 

source of moisture, if applicable, such as the refueling seal or cracks in the stainless 

liners of the refueling cavity pools walls, and perform aging management review.

(b) Identify surfaces requiring examination by implementing augmented inspections for 

the period of extended operation in accordance with Subsection IWE-1240, as 

identified in Table IWE-2500-1, Examination Category E-C.

(c) Use examination methods that are in accordance with Subsection IWE-2500.

(d) Demonstrate, through use of augmented inspections performed in accordance with 

Subsection IWE, that corrosion is not occurring or that corrosion is progressing so 

slowly that the age-related degradation will not jeopardize the intended function of 

the drywell shell through the period of extended operation.

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 IWE-3500. As discussed in the Appendix for GALL, 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 for GALL, 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 NRC. NRC 

Information Notice (IN) 86-99, IN 88-82, IN 89-79, IN 2004-09, and NUREG-1522 described 

occurrences of corrosion in steel containment shells. NRC GL 87-05 addressed the potential 

for corrosion of BWR Mark I steel drywells in the “sand pocket region.” 
NUREG-1801, Rev. 2 XI S1-6 December 2010

NRC IN 97-10 identified specific locations where concrete containments are susceptible to 

liner plate corrosion; IN 92-20 described an instance of containment bellows cracking, 

resulting in loss of leak tightness. More recently, IN 2006-01 described a through-wall 

cracking and its probable cause in the torus of a BWR Mark I containment. The cracking 

was identified by the licensee in the heat-affected zone at the high pressure cooling injection 

(HPCI) turbine exhaust pipe torus penetration. 

The licensee concluded that the cracking was most likely initiated by cyclic loading due to 

condensation oscillation during HPCI operation. These condensation oscillations induced on 

the torus shell may have been excessive due to a lack of an HPCI turbine exhaust pipe 

sparger that many licensees have installed. Other operating experience indicates that 

foreign objects embedded in concrete have caused through-wall corrosion of the liner plate 

at a few plants with reinforced concrete containments. 

The program is to consider the liner plate and containment shell corrosion and cracking 

concerns described in these generic communications. Implementation of the ISI 

requirements of Subsection IWE, in accordance with 10 CFR 50.55a, augmented to 

consider operating experience, and as recommended in LR-ISG-2006-01, is a necessary 

element of aging management for steel components of steel and concrete containments 

through the period of extended operation. 

Degradation of threaded bolting and fasteners in closures for the reactor coolant pressure 

boundary has occurred from boric acid corrosion, stress corrosion cracking (SCC), and 

fatigue loading (NRC IE Bulletin 82-02, NRC GL 91-17). SCC has occurred in high strength 

bolts used for nuclear steam supply system component supports (EPRI NP-5769). The 

augmented ASME Section XI, Subsection IWE, incorporating recommendations 

documented in EPRI NP-5769 and TR-104213, is necessary to ensure containment bolting 

integrity. 

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

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, 2009.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2009.

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components,

Subsection IWA, General Requirements, The ASME Boiler and Pressure Vessel Code, 2004 

edition as incorporated by reference in 10 CFR 50.55a, 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, The ASME Boiler and Pressure Vessel Code, 2004 edition as incorporated by 

reference in 10 CFR 50.55a, The American Society of Mechanical Engineers, New York, 

NY.
December 2010 XI S1-7 NUREG-1801, Rev. 2

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, The ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 

50.55a, 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, The ASME Boiler and Pressure Vessel Code, 2004 

edition as incorporated by reference in 10 CFR 50.55a, 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, The ASME Boiler and Pressure Vessel Code, 2004 edition as incorporated by 

reference in 10 CFR 50.55a, The American Society of Mechanical Engineers, New York, 

NY.

EPRI NP-5769, Degradation and Failure of Bolting in Nuclear Power Plants, Volumes 1 and 2, 

Electric Power Research Institute, April 1988. 

EPRI NP-5067, Good Bolting Practices, A Reference Manual for Nuclear Power Plant 

Maintenance Personnel, Volume 1: Large Bolt Manual, 1987; Volume 2: Small Bolts and 

Threaded Fasteners, Electric Power Research Institute, 1990.

EPRI TR-104213, Bolted Joint Maintenance & Application Guide, Electric Power Research 

Institute, December 1995.

RCSC (Research Council on Structural Connections): Specification for Structural Joints Using 

ASTM A325 or A490 Bolts, 2004.

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.

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 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 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. 
NUREG-1801, Rev. 2 XI S1-8 December 2010

NRC Information Notice 92-20, Inadequate Local Leak Rate Testing, U.S. Nuclear Regulatory 

Commission, March 3, 1992.

NRC Information Notice 97-10, Liner Plate Corrosion in Concrete Containment, U.S. Nuclear 

Regulatory Commission, March 13, 1997.

NRC Information Notice 2004-09, Corrosion of Steel Containment and Containment Liner, U.S. 

Nuclear Regulatory Commission, April 27, 2004.

NRC Information Notice 2006-01, Torus Cracking in a BWR Mark I Containment, U.S. Nuclear 

Regulatory Commission, January 12, 2006. 

NRC Morning Report, Failure of Safety/Relief Valve Tee-Quencher Support Bolts, March 14, 

2005. (ADAMS Accession Number ML050730347)

NUREG-1339, Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear 

Power Plants, U.S. Nuclear Regulatory Commission, June 1990.

NUREG-1522, Assessment of Inservice Conditions of Safety-Related Nuclear Plant Structures, 

June 1995. 

Staff Position and Rationale for the Final License Renewal Interim Staff Guidance LR-ISG-2006-

01, Plant-Specific Aging Management Program for Inaccessible Areas of Boiling Water 

Reactor (BWR) Mark I Steel Containments Drywell Shell, Nuclear Regulatory Commission, 

November 16, 2006.
December 2010 XI S2-1 NUREG-1801, Rev. 2

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 the 200421

The primary inspection method specified in IWL-2500 is visual examination, supplemented by 

testing. 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. The quantity of free water contained in the 

anchorage end cap and any free water that drains from tendons during the examination is 

documented. Samples of free water are analyzed for pH. 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. 

edition of the ASME Code, Section XI, 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 2004 edition of the Code specifies augmented examination requirements following posttensioning system repair/replacement activities. The post-tensioning system repair/replacement 

activities are to be in accordance with the requirements of the 2004 edition of the Code.

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. The program also includes testing of the tendon corrosion protection 

medium and the pH of free water. 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. Subsection IWE is evaluated in AMP XI.S1.

2. Preventive Action: ASME Code Section XI, Subsection IWL is a condition monitoring 

program. However, the program includes actions to prevent or minimize corrosion of the 

prestressing tendons by maintaining corrosion protection medium chemistry within 

acceptable limits specified in IWL.

 

21 Refer to the GALL Report, Chapter I, for applicability of other editions of the ASME Code, Section XI.
NUREG-1801, Rev. 2 XI S2-2 December 2010

3. Parameters Monitored or Inspected: Table IWL-2500-1 specifies two categories for 

examination of concrete surfaces: Category L-A for all accessible concrete surfaces and 

Category L-B for concrete surfaces surrounding anchorages of tendons selected for testing 

in accordance with IWL-2521. 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 201.1R and ACI 349.3R. Table IWL-2500-1 also 

specifies Category L-B for test and examination requirements for unbonded post tensioning 

systems. The number of tendons selected for examination is in accordance with Table IWL2521-1. Additional augmented examination requirements for post-tensioning system 

repair/replacement activities are to be in accordance with Table IWL-2521-2. 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. The tendon corrosion protection medium is tested by analysis for alkalinity, 

water content, and soluble ion concentrations. The pH of free water samples is analyzed.

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 of concrete and unbonded posttensioning systems are required at 1, 3, and 5 years following the initial structural integrity 

test. Thereafter, inspections are performed at 5-year intervals. For sites with multiple 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 during each inspection. 

The tendons to be examined during an inspection are selected on a random basis. 

Regarding detection methods for aging effects, all accessible concrete surfaces receive 

General Visual examination (as defined by the ASME Code). Selected areas, such as those 

that indicate suspect conditions and concrete surface areas surrounding tendon anchorages 

(Category L-B), receive a more rigorous Detailed Visual examination (as defined by the 

ASME Code). 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. Examination of corrosion protection medium and free 

water are tested for each examined tendon as specified in Table IWL-2525-1.

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. Corrosion protection medium chemistry and free water pH are monitored for 

each examined tendon. 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.
December 2010 XI S2-3 NUREG-1801, Rev. 2

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 and 

ACI 349.3R for identification of concrete degradation. IWL-2320 requires that the 

Responsible Engineer be a registered professional engineer experienced in evaluating 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 also may 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. Free 

water in the tendon anchorage areas is not acceptable, as specified in IWL-3221.3. If free 

water is found, the recommendations in Table IWL-2525-1 are followed. 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 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 IWL4000. This includes requirements for the concrete repair, repair of reinforcing steel, and 

repair of the post-tensioning system. As discussed in the Appendix for GALL, 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 for GALL, 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 for GALL, 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, the prestressing tendon inspections were 

performed in accordance with the guidance provided in Regulatory Guide 1.35. Operating 

experience pertaining to degradation of reinforced concrete in concrete containments was 
NUREG-1801, Rev. 2 XI S2-4 December 2010

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). 

NUREG-1522 described instances of cracked, spalled, and degraded concrete for 

reinforced and prestressed concrete containments. The NUREG also described cracked 

anchor heads for the prestressing tendons at three prestressed concrete containments. 

NRC Information Notice 99-10 described occurrences of degradation in prestressing 

systems. The program is to consider the degradation concerns described in these generic 

communications. Implementation of Subsection IWL, in accordance with 10 CFR 50.55a, is 

a necessary element of aging management for concrete containments through 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, 2009.

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, 2009.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2009.

ACI Standard 201.1R, Guide for Making a Condition Survey of Concrete in Service, American 

Concrete Institute.

ACI Standard 349.3R, Evaluation of Existing Nuclear Safety-Related Concrete Structures,

American Concrete Institute, 2002. 

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components,

Subsection IWA, General Requirements, The ASME Boiler and Pressure Vessel Code, 2004 

edition as approved in 10 CFR 50.55a, 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, The ASME Boiler and Pressure Vessel Code, 2004 

edition as approved in 10 CFR 50.55a, 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, The ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 

CFR 50.55a, 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.

NRC Regulatory Guide 1.35.1, Determining Prestressing Forces for Inspection of Prestressed 

Concrete Containments, U.S. Nuclear Regulatory Commission, July 1990.
December 2010 XI S2-5 NUREG-1801, Rev. 2

NRC Regulatory Guide 1.35, Inservice Inspection of Ungrouted Tendons in Prestressed Concrete 

Containments, U.S. Nuclear Regulatory Commission, July 1990

NUREG-1522, Assessment of Inservice Condition of Safety-Related Nuclear Power Plant 

Structures, June 1995.
NUREG-1801, Rev. 2 XI S2-6 December 2010

 
December 2010 XI S3-1 NUREG-1801, Rev. 2

XI.S3 ASME SECTION XI, SUBSECTION IWF

Program Description 

10 CFR 50.55a imposes the inservice inspection requirements of the American Society of 

Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section XI, for Class 1, 2, 3, 

and metal containment (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 2004 edition22

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.

of the ASME Code 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 component supports for 

license renewal. 

The requirements of subsection IWF are augmented to include monitoring of high-strength 

structural bolting (actual measured yield strength greater than or equal to 150 ksi or 1,034 MPa) 

for cracking. The program is augmented to incorporate recommendations delineated in NUREG1339 and industry recommendations delineated in the Electric Power Research Institute (EPRI) 

NP-5769, NP-5067, and TR-104213 for high-strength structural bolting, if applicable. These 

recommendations emphasize proper selection of bolting material, lubricants, and installation 

torque or tension to prevent or minimize loss of bolting preload and cracking of high-strength 

bolting.

Evaluation and Technical Basis

1. Scope of Program: This program addresses supports for ASME Class 1, 2, and 3 piping 

and components supports that are not exempt from examination in accordance with IWF -

1230 and MC supports. The scope of the program includes support members, structural

bolting, high strength structural bolting, support anchorage to the building structure, 

accessible sliding surfaces, constant and variable load spring hangers, guides, stops, and 

vibration isolation elements.

2. Preventive Action: Selection of bolting material and the use of lubricants and sealants is in 

accordance with the guidelines of EPRI NP-5769, EPRI TR-104213, and the additional 

recommendations of NUREG-1339 to prevent or mitigate degradation and failure of safetyrelated bolting. Operating experience and laboratory examinations show that the use of 

molybdenum disulfide (MoS2) as a lubricant is a potential contributor to stress corrosion 

cracking (SCC), especially when applied to high strength bolting. Thus, molybdenum 

disulfide and other lubricants containing sulfur should not be used. Preventive measures 

also include using bolting material that has an actual measured yield strength less than 

 

22 Refer to the GALL Report, Chapter I, for applicability of other editions of the ASME Code, Section XI.
NUREG-1801, Rev. 2 XI S3-2 December 2010

150 ksi or 1,034 MPa. Structural bolting replacement and maintenance activities include 

appropriate preload and proper tightening (torque or tension) as recommended in EPRI 

documents, American Society for Testing of Materials (ASTM) standards, American Institute 

of Steel Construction (AISC) Specifications, as applicable. If the structural bolting consists of 

ASTM A325, ASTM F1852, and/or ASTM A490 bolts, the preventive actions for storage, 

lubricants, and stress corrosion cracking potential discussed in Section 2 of RCSC 

(Research Council for Structural Connections) publication “Specification for Structural Joints 

Using ASTM A325 or A490 Bolts” need to be used. 

3. Parameters Monitored or Inspected: The parameters monitored or inspected include 

corrosion; deformation; misalignment of supports; missing, detached, or loosened support 

items; improper clearances of guides and stops; and improper hot or cold settings of spring 

supports and constant load supports. Accessible areas of sliding surfaces are monitored for 

debris, dirt, or indications of excessive loss of material due to wear that could prevent or 

restrict sliding as intended in the design basis of the support. Elastomeric vibration isolation 

elements are monitored for cracking, loss of material, and hardening. Structural bolts are 

monitored for corrosion and loss of integrity of bolted connections due to self loosening and 

material conditions that can affect structural integrity. High-strength structural bolting (actual 

measured yield strength greater than or equal to 150 ksi or 1,034 MPa) susceptible to SCC 

should be monitored for SCC. 

4. Detection of Aging Effects: The program requires that a sample of ASME Class 1, 2, and 

3 component supports that are not exempt from examination and 100% of MC component

supports be examined as specified in Table IWF-2500-1. The sample size examined for 

ASME Class 1, 2, and 3 component supports is as specified in Table IWF-2500-1. The 

extent, frequency, and examination methods are designed to detect, evaluate, or repair agerelated degradation before there is a loss of component support intended function. The VT-3 

examination method specified by the program can reveal loss of material due to corrosion 

and wear, verification of clearances, settings, physical displacements, loose or missing 

parts, debris or dirt in accessible areas of the sliding surfaces, or loss of integrity at bolted 

connections. The VT-3 examination can also detect loss of material and cracking of 

elastomeric vibration isolation elements. VT-3 examination of elastomeric vibration isolation 

elements should be supplemented by feel to detect hardening if the vibration isolation 

function is suspect. IWF-3200 specifies that visual examinations that detect surface flaws 

which exceed acceptance criteria may be supplemented by either surface or volumetric 

examinations to determine the character of the flaw. 

For high strength structural bolting (actual measured yield strength greater than or equal to 

150 ksi or 1,034 MPa) in sizes greater than 1 inch nominal diameter, volumetric examination 

comparable to that of ASME Code Section XI, Table IWB-2500-1, Examination Category BG-1 should be performed to detect cracking in addition to the VT-3 examination. This 

volumetric examination may be waived with adequate plant-specific justification. Other 

structural bolting (ASTM A-325, ASTM F1852, and ASTM A490 bolts) and anchor bolts are 

monitored for loss of material, loose or missing nuts, and cracking of concrete around the 

anchor bolts. 

5. Monitoring and Trending: The ASME Class 1, 2, 3, and MC component supports are 

examined periodically, as specified in Table IWF-2500-1. As required by IWF-2420(a), the 

sequence of component support examinations established during the first inspection interval 

is repeated during each successive inspection interval, to the extent practical. Component 

supports whose examinations do not reveal unacceptable degradations are accepted for 
December 2010 XI S3-3 NUREG-1801, Rev. 2

continued service. Verified changes of conditions from prior examination are recorded in 

accordance with IWA-6230. Component supports whose examinations reveal unacceptable 

conditions and are accepted for continued service by corrective measures or repair/ 

replacement activity are reexamined during the next inspection period. When the 

reexamined component support no longer requires additional corrective measures during 

the next inspection period, the inspection schedule may revert to its regularly scheduled 

inspection. Examinations that reveal indications which exceed the acceptance standards 

and require corrective measures are extended to include additional examinations in 

accordance with IWF-2430. 

6. Acceptance Criteria: The acceptance standards for visual examination are specified in 

IWF-3400. IWF-3410(a) identifies the following conditions as unacceptable:

(a) Deformations or structural degradations of fasteners, springs, clamps, or other 

support items;

(b) Missing, detached, or loosened support items, including bolts and nuts;

(c) Arc strikes, weld spatter, paint, scoring, roughness, or general corrosion on close 

tolerance machined or sliding surfaces;

(d) Improper hot or cold positions of spring supports and constant load supports;

(e) Misalignment of supports; and

(f) Improper clearances of guides and stops.

Other unacceptable conditions include:

(a) Loss of material due to corrosion or wear, which reduces the load bearing capacity of 

the component support;

(b) Debris, dirt, or excessive wear that could prevent or restrict sliding of the sliding 

surfaces as intended in the design basis of the support;

(c) Cracked or sheared bolts, including high strength bolts, and anchors; and

(d) Loss of material, cracking, and hardening of elastomeric vibration isolation elements 

that could reduce the vibration isolation function.

The above conditions may be accepted provided the technical basis for their acceptance is 

documented.

7. Corrective Actions: 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). In 

accordance with IWF-3122, supports containing unacceptable conditions are evaluated or 

tested or corrected before returning to service. Corrective actions are delineated in IWF3122.2. IWF-3122.3 provides an alternative for evaluation or testing to substantiate 

structural integrity and/or functionality. As discussed in the Appendix for GALL, the staff 
NUREG-1801, Rev. 2 XI S3-4 December 2010

finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective 

actions.

8. Confirmation Process: As discussed in the Appendix for GALL, 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 for GALL, 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 in managing the 

aging of the in-scope component supports through the period of extended operation. 

Degradation of threaded bolting and fasteners 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). 

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2009.

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, The ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 

50.55a, 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, The ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 

50.55a, 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, The ASME Boiler and Pressure Vessel Code, 2004 edition as approved in 10 CFR 

50.55a, 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, The ASME Boiler and Pressure Vessel Code, 2004 

edition as approved in 10 CFR 50.55a, 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 Light-
December 2010 XI S3-5 NUREG-1801, Rev. 2

Water Cooled Power Plants, The ASME Boiler and Pressure Vessel Code, 2004 edition as 

approved in 10 CFR 50.55a, The American Society of Mechanical Engineers, New York, NY.

EPRI NP-5067, Good Bolting Practices, A Reference Manual for Nuclear Power Plant 

Maintenance Personnel, Volume 1: Large Bolt Manual, 1987; Volume 2: Small Bolts and 

Threaded Fasteners, Electric Power Research Institute, 1990.

EPRI NP-5769, Degradation and Failure of Bolting in Nuclear Power Plants, Volumes 1 and 2, 

Electric Power Research Institute, April 1988. 

EPRI TR-104213, Bolted Joint Maintenance & Application Guide, Electric Power Research 

Institute, December 1995.

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 Morning Report, Failure of Safety/Relief Valve Tee-Quencher Support Bolts, March 14, 

2005. (ADAMS Accession Number ML050730347)

NUREG-1339, Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear 

Power Plants, U.S. Nuclear Regulatory Commission, June 1990.

RCSC (Research Council on Structural Connections): Specification for Structural Joints Using 

ASTM A325 or A490 Bolts, Chicago, 2004.

December 2010 XI S4-1 NUREG-1801, Rev. 2

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 these containments or systems and components penetrating these 

containments does not exceed allowable leakage rates specified in the technical specifications 

and (b) integrity of the containment structure is maintained during its service life.”

Appendix J provides two options, Option A and Option B, either of which can be chosen to meet 

the requirements of a containment leakage rate test (LRT) program. Option A is prescriptive 

with all testing performed on specified, uniform periodic intervals. Option B is a performancebased approach. Some of the differences between these options are discussed below. More 

detailed information for Option B is provided in the Nuclear Regulatory Commission (NRC) 

Regulatory Guide (RG) 1.16323

Appendix J requires a general inspection of the accessible interior and exterior surfaces of the 

containment structure and components be performed prior to any Type A test. General Visual 

examinations performed in accordance with the ASME Section XI, Subsection IWE (AMP XI.S1) 

or ASME Section XI, Subsection IWL (AMP XI.S2) program are an acceptable substitute. The 

purpose of the inspection is to uncover any evidence of structural deterioration that may affect 

the containment structural integrity or leak-tightness. If there is evidence of structural 

deterioration, the Type A test is not performed until corrective action is taken in accordance with 

the repair/replacement procedures.

and NEI 94-01 as approved by the NRC Final Safety Evaluation 

for the Nuclear Energy Institute (NEI) Topical Report (TR) 94-01, Revision 2.Three types of 

tests are performed under either Option A or Option B. Type A tests are performed to determine 

the overall primary containment integrated leakage rate at the loss of coolant accident peak 

containment pressure. Type B tests are intended to detect local leaks and to measure leakage 

across each pressure-containing or leakage-limiting boundary of containment penetrations. 

Type C tests are intended to detect local leaks and to measure leakage across containment 

isolation valves installed in containment penetrations or lines penetrating containment. If Type C 

tests are not performed under this program, they could be included under an ASME Code, 

Section XI, Inservice Test Program leakage testing for systems containing the isolation valves.

Evaluation and Technical Basis

1. Scope of Program: The scope of the containment LRT program includes all containment 

boundary pressure-retaining components. 

2. Preventive Action: The containment LRT program is a performance monitoring program 

that includes no preventive actions.

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 leakage 

rate of the containment pressure boundary components, including seals and gaskets. While 

the calculation of leakage rates and satisfactory performance of containment leakage rate 

 

23 RG 1.163 Rev. 0 or the latest Revision.
NUREG-1801, Rev. 2 XI S4-2 December 2010

testing 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 ASME Section XI, 

Subsection IWE (AMP XI.S1) and ASME Section XI, Subsection IWL (AMP XI.S2).

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 adjusted on the basis of acceptable performance in meeting 

leakage limits in prior tests. Additional details for implementing Option B are provided in 

NRC RG 1.163 and NEI 94-01.

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. 

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 are taken. As discussed in the Appendix for GALL, 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 for GALL, 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 are assessed under 

10 CFR 50.72 and 10 CFR 50.73. As discussed in the Appendix for GALL, 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, in 

conjunction with the containment inservice inspection 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 B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

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, 2009.
December 2010 XI S4-3 NUREG-1801, Rev. 2

10 CFR 50.72, Immediate Notification Requirements for Operating Nuclear Power Reactors,

Office of the Federal Register, National Archives and Records Administration, 2009.

10 CFR 50.73, Licensee Event Report System, Office of the Federal Register, National Archives 

and Records Administration, 2009.

Final Safety Evaluation for ‘Nuclear Energy Institute (NEI) Topical Report (TR) 94-01, Revision 

2, Industry Guideline for Implementing Performance-Based Option of 10 CFR, Part 50, 

Appendix J,’ and ‘Electric Power Research Institute (EPRI) Report No. 1009325, Revision 2, 

Risk Impact Assessment of Extended Integrated Leak Rate Testing Intervals, August 2007,’ 

June 25, 2008.

NEI 94-01, Rev. 2-A, Industry Guideline for Implementing Performance-Based Option of 10 CFR 

Part 50 Appendix J, Nuclear Energy Institute, August 2007.

NRC Regulatory Guide 1.163, Rev. 0, Performance-Based Containment Leak-Test Program, 

U.S. Nuclear Regulatory Commission, September 1995.

December 2010 XI S5-1 NUREG-1801, Rev. 2

XI.S5 MASONRY WALLS 

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 (a) the identification of masonry walls in 

close proximity to or having attachments from safety-related systems or components and (b) 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 (a) deterioration 

of the masonry walls (e.g., new cracks not considered in the reevaluation), (b) physical plant 

changes such as installation of new safety-related systems or components in close proximity to 

masonry walls, or (c) reclassification of systems or components from non-safety-related to 

safety-related, provided appropriate evaluation is performed to account for such occurrences. 

Important elements in the evaluation of many masonry walls during the NRC IEB 80-11 program 

included (a) installation of steel edge supports to provide a sound technical basis for boundary 

conditions used in seismic analysis and (b) installation of steel bracing to ensure stability or 

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 steel edge supports and steel 

bracings are considered component supports and aging effects are managed by the Structures 

Monitoring program (AMP XI.S6). 

The program requires periodic visual inspection of masonry walls in the scope of license 

renewal to detect loss of material and cracking of masonry units and mortar. The aging effects 

that could impact masonry wall intended function or potentially invalidate its evaluation basis are 

entered in the corrective action process for further analysis, repair, or replacement.

Since the issuance of NRC IEB 80-11 and NRC IN 87-67, the NRC promulgated 10 CFR 50.65, 

the Maintenance Rule. For license renewal, masonry walls may be inspected as part of the 

“Structures Monitoring Program” (AMP XI.S6) conducted for the Maintenance Rule, provided the 

10 attributes described below are incorporated in AMP XI.S6. The aging effects on masonry 

walls that are considered fire barriers also are managed by AMP XI.M26, Fire Protection. 

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. The aging effects on masonry walls that are 

considered fire barriers also are managed by AMP XI.M26, Fire Protection, as well as being 

managed by this program. 

2. Preventive Action: This is a condition monitoring program and no specific preventive 

actions are required.

3. Parameters Monitored or Inspected: The primary parameters monitored are potential 

shrinkage and/or separation and cracking of masonry walls and gaps between the supports 

and masonry walls that could impact the intended function or potentially invalidate its 

evaluation basis.
NUREG-1801, Rev. 2 XI S5-2 December 2010

4. Detection of Aging Effects: Visual examination of the masonry walls by qualified 

inspection personnel is sufficient. In general, masonry walls should be inspected every 5 

years, with provisions for more frequent inspections in areas where significant loss of 

material or cracking is observed to ensure there is no loss of intended function between 

inspections. However, masonry walls that are fire barriers are visually inspected in 

accordance with AMP XI.M26.

5. Monitoring and Trending: Trending is not required. Condition monitoring for evidence of 

shrinkage and/or separation and cracking is achieved by periodic examination. Degradation 

detected from monitoring is evaluated.

6. Acceptance Criteria: For each masonry wall, the extent of observed shrinkage and/or 

separation and cracking of masonry may not invalidate the evaluation basis or impact the 

wall’s intended function. However, further evaluation is conducted if the extent of cracking 

and loss of material is sufficient to impact the intended function of the wall or invalidate its 

evaluation basis.

7. Corrective Actions: A corrective action option is to develop a new analysis or evaluation 

basis that accounts for the degraded condition of the wall (i.e., acceptance by further 

evaluation). Other alternatives include repair or replacing the degraded wall. As discussed in 

the Appendix for GALL, 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 for GALL, 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 for GALL, 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,

NRC Generic Letter 87-02, 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. NUREG-1522 documents instances of observed cracks and 

other deterioration of masonry-wall joints at nuclear power plants. Whether conducted as a 

stand-alone program or as a part of structures monitoring, 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 Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

10 CFR 50.48, Fire Protection, Office of the Federal Register, National Archives and Records 

Administration, 2009. 
December 2010 XI S5-3 NUREG-1801, Rev. 2

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, 2009.

10 CFR 54.4, Scope, Office of the Federal Register, National Archives and Records 

Administration, 2009. 

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.

NRC Regulatory Guide 1.160, Rev. 2, Monitoring the Effectiveness of Maintenance at Nuclear 

Power Plants, U.S. Nuclear Regulatory Commission, March 1997. 

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-1522, Assessment of Inservice Condition of Safety-Related Nuclear Power Plant 

Structures, June 1995.

December 2010 XI S6-1 NUREG-1801, Rev. 2

XI.S6 STRUCTURES MONITORING 

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. 

The structures monitoring program consists of periodic visual inspections by personnel qualified 

to monitor structures and components for applicable aging effects, such as those described in 

the American Concrete Institute Standards (ACI) 349.3R, ACI 201.1R, and American National 

Standards Institute/American Society of Civil Engineers Standard (ANSI/ASCE) 11. Visual 

inspections should be supplemented with volumetric or surface examinations to detect stress 

corrosion cracking (SCC) in high strength (actual measured yield strength greater than or equal 

to 150 kilo-pound per square inch [ksi] or greater than or equal to 1,034 MPa) structural bolts 

greater than 1 inch (25 mm) in diameter. Identified aging effects are evaluated by qualified 

personnel using criteria derived from industry codes and standards contained in the plant 

current licensing bases, including ACI 349.3R, ACI 318, ANSI/ASCE 11, and the American 

Institute of Steel Construction (AISC) specifications, as applicable. 

The program includes preventive actions delineated in NUREG-1339 and in Electric Power 

Research Institute (EPRI) NP-5769, NP-5067, and TR-104213 to ensure structural bolting 

integrity, if applicable. 

The program also includes periodic sampling and testing of ground water and the need to 

assess the impact of any changes in its chemistry on below grade concrete structures. 

If protective coatings are relied upon to manage the effects of aging for any structures included 

in the scope of this aging management program (AMP), the structures monitoring program is to 

address protective coating monitoring and maintenance.

Evaluation and Technical Basis

1. Scope of Program: The scope of the program includes all structures, structural 

components, component supports, and structural commodities in the scope of license 

renewal that are not covered by other structural AMPs (i.e., “ASME Section XI, Subsection 

IWE” (AMP XI.S1); “ASME Section XI, Subsection IWL” (AMP XI.S2); “ASME Section XI, 

Subsection IWF” (AMP XI.S3); “Masonry Walls” (AMP XI.S5); and NRC RG 1.127, 

“Inspection of Water-Control Structures Associated with Nuclear Power Plants” (AMP XI.S7). 

Examples of structures, structural components, and commodities in the scope of the 

program are concrete and steel structures, structural bolting, anchor bolts and embedments, 

component support members, pipe whip restraints and jet impingement shields, 

transmission towers, panels and other enclosures, racks, sliding surfaces, sump and pool 

liners, electrical cable trays and conduits, trash racks associated with water control 

structures, electrical duct banks, manholes, doors, penetration seals, and tube tracks. The 

applicant is to specify other structures or components that are in the scope of its structures 

monitoring program. The scope of this program includes periodic sampling and testing of 

ground water and may include inspection of masonry walls and water-control structures 
NUREG-1801, Rev. 2 XI S6-2 December 2010

provided all the attributes of “Masonry Walls” (AMP XI.S5) and NRC RG 1.127, “Inspection 

of Water-Control Structures Associated with Nuclear Power Plants” (AMP XI.S7) are 

incorporated in the attributes of this program. 

2. Preventive Action: The structures monitoring program is a condition monitoring program. 

The program should include preventive actions delineated in NUREG-1339 and in EPRI NP5769, NP-5067, and TR-104213 to ensure structural bolting integrity, if applicable. These 

actions emphasize proper selection of bolting material, lubricants, and installation torque or 

tension to prevent or minimize loss of bolting preload and cracking of high strength bolting. If 

the structural bolting consists of ASTM A325, ASTM F1852, and/or ASTM A490 bolts, the 

preventive actions for storage, lubricants, and stress corrosion cracking potential discussed 

in Section 2 of RCSC (Research Council for Structural Connections) publication 

“Specification for Structural Joints Using ASTM A325 or A490 Bolts,” need to be used.

3. Parameters Monitored or Inspected: For each structure/aging effect combination, the 

specific parameters monitored or inspected depend on the particular structure, structural 

component, or commodity. Parameters monitored or inspected are commensurate with 

industry codes, standards, and guidelines and also consider industry and plant-specific 

operating experience. ACI 349.3R and ANSI/ASCE 11 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). 

For concrete structures, parameters monitored include loss of material, cracking, increase in 

porosity and permeability, loss of foundation strength, and reduction in concrete anchor 

capacity due to local concrete degradation. Steel structures and components are monitored 

for loss of material due to corrosion. Structural bolting is monitored for loose bolts, missing 

or loose nuts, and other conditions indicative of loss of preload. High strength (actual 

measured yield strength ≥ 150 ksi or 1,034 MPa) structural bolts greater than 1 inch 

(25 mm) in diameter are monitored for SCC. Other structural bolting (ASTM A-325, ASTM 

F1852, and ASTM A490 bolts), and anchor bolts are monitored for loss of material, loose or 

missing nuts, and cracking of concrete around the anchor bolts. Accessible sliding surfaces 

are monitored for indication of significant loss of material due to wear or corrosion, debris, or 

dirt. Elastomeric vibration isolators and structural sealants are monitored for cracking, loss of 

material, and hardening. These parameters and other monitored parameters are selected to 

ensure that aging degradation leading to loss of intended functions will be detected and the 

extent of degradation can be determined. Ground water chemistry (pH, chlorides, and 

sulfates) are monitored periodically to assess its impact, if any, on below grade concrete 

structures. If necessary for managing settlement and erosion of porous concrete subfoundations, the continued functionality of a site de-watering system is monitored. The plantspecific structures monitoring program should contain sufficient detail on parameters 

monitored or inspected to conclude that this program attribute is satisfied.

4. Detection of Aging Effects: Structures are monitored under this program using periodic 

visual inspection of each structure/aging effect combination by a qualified inspector to 

ensure that aging degradation will be detected and quantified before there is loss of 

intended function. Visual inspection of high strength (actual measured yield strength ≥ 150 

ksi or 1,034 MPa) structural bolting greater than 1 inch (25 mm) in diameter is supplemented 

with volumetric or surface examinations to detect cracking. Other structural bolting (ASTM 

A-325, ASTM F1852, and ASTM A490 bolts) and anchor bolts are monitored for loss of 

material, loose or missing nuts, and cracking of concrete around the anchor bolts.

Accessible sliding surfaces are monitored for indication of significant loss of material due to 
December 2010 XI S6-3 NUREG-1801, Rev. 2

wear or corrosion, debris, or dirt. Visual inspection of elastomeric vibration isolation 

elements should be supplemented by feel to detect hardening if the vibration isolation 

function is suspect. The inspection frequency depends on safety significance and the 

condition of the structure as specified in NRC RG 1.160, Rev. 2. In general, all structures 

and ground water quality are monitored on a frequency not to exceed 5 years. Some 

structures of lower safety significance, and subjected to benign environmental conditions, 

may be monitored at an interval exceeding five years; however, they should be identified 

and listed, together with their operating experience. The program includes provisions for 

more frequent inspections of structures and components categorized as (a)(1) in 

accordance with 10 CFR 50.65. Inspector qualifications should be consistent with industry 

guidelines and standards and guidelines for implementing the requirements of 10 CFR 

50.65. Qualifications of inspection and evaluation personnel specified in ACI 349.3R are 

acceptable for license renewal.

The structures monitoring program addresses detection of aging affects for inaccessible, 

below-grade concrete structural elements. For plants with non-aggressive ground water/soil 

(pH > 5.5, chlorides < 500 ppm, or sulfates <1500 ppm), the program recommends: 

(a) evaluating 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 and (b) examining representative samples of the exposed portions of the below grade 

concrete, when excavated for any reason.

For plants with aggressive ground water/soil (pH < 5.5, chlorides > 500 ppm, or sulfates 

> 1500 ppm) 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.

5. Monitoring and Trending: Regulatory Position 1.5, "Monitoring of Structures," in NRC 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: The structures monitoring program calls for inspection results to be 

evaluated by qualified engineering personnel based on acceptance criteria selected for each 

structure/aging effect to ensure that the need for corrective actions is identified before loss 

of intended functions. The criteria are derived from design bases codes and standards that 

include ACI 349.3R, ACI 318, ANSI/ASCE 11, or the relevant AISC specifications, as 

applicable, and consider industry and plant operating experience. The criteria are directed at 

the identification and evaluation of degradation that may affect the ability of the structure or 

component to perform its intended function. Applicants who are not committed to ACI 

349.3R and elect to use plant-specific criteria for concrete structures should describe the 

criteria and provide a technical basis for deviations from those in ACI 349.3R. Loose bolts 

and nuts and cracked high strength bolts are not acceptable unless accepted by engineering 

evaluation. Structural sealants are acceptable if the observed loss of material, cracking, and 

hardening will not result is loss of sealing. Elastomeric vibration isolation elements are 

acceptable if there is no loss of material, cracking, or hardening that could lead to the 

reduction or loss of isolation function. Acceptance criteria for sliding surfaces are (a) no 

indications of excessive loss of material due to corrosion or wear and (b) no debris or dirt 
NUREG-1801, Rev. 2 XI S6-4 December 2010

that could restrict or prevent sliding of the surfaces as required by design. The structures 

monitoring program is to contain sufficient detail on acceptance criteria to conclude that this 

program attribute is satisfied.

7. Corrective Actions: Evaluations are performed for any inspection results that do not satisfy 

established criteria. Corrective actions are initiated in accordance with the corrective action 

process if the evaluation results indicate there is a need for a repair or replacement. As 

discussed in the Appendix for GALL, 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 for GALL, 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 for GALL, 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 

operations. NUREG-1522 documents the results of a survey sponsored in 1992 by the 

Office of Nuclear Regulatory Regulation to obtain information on the types of distress in the 

concrete and steel structures and components, the type of repairs performed, and the 

durability of the repairs. Licensees who responded to the survey reported cracking, scaling, 

and leaching of concrete structures. The degradation was attributed to drying shrinkage, 

freeze-thaw, and abrasion. The NUREG also describes the results of NRC staff inspections 

at six plants. The staff observed concrete degradation, corrosion of component support 

members and anchor bolts, cracks and other deterioration of masonry walls, and ground 

water leakage and seepage into underground structures. The observed and reported 

degradations were more severe at coastal plants than those observed in inland plants as a 

result of brackish and sea water. Previous license renewal applicants reported similar 

degradation and corrective actions taken through their structures monitoring program. Many 

license renewal applicants have found it necessary to enhance their structures monitoring 

program to ensure that the aging effects of structures and components in the scope of 10 

CFR Part 54.4 are adequately managed during the period of extended operation. There is 

reasonable assurance that implementation of the structures monitoring program described 

above will be effective in managing the aging of the in-scope structures and component 

supports through 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, 2009.

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, 2009.

10 CFR 54.4, Scope, Office of the Federal Register, National Archives and Records 

Administration, 2009.
December 2010 XI S6-5 NUREG-1801, Rev. 2

ACI Standard 201.1R, Guide for Making a Condition Survey of Concrete in Service, American 

Concrete Institute, 1992.

ACI Standard 318, Building Code Requirements for Reinforced Concrete and Commentary, 

American Concrete Institute.

ACI Standard 349.3R, Evaluation of Existing Nuclear Safety-Related Concrete Structures,

American Concrete Institute, 2002. 

AISC, AISC Specification for Steel Buildings, American Institute of Steel Construction, Inc., 

Chicago, IL.

ANSI/ASCE 11-90, 99, Guideline for Structural Condition Assessment of Existing Buildings,

American Society of Civil Engineers.

EPRI NP-5067, Good Bolting Practices, A Reference Manual for Nuclear Power Plant 

Maintenance Personnel, Volume 1: Large Bolt Manual, 1987; Volume 2: Small Bolts and 

Threaded Fasteners, Electric Power Research Institute, 1990.

EPRI NP-5769, Degradation and Failure of Bolting in Nuclear Power Plants, Volumes 1 and 2, 

Electric Power Research Institute, April 1988. 

EPRI TR-104213, Bolted Joint Maintenance & Application Guide, Electric Power Research 

Institute, December 1995.

RCSC (Research Council on Structural Connections), Specification for Structural Joints Using 

ASTM A325 or A490 Bolts, Chicago, 2004.

NRC Regulatory Guide 1.127, Rev. 1, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants, U.S. Nuclear Regulatory Commission, March 1978.

NRC Regulatory Guide 1.142, Rev. 2, Safety-related Concrete Structures for Nuclear Power 

Plants (Other than Reactor Vessels and Containments), U.S. Nuclear Regulatory 

Commission, November 2001.

NRC Regulatory Guide 1.160, Rev. 2, Monitoring the Effectiveness of Maintenance at Nuclear 

Power Plants, U.S. Nuclear Regulatory Commission, March 1997.

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-1339, Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear 

Power Plants, U.S. Nuclear Regulatory Commission, June 1990. 

NUREG-1522, Assessment of Inservice Condition of Safety-Related Nuclear Power Plant 

Structures, June 1995.

December 2010 XI S7-1 NUREG-1801, Rev. 2

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 raw water-control structures associated with emergency cooling water systems or flood 

protection of nuclear power plants. The NRC 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 NRC 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.

NRC RG 1.127 provides detailed guidance for the licensee's inspection program for watercontrol structures, including guidance on engineering data compilation, inspection activities, 

technical evaluation, inspection frequency, and the content of inspection reports. NRC RG 1.127 

delineates current NRC practice in evaluating inservice inspection programs for water-control 

structures.

For plants not committed to NRC RG 1.127, Revision 1, aging management of water-control 

structures may be included in the “Structures Monitoring” (AMP XI.S6). Even if a plant is 

committed to NRC RG 1.127, Revision 1, aging management of certain structures and 

components may be included in the “Structures Monitoring” (AMP XI.S6). However, details 

pertaining to water-control structures, as described herein, are incorporated in AMP XI.S6 

program attributes.

NRC RG 1.127 attributes evaluated below do not include inspection of dams. For dam 

inspection and maintenance, programs under the regulatory jurisdiction of the Federal Energy 

Regulatory Commission (FERC) or the U.S. Army Corps of Engineers, continued through the 

period of extended operation, are 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 evaluates the effectiveness of the aging management program (AMP) 

based on compatibility to the common practices of the FERC and Corps programs.

Evaluation and Technical Basis

1. Scope of Program: NRC RG 1.127 applies to raw 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. The scope of the program also includes 

structural steel and structural bolting associated with water-control structures, steel or wood 

piles and sheeting required for the stability of embankments and channel slopes, and 

miscellaneous steel, such as sluice gates and trash racks.

2. Preventive Action: NRC RG 1.127 is a condition monitoring program. This program is 

augmented to incorporate preventive measures recommended in NUREG-1339, Electric 

Power Research Institute (EPRI) TR-104213, EPRI NP-5067, and EPRI NP-5769 to ensure 
NUREG-1801, Rev. 2 XI S7-2 December 2010

structural bolting integrity, if applicable. The documents provide guidelines for selection of 

replacement bolting material, approved thread lubricants, and appropriate torque and 

preload to be used for installation of bolting. If the structural bolting consists of ASTM A325, 

ASTM F1852, and/or ASTM A490 bolts, the preventive actions for storage, lubricants, and 

stress corrosion cracking potential discussed in Section 2 of RCSC (Research Council for 

Structural Connections) publication “Specification for Structural Joints Using ASTM A325 or 

A490 Bolts” need to be used.

3. Parameters Monitored or Inspected: NRC 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 are those described in 

American Concrete Institute (ACI) 201.1 and ACI-349-3R. These include cracking, 

movements (e.g., settlement, heaving, deflection), conditions at junctions with abutments 

and embankments, loss of material, increase in porosity and permeability, 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. 

Steel components are monitored for loss of material due to corrosion. 

Parameters monitored for channels and canals include erosion or degradations that may 

impose constraints on the function of the cooling system and present a potential hazard to 

the safety of the plant. Submerged emergency canals (e.g., artificially dredged canals at the 

river bed or the bottom of the reservoir) should be monitored for sedimentation, debris, or 

instability of slopes that may impair the function of the canals under extreme low flow 

conditions. 

Further details of parameters to be monitored and inspected for these and other watercontrol structures are specified in Section C.2 of NRC RG 1.127. The program is augmented 

to require monitoring of bolted connections for loss of material and loose bolts and nuts and 

other conditions indicative of loss of preload. High strength (actual measured yield strength 

≥ 150 ksi or 1,034 MPa) structural bolts greater than 1 inch (25 mm) in diameter are 

monitored for stress corrosion cracking, if applicable. Other structural bolting (ASTM A-325, 

ASTM F1852, and ASTM A490 bolts) and anchor bolts are monitored for loss of material, 

loose or missing nuts, and cracking of concrete around the anchor bolts. Accessible sliding 

surfaces are monitored for indication of significant loss of material due to wear or corrosion, 

debris, or dirt. The program also is augmented to require monitoring of wooden components 

for loss of material and change in material properties. 

4. Detection of Aging Effects: NRC RG 1.127 specifies that inspection of water-control 

structures should be conducted under the direction of qualified engineers experienced in the 

investigation, design, construction, and operation of these types of facilities. 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. 

NRC 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 
December 2010 XI S7-3 NUREG-1801, Rev. 2

degradation. NRC RG 1.127 describes periodic inspections to be performed at least once 

every 5 years. This interval has been shown to be adequate to detect degradation of watercontrol structures before a loss of an intended function. The program should include 

provisions for increased inspection frequency if the extent of the degradation is such that the 

structure or component may not meet its design basis if allowed to continue uncorrected 

until the next normally scheduled inspection. NRC 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.

The program should address detection of aging affects for inaccessible, below-grade, and 

submerged concrete structural elements. For plants with non-aggressive raw water and 

groundwater/soil (pH > 5.5, chlorides < 500 parts per million [ppm], or sulfates < 1500 ppm), 

the program should require (a) evaluation of 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 and (b) examination of representative samples of 

the exposed portions of the below-grade concrete when excavated for any reason. 

Submerged concrete structures should be inspected during periods of low tide or when 

dewatered and accessible.

For plants with aggressive environment raw water (pH < 5.5, chlorides > 500 ppm, or 

sulfates > 1500 ppm) or ground water/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.

5. Monitoring and Trending: Water-control structures are monitored by periodic inspection, 

as described in NRC RG 1.127. Changes of degraded conditions from prior inspection, such 

as growth of an active crack or extent of corrosion, should be trended until it is evident that 

the change is no longer occurring or until corrective actions are implemented in accordance 

with 10 CFR 50.65 and RG 1.160, Rev. 2. 

6. Acceptance Criteria: Quantitative acceptance criteria to evaluate the need for corrective 

actions are not specified in NRC RG 1.127. However, the “Evaluation Criteria” provided in 

Chapter 5 of ACI 349.3R provide 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 are acceptable. Acceptance criteria for earthen structures, such as canals and 

embankments, are consistent with programs falling within the regulatory jurisdiction of the 

FERC or the U.S. Army Corps of Engineers. Loose bolts and nuts, cracked high strength 

bolts, and degradation of piles and sheeting are accepted by engineering evaluation or 

subject to corrective actions. Engineering evaluation should be documented and based on 

codes, specifications, and standards such as AISC specifications, SEI/ASCE 11, and those 

referenced in the plant’s current licensing basis.

7. Corrective Actions: NRC RG 1.127 recommends that when inspection 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 for GALL, the staff finds the requirements of 

10 CFR Part 50, Appendix B, acceptable to address the corrective actions.
NUREG-1801, Rev. 2 XI S7-4 December 2010

8. Confirmation Process: As discussed in the Appendix for GALL, 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 for GALL, 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 

NRC RG 1.127 programs, at a number of nuclear power plants, and, in some cases, it has 

required remedial action. NRC NUREG-1522 described instances and corrective actions of 

severely degraded steel and concrete components at the intake structure and pumphouse of 

coastal plants. Other degradation described in the NUREG include appreciable leakage 

from the spillway gates, concrete cracking, corrosion of spillway bridge beam seats of a 

plant dam and cooling canal, and appreciable differential settlement of the outfall structure 

of another. 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 NRC 

RG 1.127 have been successful in detecting significant degradation before loss of intended 

function occurs.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

ACI Standard 201.1R, Guide for Making a Condition Survey of Concrete in Service, American 

Concrete Institute, 1992.

ACI Standard 349.3R, Evaluation of Existing Nuclear Safety-Related Concrete Structures,

American Concrete Institute, 2002. 

EPRI NP-5067, Good Bolting Practices, A Reference Manual for Nuclear Power Plant 

Maintenance Personnel, Volume 1: Large Bolt Manual, 1987; Volume 2: Small Bolts and 

Threaded Fasteners, Electric Power Research Institute, 1990.

EPRI NP-5769, Degradation and Failure of Bolting in Nuclear Power Plants, Volumes 1 and 2, 

Electric Power Research Institute, April 1988. 

EPRI TR-104213, Bolted Joint Maintenance & Application Guide, Electric Power Research 

Institute, December 1995.

NRC Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear 

Power Plants, Revision 1, U.S. Nuclear Regulatory Commission, March 1978. 

NRC Regulatory Guide 1.160, Rev. 2, Monitoring the Effectiveness of Maintenance at Nuclear 

Power Plants, U.S. Nuclear Regulatory Commission, March 1997.

NUREG-1339, Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear 

Power Plants, U.S. Nuclear Regulatory Commission, June 1990. 
December 2010 XI S7-5 NUREG-1801, Rev. 2

NUREG-1522, Assessment of Inservice Conditions of Safety-Related Nuclear Plant Structures, 

U.S. Nuclear Regulatory Commission, June 1995. 

RCSC (Research Council on Structural Connections), Specification for Structural Joints Using 

ASTM A325 or A490 Bolts, 2004.

December 2010 XI S8-1 NUREG-1801, Rev. 2

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, or latest version) 

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 

Emergency Core Cooling Systems (ECCS) suction strainers, which reduces flow through the 

system and could cause unacceptable head loss for the pumps.

Maintenance of Service Level I coatings applied to carbon steel and concrete surfaces inside 

containment (e.g., steel liner, steel containment shell, structural steel, supports, penetrations, 

and concrete walls and floors) also serve to prevent or minimize loss of material due to 

corrosion of carbon steel components and aids in decontamination. Regulatory Position C4 in 

NRC RG 1.54, Rev. 2, 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. American Society for Testing of Materials (ASTM) 

D 5163-08 and endorsed years of the standard in NRC RG 1.54 are acceptable and considered 

consistent with NUREG-1801. In addition, Electric Power Research Institute (EPRI) Report 

1019157, Guidelines for Inspection and Maintenance of Safety-related Protective Coatings, 

provides additional information on the ASTM standard guidelines.

A comparable program for monitoring and maintaining protective coatings inside containment, 

developed in accordance with NRC RG 1.54, Rev. 2, is acceptable as an aging management 

program for license renewal.

Service Level I coatings credited for preventing corrosion of steel containments and steel liners 

for concrete containments are subject to requirements specified by the American Society of 

Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code, Section XI, 

Subsection IWE (AMP XI.S1). However, this program (AMP XI.S8) reviews Service Level I 

coatings to ensure that the protective coating monitoring and maintenance program are 

adequate for license renewal.

Evaluation and Technical Basis

1. Scope of Program: The minimum scope of the program is Service Level I coatings applied 

to steel and concrete surfaces inside containment (e.g., steel liner, steel containment shell, 

structural steel, supports, penetrations, and concrete walls and floors), defined in NRC RG 

1.54, Rev. 2, 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." The scope of the program also should 

include any Service Level I coatings that are credited by the licensee for preventing loss of 

material due to corrosion in accordance with AMP XI.S1. 

2. Preventive Action: The program is a condition monitoring program and does not 

recommend any preventive actions. However, for plants that credit coatings to minimize loss 

of material, this program is a preventive action.

3. Parameters Monitored or Inspected: Regulatory Position C4 in NRC RG 1.54, Rev 1, 

states that "ASTM D 5163-96 provides guidelines that are acceptable to the NRC staff for 
NUREG-1801, Rev. 2 XI S8-2 December 2010

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 

5163-08. ASTM D 5163-08 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 5163-08, paragraph 6, defines the inspection 

frequency to be each refueling outage or during other major maintenance outages, as 

needed. ASTM D 5163-08, paragraph 9, discusses the qualifications for inspection 

personnel, the inspection coordinator, and the inspection results evaluator. 

ASTM D 5163-08, subparagraph 10.1, discusses development of the inspection plan and 

the inspection methods to be used. It states that 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 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 5163-08, subparagraph 10.5, 

identifies instruments and equipment needed for inspection. 

5. Monitoring and Trending: ASTM D 5163-08 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 as postponed to 

future outages, but under surveillance in the interim period.

6. Acceptance Criteria: ASTM D 5163-08, subparagraphs 10.2.1 through 10.2.6, 10.3, and 

10.4, contains one acceptable method for the 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 5163-08, paragraph 11, addresses evaluation. It specifies that the 

inspection report is to be evaluated by the responsible evaluation personnel, who prepare a 

summary of findings and recommendations for future surveillance or repair, and prioritization 

of repairs.

7. Corrective Actions: A recommended corrective action plan is required for major defective 

areas so that these areas can be repaired during the same outage, if appropriate. As 

discussed in the Appendix for GALL, 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 for GALL, 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: NRC Information Notice 88-82, NRC Bulletin 96-03, NRC Generic 

Letter (GL) 04-02, and NRC GL 98-04 describe industry experience pertaining to coatings 

degradation inside containment and the consequential clogging of sump strainers. NRC 
December 2010 XI S8-3 NUREG-1801, Rev. 2

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

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

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.

ASTM D 5163-08, Standard Guide for Establishing a Program for Condition Assessment of 

Coating Service Level I Coating Systems in Nuclear Power Plants, American Society for 

Testing and Materials, 2008.

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.

EPRI Report 1003102, Guideline on Nuclear Safety-Related Coatings, Revision 1, (Formerly 

TR-109937), Electric Power Research Institute, November 2001.

EPRI Report 1019157, Guideline on Nuclear Safety-Related Coatings, Revision 2, (Formerly 

TR-109937and 1003102), Electric Power Research Institute, December 2009. 

NRC Bulletin 96-03, Potential Plugging of Emergency Core Cooling Suction Strainers by Debris 

in Boiling-Water Reactors, U.S. Nuclear Regulatory Commission, May 6, 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 Generic Letter 04-02, Potential Impact of Debris Blockage on Emergency Recirculation 

during Design Basis Accidents at Pressurized-Water Reactors, U.S. Nuclear Regulatory 

Commission, September 13, 2004.

NRC Information Notice 88-82, Torus Shells with Corrosion and Degraded Coatings in BWR 

Containments, U.S. Nuclear Regulatory Commission, November 14, 1988.

NRC Information Notice 97-13, Deficient Conditions Associated With Protective Coatings at 

Nuclear Power Plants, U.S. Nuclear Regulatory Commission, March 24, 1997.

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.
NUREG-1801, Rev. 2 XI S8-4 December 2010

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.

NRC Regulatory Guide 1.54, Rev. 2, Service Level I, II, and III Protective Coatings Applied to 

Nuclear Power Plants, U.S. Nuclear Regulatory Commission, October 2010. 
December 2010 XI E1-1 NUREG-1801, Rev. 2

XI.E1 INSULATION MATERIAL FOR ELECTRICAL CABLES AND CONNECTIONS NOT 

SUBJECT TO 10 CFR 50.49 ENVIRONMENTAL QUALIFICATION REQUIREMENTS 

Program Description

The purpose of the aging management program (AMP) 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 temperature, radiation, or moisture are maintained 

consistent with the current licensing basis through the period of extended operation.

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. 

Insulation materials used in electrical 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 plant design 

environment for the cable or connection insulation material that could increase the rate of aging 

of a component or have an adverse effect on operability. An adverse localized environment 

exists based on the most limiting condition for temperature, radiation, or moisture for the 

insulation material of cables or connections. Adverse localized environments can be identified 

through the use of an integrated approach. This approach may include, but is not limited to, (a) 

the review of Environmental Qualification (EQ) zone maps that show radiation levels and 

temperatures for various plant areas, (b) consultations with plant staff who are cognizant of 

plant conditions, (c) utilization of infrared thermography to identify hot spots on a real-time basis, 

and (d) the review of relevant plant-specific and industry operating experience. 

The program described herein was 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. Cables and connections from accessible areas 

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, a determination is made as to whether the same condition or 

situation is applicable to 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 is that failures of deteriorated cable systems 

(cables, connections, and penetrations) might be induced during accident conditions.” Since the

cables and connections are not subject to the environmental qualification requirements of 

10 CFR 50.49, an AMP is required to manage the aging effects. This AMP provides reasonable 

assurance the insulation material for electrical cables and connections will perform its intended 

function for the period of extended operation.

Evaluation and Technical Basis

1. Scope of Program: This AMP applies to accessible electrical cables and connections within 

the scope of license renewal that are located in adverse localized environments caused by 

temperature, radiation, or moisture.
NUREG-1801, Rev. 2 XI E1-2 December 2010

2. Preventive Actions: This is a condition monitoring program and no actions are taken as 

part of this program to prevent or mitigate aging degradation.

3. Parameters Monitored/Inspected: Accessible electrical cables and connections installed in 

adverse localized environments are visually inspected for cable jacket and connection 

insulation surface anomalies indicating signs of reduced insulation resistance due to 

thermal/thermoxidative degradation of organics, radiolysis and photolysis (UV sensitive 

materials only) of organics; radiation-induced oxidation, and moisture intrusion as indicated 

by signs of embrittlement, discoloration, cracking, melting, swelling or surface 

contamination. An adverse localized environment is a plant-specific condition; therefore, the 

applicant should clearly define how this condition is determined. The applicant should 

determine and inspect the adverse localized conditions for each of the most limiting 

temperature, radiation, or moisture conditions for the accessible cables and connections that 

are within the scope of license renewal. 

4. Detection of Aging Effects: Insulation aging degradation from temperature, radiation, or 

moisture causes cable jacket and connection insulation surface anomalies. Accessible 

electrical cables and connections installed in adverse localized environments are visually 

inspected for cable jacket and connection insulation surface anomalies, such as 

embrittlement, discoloration, cracking, melting, swelling or surface contamination. The 

inspection of cable jacket and connection insulation surfaces is used to infer the adequacy 

of the cables and connections. 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 cables and connection insulation since 

experience has shown that aging degradation is a slow process. A 10-year inspection 

interval provides 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 prior to the 

period of extended operation.

5. Monitoring and Trending: Trending actions are not included as part of this AMP, because 

the ability to trend visual inspection results is limited. However, inspection results that are 

trendable provide additional information on the rate of cable or connection degradation. 

6. Acceptance Criteria: The accessible cables and connections are to be free from 

unacceptable visual indications of surface anomalies that suggest that cable jacket or 

connection insulation 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 jacket and connection 

insulation 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 

cables 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 cables or connections. When an unacceptable condition or situation is identified, a 

determination is made as to whether the same condition or situation is applicable to 

inaccessible cables or connections. As discussed in the Appendix for GALL, the staff finds 

the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective 

actions.
December 2010 XI E1-3 NUREG-1801, Rev. 2

8. Confirmation Process: As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process.

9. Administrative Controls: The administrative controls for this AMP provide for a formal 

review and approval process. As discussed in the Appendix for GALL, 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 elevated temperature, radiation, or moisture for electrical cables 

and connections may exist. For example next to or above (within 3 feet of) steam 

generators, pressurizers, or hot process pipes, such as feedwater lines. These adverse 

localized environments have been found to cause degradation of the insulating materials on 

electrical cables and connections that are visually observable, such as color changes or 

surface cracking. These visual indications can be used as indicators of degradation.

This AMP considers the technical information and guidance provided in NUREG/CR-5643, 

IEEE Std. 1205-2000, SAND96-0344, and EPRI TR-109619.

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

EPRI TR-109619, Guideline for the Management of Adverse Localized Equipment 

Environments, Electric Power Research Institute, Palo Alto, CA, June 1999.

IEEE Std. 1205-2000, 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.

December 2010 XI E2-1 NUREG-1801, Rev. 2

XI.E2 INSULATION MATERIAL FOR ELECTRICAL CABLES AND CONNECTIONS NOT 

SUBJECT TO 10 CFR 50.49 ENVIRONMENTAL QUALIFICATION REQUIREMENTS USED 

IN INSTRUMENTATION CIRCUITS 

Program Description

The purpose of this aging management program (AMP) 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 used in instrumentation 

circuits with sensitive, high-voltage, low-level current signals exposed to adverse localized 

environments caused by temperature, radiation, or moisture) are maintained consistent with the 

current licensing basis through the period of extended operation. 

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. 

Insulation materials used in electrical cables or connections may degrade more rapidly in 

adverse localized environments. An adverse localized environment is a condition in a limited 

plant area that is significantly more severe than the plant design environment for the cable or 

connection insulation material that could increase the rate of aging of a component or have an 

adverse effect on operability. Exposure of electrical cable and connection insulation material to 

adverse localized environments caused by temperature, 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 all 

circuits, but especially those with sensitive, high voltage, low-level current signals, such as 

radiation monitoring and nuclear instrumentation circuits, because a reduced IR may contribute 

to signal inaccuracies.

In this AMP, 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 and connection insulation material aging degradation. In the 

second method, direct testing of the cable system is performed.

This AMP applies to high-range-radiation and neutron flux monitoring instrumentation cables in 

addition to other cables used in high voltage, low-level current signal applications that are 

sensitive to reduction in IR. For these cables, AMP XI.E1 does not apply.

As stated in NUREG/CR-5643, “the major concern is that failures of deteriorated cable systems 

(cables, connections, and penetrations) might be induced during accident conditions.” Since the

instrumentation cables and connections are not subject to the environmental qualification 

requirements of 10 CFR 50.49, an AMP is required to manage the aging effects. This AMP 

provides reasonable assurance the insulation material for electrical cables and connections will 

perform its intended function for the period of extended operation.

Evaluation and Technical Basis

1. Scope of Program: This AMP applies to electrical cables and connections (cable system) 

used in circuits with sensitive, high voltage, low-level current signals, such as radiation 
NUREG-1801, Rev. 2 XI E2-2 December 2010

monitoring and nuclear instrumentation, that are subject to aging management review and 

installed in adverse localized environments caused by temperature, radiation, or moisture. 

2. Preventive Actions: This is a performance monitoring program and 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 surveillance, an applicant may detect severe aging degradation 

prior to the loss of the cable and connection intended function. The first reviews are 

completed prior to the period of extended operation and at least every 10 years thereafter. 

All calibration or surveillance results that do not meet acceptance criteria are reviewed for 

aging effects when the results are available.

Cable system testing is conducted when the 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. 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 system insulation condition as 

justified in the application) is performed. The test frequency of the cable system is 

determined by the applicant based on engineering evaluation, but the test frequency is at 

least once every 10 years. The first test is to be completed prior to the period of extended

operation.

5. Monitoring and Trending: Trending actions are not included as part of this AMP 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 cable or 

connection degradation.

6. Acceptance Criteria: Calibration results or findings of surveillance and cable system testing 

are to be within the acceptance criteria, as set out in the applicant’s procedures.

7. Corrective Actions: Corrective actions, such as recalibration and circuit trouble-shooting, 

are implemented when calibration, surveillance, or cable system test results do not meet the 

acceptance criteria. An engineering evaluation is performed when the 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 calibration, surveillance, or cable system 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 acceptance criteria; the corrective actions required; and 

likelihood of recurrence. When an unacceptable condition or situation is identified, a 

determination also is made as to whether the review of calibration and surveillance results 

or the cable system testing frequency needs to be increased. As discussed in the Appendix 

for GALL, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to 

address the corrective actions.
December 2010 XI E2-3 NUREG-1801, Rev. 2

8. Confirmation Process: As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address confirmation process.

9. Administrative Controls: The administrative controls for this AMP provide for a formal 

review and approval process. As discussed in the Appendix for GALL, 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 a 

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 containment near the 

reactor vessel.

This AMP considers the technical information and guidance provided in NUREG/CR-5643, 

IEEE Std. 1205-2000, SAND96-0344, EPRI TR-109619, NRC IN 97-45, and NRC IN 97-45, 

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, 2009.

EPRI TR-109619, Guideline for the Management of Adverse Localized Equipment 

Environments, Electric Power Research Institute, Palo Alto, CA, June 1999.

IEEE Std. 1205-2000, IEEE Guide for Assessing, Monitoring and Mitigating Aging Effects on 

Class 1E Equipment Used in Nuclear Power Generating Stations.

NRC Information Notice 97-45, Environmental Qualification Deficiency for Cables and 

Containment Penetration Pigtails, U. S, Nuclear Regulatory Commission, July 2, 1997.

NRC Information Notice 97-45, Supplement 1, Environmental Qualification Deficiency for 

Cables and Containment Penetration Pigtails, U. S, Nuclear Regulatory Commission, 

February 17, 1998.

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. 

December 2010 XI E3-1 NUREG-1801, Rev. 2

XI.E3 INACCESSIBLE POWER CABLES NOT SUBJECT TO 10 CFR 50.49 

ENVIRONMENTAL QUALIFICATION REQUIREMENTS 

Program Description

The purpose of the aging management program (AMP) described herein is to provide 

reasonable assurance that the intended functions of inaccessible or underground power cables 

that are not subject to the environmental qualification requirements of 10 CFR 50.49 and are 

exposed to wetting or submergence are maintained consistent with the current licensing basis 

through the period of extended operation. 

Most electrical cables in nuclear power plants are located in dry environments. However, some 

cables may be exposed to wetting or submergence, and are inaccessible or underground, such 

as cables in conduits, cable trenches, cable troughs, duct banks, underground vaults, or directly

buried in soil installations. When a power cable (greater than or equal to 400 volts) is exposed 

to wet, submerged, or other adverse environmental conditions for which it was not designed, an 

aging effect of reduced insulation resistance may result, causing a decrease in the dielectric 

strength of the conductor insulation. This insulation degradation can be caused by wetting or 

submergence. This can potentially lead to failure of the cable’s insulation system. 

In this AMP, periodic actions are taken to prevent cables from being exposed to significant 

moisture, defined as periodic exposures to moisture that last more than a few days (e.g., cable 

wetting or submergence in water. Examples of periodic actions are inspecting for water 

collection in cable manholes and conduits and draining water, as needed. However, the above 

actions are not sufficient to ensure that water is not trapped elsewhere in the raceways. For 

example, (a) if a duct bank conduit has low points in the routing, there could be potential for 

long-term submergence at these low points; (b) concrete raceways may crack due to soil 

settling over a long period of time; (c) manhole covers may not be watertight; (d) in certain 

areas, the water table is high in seasonal cycles, so the raceways may get refilled soon after 

purging; and (e) 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 power cables exposed to 

significant moisture are tested to indicate the condition of the conductor insulation. The specific 

type of test performed is determined prior to the initial test, and is to be a proven test for 

detecting deterioration of the insulation system due to wetting or submergence, such as 

Dielectric Loss (Dissipation Factor/Power Factor), AC Voltage Withstand, Partial Discharge, 

Step Voltage, Time Domain Reflectometry, Insulation Resistance and Polarization Index, Line 

Resonance Analysis, or other testing that is state-of-the-art at the time the tests are performed. 

One or more tests are used to determine the condition of the cables so they will continue to 

meet their intended function during the period of extended operation.

As stated in NUREG/CR-5643, “the major concern is that failures of deteriorated cable systems 

(cables, connections, and penetrations) might be induced during accident conditions.” Because

the cables are not subject to the environmental qualification requirements of 10 CFR 50.49, an 

AMP is required to manage the aging effects. This AMP provides reasonable assurance the 

insulation material for electrical cables will perform its intended function for the period of 

extended operation.
NUREG-1801, Rev. 2 XI E3-2 December 2010

Evaluation and Technical Basis

1. Scope of Program: This AMP applies to all inaccessible or underground (e.g., in conduit, 

duct bank, or direct buried) power cables (greater than or equal to 400 volts) within the 

scope of license renewal exposed to adverse environments, primarily significant moisture. 

Significant moisture is defined as periodic exposures to moisture that last more than a few 

days (e.g., cable wetting or submergence in water). Submarine or other cables designed for 

continuous wetting or submergence are not included in this AMP.

2. Preventive Actions: This is a condition monitoring program. However, periodic actions are 

taken to prevent inaccessible cables from being exposed to significant moisture, such as 

identifying and inspecting in-scope accessible cable conduit ends and cable manholes for 

water collection, and draining the water, as needed. 

The inspection frequency for water collection is established and performed based on plantspecific operating experience with cable wetting or submergence in manholes (i.e., the 

inspection is performed periodically based on water accumulation over time and event 

driven occurrences, such as heavy rain or flooding). The periodic inspection should occur at 

least annually. The inspection should include direct observation that cables are not wetted 

or submerged, that cables/splices and cable support structures are intact, and that 

dewatering/drainage systems (i.e., sump pumps) and associated alarms operate properly. In 

addition, operation of dewatering devices should be inspected and operation verified prior to 

any known or predicted heavy rain or flooding events. If water is found during inspection 

(i.e., cable exposed to significant moisture), corrective actions are taken to keep the cable 

dry and to assess cable degradation. The first inspection for license renewal is completed 

prior to the period of extended operation.

3. Parameters Monitored/Inspected: Inspection for water collection is performed based on 

plant-specific operating experience with water accumulation in the manhole. Inaccessible or 

underground power (greater than or equal to 400 volts) cables within the scope of license 

renewal exposed to significant moisture are tested to provide an indication of the condition 

of the conductor insulation. The specific type of test to be used should be capable of 

detecting reduced insulation resistance of the cable’s insulation system due to wetting or 

submergence. 

4. Detection of Aging Effects: For power cables exposed to significant moisture, test 

frequencies are adjusted based on test results (including trending of degradation where 

applicable) and operating experience. Cable testing should occur at least once every 6 

years. A 6-year interval provides multiple data points during a 20-year period, which can be 

used to characterize the degradation rate. This is an adequate period to monitor 

performance of the cable and take appropriate corrective actions since experience has 

shown that although a slow process, aging degradation could be significant.. The first tests 

for license renewal are to be completed prior to the period of extended operation with 

subsequent tests performed at least every 6 years thereafter. The applicant can assess the 

condition of the cable insulation with reasonable confidence using one or more of the 

following techniques: Dielectric Loss (Dissipation Factor/Power Factor), AC Voltage 

Withstand, Partial Discharge, Step Voltage, Time Domain Reflectometry, Insulation 

Resistance and Polarization Index, Line Resonance Analysis, or other testing that is stateof-the-art at the time the tests are performed. One or more tests are used to determine the 

condition of the cables so they will continue to meet their intended function during the period 

of extended operation.
December 2010 XI E3-3 NUREG-1801, Rev. 2

5. Monitoring and Trending: Trending actions are included as part of this AMP, although the 

ability to trend results is dependent on the specific type of test(s) or inspection chosen. 

Results that are trendable provide additional information on the rate of cable insulation 

degradation.

6. Acceptance Criteria: The acceptance criteria for each test are defined by the specific type 

of test performed and the specific cable tested. Acceptance criteria for inspections of 

manholes are defined by the observation that the cables and support structures are not 

submerged or immersed in standing water at the time of the inspection.

7. Corrective Actions: Corrective actions are taken and an engineering evaluation is 

performed when the test or inspection acceptance criteria are not met. Such an evaluation 

considers the significance of the test or inspection 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 or inspection 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 

accessible or inaccessible, in-scope power cables. Corrective actions may include, but are 

not limited to, installation of permanent drainage systems, installation of sump pumps and 

alarms, more frequent cable testing or manhole inspections, or replacement of the affected 

cable. As discussed in the Appendix for GALL, 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process.

9. Administrative Controls: The administrative controls for this AMP provide for a formal 

review and approval process. As discussed in the Appendix for GALL, 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 insulation materials are 

susceptible to water tree formation. The formation and growth of water trees varies directly 

with operating voltage. Aging effects of reduced insulation resistance due to other 

mechanisms may also result in a decrease in the dielectric strength of the conductor 

insulation. Minimizing exposure to moisture mitigates the potential for the development of 

reduced insulation resistance. 

Recent incidents involving early failures of electric cables and cable failures leading to 

multiple equipment failures, are cited in NRC IN 2002-12, “Submerged Safety-Related 

Cables,” and NRC GL 2007-01, “Inaccessible or Underground Power Cable Failures That 

Disable Accident Mitigation Systems or Cause Plant Transients.” 

The NRC issued GL 2007-001 on inaccessible or underground cables to (a) inform 

licensees that the failure of certain power cables can affect the functionality of multiple 

accident mitigation systems or cause plant transients and (b) gather information from 

licensees on the monitoring of inaccessible or underground power cable failures for all 

cables that are within the scope of the Maintenance Rule. Based on the review of licensees’ 

responses, the NRC staff has identified 269 cable failures for 104 reactor units. The data 

obtained from the GL responses show an increasing trend of cable failures. The NRC staff 
NUREG-1801, Rev. 2 XI E3-4 December 2010

has noted that the predominant factor contributing to cable failures at nuclear power plants 

was due to moisture/submergence. The staff also noted that the GL failure data show that 

the majority of the reported failures occurred at the 4160-volt, 480 volt, and 600-volt service 

voltage levels for both energized and de-energized cables. These cables are failing within 

the plants’ 40-year licensing period. 

The NRC inspectors also have continued to identify safety-related cables which are 

submerged. The staff noted that licensees had not demonstrated that the subject safetyrelated cables were designed for wetted or submerged service for the current license period. 

This AMP considers the technical information and generic communication guidance 

provided in NUREG/CR-5643; IEEE Std. 1205-2000; SAND96-0344; EPRI 109619; EPRI 

103834-P1-2; NRC IN 2002-12; NRC GL 2007-01; NRC GL 2007-01 Summary Report; NRC 

Inspection Procedure, Attachment 71111.06, Flood Protection Measures; NRC Inspection 

Procedure, Attachment 71111.01, Adverse Weather Protection; RG 1.211 Rev 0; DG-1240; 

and NUREG/CR-7000. 

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

DG-1240, Condition Monitoring Program for Electric Cables Used In Nuclear Power Plants, 

June 2010.

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. 1205-2000, IEEE Guide for Assessing, Monitoring and Mitigating Aging Effects on 

Class 1E Equipment Used in Nuclear Power Generating Stations.

NRC Inspection Procedure, Attachment 71111.06, Flood Protection Measures, June 25, 2009.

NRC Inspection Procedure, Attachment 71111.01, Adverse Weather Protection, April 8, 2009.

NRC Information Notice 2002-12, Submerged Safety-Related Electrical Cables, March 21, 

2002.

NRC Generic Letter 2007-01, Summary Report, Inaccessible or Underground Power Cable 

Failures that Disable Accident Mitigation Systems or Cause Plant Transients, November 12, 

2008.

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.
December 2010 XI E3-5 NUREG-1801, Rev. 2

RG 1.211 Rev 0, Qualification of Safety-Related Cables and Field Splices for Nuclear Power 

Plants, April 2009.

NUREG/CR-7000, Essential Elements of an Electric Cable Condition Monitoring Program, 

January 2010.

December 2010 XI E4-1 NUREG-1801, Rev. 2

XI.E4 METAL ENCLOSED BUS

Program Description

The purpose of this aging management program (AMP) is to provide an internal and external 

inspection of Metal Enclosed Buses (MEBs) to identify age-related degradation of insulating 

material (i.e., porcelain, xenoy, thermoplastic organic polymers), and metallic and elastomer 

components (e.g., gaskets, boots, and sealants).

MEBs are electrical buses installed on electrically insulated supports that are constructed with 

each phase conductor enclosed in a separate metal enclosure (isolated phase bus), all 

conductors enclosed in a common metal enclosure (non-segregated bus), or all phase 

conductors in a common metal enclosure, but separated by metal barriers between phases 

(segregated bus). The conductors are adequately separated and insulated from ground by 

insulating supports or bus insulation. The MEBs are used in power systems to connect various 

elements in electric power circuits, such as switchgear, transformers, main generators, and 

diesel generators.

Industry operating experience indicates that failures of MEBs have been caused by cracked 

insulation and moisture, debris, or excessive dust buildup internal to the bus duct housing. 

Cracked insulation has resulted from high ambient temperature and contamination from bus bar 

joint compounds. Cracked insulation in the presence of moisture or debris has provided phaseto-phase or phase-to-ground 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 and 

operators.

MEBs may experience increased resistance of connection due to loosening of bolted bus duct 

connections caused by repeated thermal cycling of connected loads. This phenomenon can 

occur in heavily loaded circuits (i.e., those exposed to appreciable ohmic heating). For example, 

SAND 96-0344 identified instances of termination loosening at several plants due to thermal 

cycling and NRC IN 2000-14 identified torque relaxation of splice plate connecting bolts as one 

potential cause of a MEB fault. 

This AMP includes the inspection of all bus ducts within the scope of license renewal and a 

sample of accessible MEB bolted connections for increased resistance of connection. The 

technical basis for the sample selections should be 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. 

Evaluation and Technical Basis

1. Scope of Program: This AMP manages the age-related degradation effects for electrical 

bus bar bolted connections, bus bar insulation, bus bar insulating supports, bus enclosure 

assemblies (internal and external), and elastomers. This program does not manage the 

aging effects on external bus structural supports, which are managed under AMP XI.S6, 

“Structures Monitoring.” Alternatively, the aging effects on elastomers can be managed 

under AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components,” and the external surfaces of MEB enclosure assemblies can be managed 

under AMP XI.S6, “Structures Monitoring.” 
NUREG-1801, Rev. 2 XI E4-2 December 2010

2. Preventive Actions: This is a condition monitoring program and no actions are taken as 

part of this program to prevent or mitigate aging degradation.

3. Parameters Monitored/Inspected: This AMP provides for the inspection of the internal and 

external portions of the MEB. Internal portions (bus enclosure assemblies) of the MEB are 

inspected for cracks, corrosion, foreign debris, excessive dust buildup, and evidence of 

water intrusion. The bus insulation is inspected for signs of reduced insulation resistance 

due to thermal/thermoxidative degradation of organics/thermoplastics, radiation-induced 

oxidation, moisture/debris intrusion, or ohmic heating, as indicated by embrittlement, 

cracking, chipping, melting, discoloration, or swelling, which may indicate overheating or 

aging degradation. The internal bus insulating supports are inspected for structural integrity 

and signs of cracks. A sample of accessible bolted connections is inspected for increased 

resistance of connection. Alternatively, for accessible bolted connections covered with heat 

shrink tape, sleeving, insulating boots, etc., the sample may be visually inspected for 

insulation material surface anomalies. The external portions of the MEB, including 

accessible gaskets, boots, and sealants, are inspected for hardening and loss of strength 

due to elastomer degradation that could permit water or foreign debris to enter the bus. MEB 

external surfaces are inspected for loss of material due to general, pitting, and crevice 

corrosion. 

4. Detection of Aging Effects: MEB internal surfaces are visually inspected for aging 

degradation including cracks, corrosion, foreign debris, excessive dust buildup, and 

evidence of moisture intrusion. MEB insulating material is visually inspected for signs of 

embrittlement, cracking, chipping, melting, discoloration, swelling, or surface contamination. 

Internal bus insulating supports are visually inspected for structural integrity and signs of 

cracks. MEB external surfaces are visually inspected for loss of material due to general, 

pitting, and crevice corrosion. Accessible elastomers (e.g., gaskets, boots, and sealants) are 

inspected for degradation including surface cracking, crazing, scuffing, dimensional change 

(e.g. “ballooning” and “necking”), shrinkage, discoloration, hardening and loss of strength.

A sample of accessible bolted connections is inspected for increased resistance of 

connection by using thermography or by measuring connection resistance using a microohmmeter. Twenty percent of the population with a maximum sample of 25 constitutes a 

representative sample size. Otherwise, a technical justification of the methodology and 

sample size used for selecting components should be included as part of the AMP’s site

documentation. 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. 

The first inspection using thermography or measuring connection resistance is completed 

prior to the period of extended operation and every 10 years thereafter provided visual 

inspection is not used to inspect bolted connections. This is an adequate period to preclude 

failures of the MEBs since experience has shown that MEB aging degradation is a slow 

process.

As an alternative to thermography or measuring connection resistance of bolted 

connections, for 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 embrittlement, cracking, chipping, melting, 

discoloration, swelling, or surface contamination. When this alternative visual inspection is 
December 2010 XI E4-3 NUREG-1801, Rev. 2

used to check the bolted connection sample, the first inspection is completed prior to the 

period of extended operation and every 5 years thereafter.

5. Monitoring and Trending: Trending actions are not included as part of this AMP 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: MEB insulation materials are free from regional indications of surface 

anomalies such as embrittlement, cracking, chipping, melting, discoloration, and swelling, or 

surface contamination. MEB internal surfaces show no indications of corrosion, cracks, 

foreign debris, excessive dust buildup, or evidence of moisture intrusion. Accessible 

elastomers (e.g., gaskets, boots, and sealants) show no indications of surface cracking, 

crazing, scuffing, dimensional change (e.g. “ballooning” and “necking”), shrinkage, 

discoloration, hardening, and loss of strength. MEB external surfaces are free from loss of 

material due to general, pitting, and crevice corrosion.

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. When the visual inspection alternative for bolted 

connections is used, the absence of embrittlement, cracking, chipping, melting, 

discoloration, swelling, or surface contamination of the insulation material provides positive 

indication that the bolted connections are not loose. 

7. Corrective Actions: Corrective actions are taken and an engineering evaluation is 

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 for GALL, 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process.

9. Administrative Controls: The administrative controls for this AMP provide for a formal 

review and approval process. As discussed in the Appendix for GALL, 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 also has shown that bus connections in the MEBs exposed to appreciable ohmic 

heating during operation may experience loosening due to repeated cycling of connected 

loads.

This AMP considers the technical information and guidance provided in SAND 96-0344, 

IEEE Std. 1205-2000, NRC IN 89-64, NRC IN 98-36, NRC IN 2000-14, and NRC IN 2007-

01. 
NUREG-1801, Rev. 2 XI E4-4 December 2010

References

10 CFR Part 50, Appendix B, Quality Assurance criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

IEEE Std. 1205-2000, IEEE Guide for Assessing, Monitoring and Mitigating Aging Effects on 

Class 1E Equipment Used in Nuclear Power Generating Stations. 

NRC Information Notice 89-64, Electrical Bus Bar Failures, September 7, 1989.

NRC Information Notice 98-36, Inadequate or Poorly Controlled, Non-Safety-Related 

Maintenance Activities Unnecessary Challenged Safety Systems, September 18, 1998.

NRC Information Notice 2000-14, Non-Vital Bus Fault Leads to Fire and Loss of Offsite Power, 

September 27, 2000.

NRC Information Notice 2007-01, Recent Operating Experience Concerning Hydrostatic 

Barriers, January 31, 2007.

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.
December 2010 XI E5-1 NUREG-1801, Rev. 2

XI.E5 FUSE HOLDERS 

Program Description

The purpose of the aging management program (AMP) described herein is to provide 

reasonable assurance that the intended functions of the metallic clamps of fuse holders are 

maintained consistent with the current licensing basis through the period of extended operation.

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.

AMP XI.E1, “Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements,” manages the aging of insulating material but not the 

metallic clamps of the fuse holders. The AMP for fuse holders (metallic clamps) needs to 

account for the following aging stressors if applicable: increased resistance of connection due to 

chemical contamination, corrosion, and oxidation or fatigue caused by ohmic heating, thermal 

cycling, electrical transients, frequent manipulation, or vibration. AMP 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 chemical contamination, corrosion, oxidation, fatigue, or vibration

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 is 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 AMP is required to manage the aging effects. This AMP ensures that fuse 

holders will perform their intended function for the period of extended operation.

Evaluation and Technical Basis

1. Scope of Program: This AMP manages fuse holders (metallic clamps) located outside of 

active devices that are considered susceptible to the following aging effects: increased 

resistance of connection due to chemical contamination, corrosion, and oxidation or fatigue 

caused by ohmic heating, thermal cycling, electrical transients, frequent manipulation, or 

vibration. Fuse holders inside an active device (e.g., switchgear, power supplies, power 

inverters, battery chargers, and circuit boards) are not within the scope of this AMP.

2. Preventive Actions: This is a condition monitoring program and no actions are taken as 

part of this program to prevent or mitigate aging degradation.
NUREG-1801, Rev. 2 XI E5-2 December 2010

3. Parameters Monitored/Inspected: The metallic clamp portion of the fuse holder is tested to 

provide an indication of increased resistance of the connection due to chemical 

contamination, corrosion, and oxidation or fatigue caused by ohmic heating, thermal cycling, 

electrical transients, frequent manipulation or vibration.

4. Detection of Aging Effects: Fuse holders within the scope of license renewal are tested at 

least once every 10 years to provide an indication of the condition of the metallic clamp of 

the fuse holder. 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 provides 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 

prior to the period of extended operation.

5. Monitoring and Trending: Trending actions are not included as part of this AMP 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. The metallic clamp of the fuse 

holder needs to be below the maximum allowed temperature for the application when 

thermography is used; otherwise, a low resistance value appropriate for the application 

when resistance measurement is used.

7. Corrective Action: Corrective actions are taken and 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 for GALL, 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process.

9. Administrative Controls: The administrative controls for this AMP provide for a formal 

review and approval process. As discussed in the Appendix for GALL, 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. Operating experience in NUREG-1760 documented fuse holder 

failures due to fatigue and recommends maintenance procedures be reviewed to minimize 

removal and reinsertion of fuses to de-energize components (as this can lead to degradation 

of the fuse holders).

This AMP considers the technical information and guidance provided in NUREG-1760, IEEE

Std. 1205-2000, NRC IN 86-87, NRC IN 87-42, and NRC IN 91-78. 
December 2010 XI E5-3 NUREG-1801, Rev. 2

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

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 86-87, Loss of Offsite Power Upon an Automatic Bus Transfer, October 

10, 1986.

NRC Information Notice 87-42, Diesel Generator Fuse Contacts, September 4, 1987.

NRC Information Notice 91-78, Status Indication of Control Power for Circuit Breakers Used in 

Safety-Related Application, November 28, 1991.

NUREG-1760, Aging Assessment of Safety-Related Fuses Used in Low- and Medium-Voltage 

Applications in Nuclear Power Plants, May 31, 2002.

December 2010 XI E6-1 NUREG-1801, Rev. 2

XI.E6 ELECTRICAL CABLE CONNECTIONS NOT SUBJECT TO 10 CFR 50.49 

ENVIRONMENTAL QUALIFICATION REQUIREMENTS

Program Description

The purpose of the aging management program (AMP) described herein is to provide 

reasonable assurance that the intended functions of the metallic parts of electrical cable 

connections that are not subject to the environmental qualification requirements of 10 CFR 

50.49 and susceptible to age-related degradation resulting in increased resistance of connection 

due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, 

corrosion, or oxidation are maintained consistent with the current licensing basis through the

period of extended operation.

Cable connections are used to connect cable conductors to other cable conductors or electrical 

devices. Connections associated with cables within the scope of license renewal are part of this 

AMP. 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 AMP focuses on the metallic parts of the electrical 

cable connections. This AMP provides a one-time test, on a sampling basis, to ensure that 

either aging of metallic cable connections is not occurring and/or that the existing preventive 

maintenance program is effective such that a periodic inspection program is not required. The 

one-time test confirms the absence of age-related degradation of cable connections resulting in 

increased resistance of connection due to thermal cycling, ohmic heating, electrical transients, 

vibration, chemical contamination, corrosion, or oxidation.

AMP XI.E1, “Insulation Material for 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. AMP XI.E1 is based on a visual inspection of 

accessible cables and connections. Visual inspection may not be sufficient to detect the aging 

effects from thermal cycling, ohmic heating, electrical transients, vibration, chemical 

contamination, corrosion, or oxidation on the metallic parts of cable connections.

Electrical cable connections exposed to appreciable ohmic or ambient heating during operation 

may experience increased resistance of connection caused by repeated cycling of connected 

loads or of the ambient temperature environment. Different materials used in various cable 

system components can produce situations where stresses between these components change 

with repeated thermal cycling. For example, under loaded conditions, ohmic heating may raise 

the temperature of a compression terminal and cable conductor well above the ambient 

temperature, thereby causing thermal expansion of both components. Thermal expansion 

coefficients of different materials may alter mechanical stresses between the components and 

may adversely impact the termination. When the current is reduced, the affected components 

cool and contract. Repeated cycling in this fashion can cause loosening of the termination and 

may lead to increased resistance of connection or eventual separation of compression-type 

terminations. Threaded connectors may loosen if subjected to significant thermally-induced 

stress and cycling. 

Cable connections within the scope of license renewal should be tested at least once prior to 

the period of extended operation to provide an indication of the integrity of the cable 

connections. The specific type of test to be performed is a proven test for detecting increased 

resistance of connection, such as thermography, contact resistance testing, or another 

appropriate test. As an alternative to thermography or resistance measurement of cable 
NUREG-1801, Rev. 2 XI E6-2 December 2010

connections, for the accessible cable connections that are covered with insulation materials 

such as tape, the applicant may perform visual inspection of insulation material to detect aging 

effects for covered cable connections. When this alternative visual inspection is used to check 

cable connections, the applicant must use periodic inspections and cannot use a one-time test 

to confirm the absence of age-related degradation of cable connections. The basis for 

performing only a periodic visual inspection is documented.

This AMP, as described, is a sampling program. The following factors are considered for 

sampling: voltage level (medium and low voltage), circuit loading (high loading), connection type 

and location (high temperature, high humidity, vibration, etc.). The technical basis for the 

sample selections should be 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. The corrective action program is used to evaluate 

the condition and determine appropriate corrective action.

SAND96-0344, “Aging Management Guidelines for Electrical Cable and Terminations,” 

indicated that loose terminations were identified by several plants. The major concern is failures 

of a deteriorated cable system (cables, connections including fuse holders, and penetrations) 

that could prevent it from performing its intended function. This AMP is not applicable to cable 

connections in harsh environments since they are already addressed by the requirements of 10 

CFR 50.49. Even though cable connections may not be exposed to harsh environments, 

increased resistance of connection is a concern due to the aging mechanisms discussed above. 

Evaluation and Technical Basis

1. Scope of Program: Cable connections associated with cables within the scope of license 

renewal that are external connections terminating at active or passive devices, are in the 

scope of this AMP. Wiring connections internal to an active assembly are considered part of 

the active assembly and, therefore, are not within the scope of this AMP. This AMP does not 

include high-voltage (>35 kilovolts) switchyard connections. The cable connections covered 

under the Environmental Qualification (EQ) program are not included in the scope of this 

program.

2. Preventive Actions: This is a condition monitoring program, and no actions are taken as 

part of this program to prevent or mitigate aging degradation.

3. Parameters Monitored/Inspected: This AMP focuses on the metallic parts of the 

connection. The one-time testing verifies that increased resistance of connection due to 

thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, 

corrosion, or oxidation is not an aging effect that requires periodic testing. A representative 

sample of electrical cable connections is tested. The following factors are considered for 

sampling: voltage level (medium and low voltage), circuit loading (high load), connection 

type, and location (high temperature, high humidity, vibration, etc.). The technical basis for 

the sample selection is documented.

4. Detection of Aging Effects: A representative sample of electrical connections within the 

scope of license renewal is tested at least once prior to the period of extended operation to 

confirm that there are no aging effects requiring management during the period of extended 

operation. Testing may include thermography, contact resistance testing, or other 

appropriate testing methods without removing the connection insulation, such as heat shrink 

tape, sleeving, insulating boots, etc. The one-time test provides additional confirmation to 
December 2010 XI E6-3 NUREG-1801, Rev. 2

support industry operating experience that shows that electrical connections have not 

experienced a high degree of failures, and that existing installation and maintenance 

practices are effective. Twenty percent of the population with a maximum sample of 25 

constitutes a representative sample size. Otherwise a technical justification of the 

methodology and sample size used for selecting components for one-time test should be 

included as part of the AMP’s site documentation.

As an alternative to thermography or measuring connection resistance of the cable 

connection sample, for accessible cable connections that are covered with heat shrink tape, 

sleeving, insulating boots, etc., the applicant may use visual inspection of insulation 

materials to detect surface anomalies, such as embrittlement, cracking, chipping, melting, 

discoloration, swelling or surface contamination. When this alternative visual inspection is 

used to check cable connections, the first inspection is completed prior to the period of 

extended operation and every 5 years thereafter. The basis for performing only a periodic 

visual inspection to monitor age-related degradation of cable connections is documented.

5. Monitoring and Trending: Trending actions are not included as part of this AMP because it 

is a one-time testing or, alternatively, a periodic visual inspection program where the ability 

to trend inspection results is limited. However, results that are trendable provide additional 

information on the rate of degradation.

6. Acceptance Criteria: Cable connections should not indicate abnormal temperature for the 

application when thermography is used; otherwise a low resistance value appropriate for the 

application when resistance measurement is used. When the visual inspection alternative 

for covered cable connections is used, the absence of embrittlement, cracking, chipping, 

melting, discoloration, swelling or surface contamination indicates that the covered cable 

connection components are not loose.

7. Corrective Actions: If acceptance criteria are not met, the corrective action program is 

used to perform an evaluation that considers the extent of the condition, the indications of 

aging effect, and changes to the one-time testing program or alternative inspection program. 

Corrective actions may include, but are not limited to, sample expansion, increased 

inspection frequency, and replacement or repair of the affected cable connection 

components. As discussed in the Appendix for GALL, 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 for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process.

9. Administrative Controls: The administrative controls for this AMP provide for a formal 

review and approval process. As discussed in the Appendix for GALL, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the administrative 

controls.

10. Operating Experience: Electrical cable connections exposed to thermal cycling, ohmic 

heating, electrical transients, vibration, chemical contamination, corrosion, or oxidation

during operation may experience increased resistance of connection. There have been 

limited numbers of age-related failures of cable connections reported. An applicant’s 

operating experience with detection of aging effects should be adequate to demonstrate that 

the program is capable of detecting the presence or noting the absence of aging effects for 
NUREG-1801, Rev. 2 XI E6-4 December 2010

electrical cable connections where a one-time inspection is used to confirm the 

effectiveness of another preventive or mitigative AMP.

This AMP considers the technical information and guidance provided in NUREG/CR-5643, 

SAND96-0344, IEEE Std. 1205-2000, EPRI 109619, EPRI 104213, NEI White Paper on 

AMP XI.E6, Final License Renewal Interim Staff Guidance LR-ISG-2007-02, Staff Response 

to the NEI White Paper on AMP XI.E6, Licensee Event Report (LER) 361 2007005, LER 

3612007006 and LER 3612008006. 

References

10 CFR Part 50, Appendix B, Quality Assurance Criteria for Nuclear Power Plants, Office of the 

Federal Register, National Archives and Records Administration, 2009.

EPRI 104213, Bolted Joint Maintenance & Application Guide, Electric Power Research Institute, 

Palo Alto, CA, December 1995.

EPRI 109619, Guideline for the Management of Adverse Localized Equipment Environments, 

Electric Power Research Institute, Palo Alto, CA, June 1999.

Final License Renewal Interim Staff Guidance LR-ISG-2007-02: Changes to Generic Aging 

Lesson Learned (GALL) Report Aging Management Program (AMP) XI.E6, Electrical Cable 

Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements, 74 FR 

68287, U.S. Nuclear Regulatory Commission, December 23, 2009.

IEEE Std. 1205-2000, IEEE Guide for Assessing, Monitoring and Mitigating Aging Effects on 

Class 1E Equipment Used in Nuclear Power Generating Stations. 

Licensee Event Report 361 2007005, San Onofre Unit 2, Loose Electrical Connection Results in 

Inoperable Pump Room Cooler, U.S. Nuclear Regulatory Commission.

Licensee Event Report 3612007006, San Onofre Units 2 and 3, Loose Electrical Connection 

Results in One Train of Emergency Chilled Water (ECW) System Inoperable, U.S. Nuclear 

Regulatory Commission.

Licensee Event Report 3612008006, San Onofre 2, Loose Connection Bolting Results in 

Inoperable Battery and TS Violation, U.S. Nuclear Regulatory Commission.

NEI White Paper, GALL AMP XI.E6 (Electrical Cables), Nuclear Energy Institute, September 5, 

2006. (ADAMS Accession Number ML062770105)

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.

Staff’s Response to the NEI White Paper on Generic Aging Lessons Learned (GALL) Report 

Aging Management Program (AMP) XI.E6, Electrical Cable Connections Not Subject to 
December 2010 XI E6-5 NUREG-1801, Rev. 2

10 CFR 50.49 Environmental Qualification Requirements, U.S. Nuclear Regulatory 

Commission, March 16, 2007. (ADAMS Accession Number ML070400349)

December 2010 A-i NUREG-1801, Rev. 2

APPENDIX 

QUALITY ASSURANCE FOR 

AGING MANAGEMENT PROGRAMS 

December 2010 A-1 NUREG-1801, Rev. 2

QUALITY ASSURANCE FOR AGING MANAGEMENT PROGRAMS

The license renewal applicant must demonstrate that the effects of aging on structures and 

components (SC) subject to an aging management review (AMR) will be managed in a manner 

that is consistent with the CLB of the facility for the period of extended operation. Therefore, 

those aspects of the AMR process that affect the quality of safety-related SCs are subject to the 

quality assurance (QA) requirements of Appendix B to 10 CFR Part 50. For non-safety-related 

SCs 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 non-conformances, 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, the confirmation process 

element (Element 8) for license renewal AMPs consists of follow-up actions to verify that the 

corrective actions implemented are effective in preventing a recurrence. As an example, for the 

management of internal piping corrosion, the AMP XI.M2, “Water Chemistry,” may be used to 

minimize the piping’s susceptibility to corrosion. However, it also may be necessary to institute a 

condition monitoring program that uses ultrasonic inspection to verify that corrosion is indeed 

insignificant. 

• 10 CFR 50.34(b)(6)(i) requires that the final safety analysis report submitted by a nuclear 

power plant license applicant includes information on the applicant’s organizational 

structure, allocations of 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 for safe operation. 

Pursuant to 10 CFR 50.36(c)(5), administrative controls related to organization and 

management, procedures, record keeping, review and audit, and reporting ensure the safe 

operation of the facility. Programs that are consistent with the requirements of 10 CFR Part 

50, Appendix B, also satisfy the administrative controls element necessary for 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 SCs. 

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-safety-related SCs include alternative 

means to address corrective actions, confirmation processes, and administrative controls. Such 

alternate means are subject to review by the NRC on a case-by-case basis.




UNITED STATES 

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

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OFFICIAL BUSINESS
NUREG

-1801, Rev. 2

Final 

Generic Aging Lessons Learned (GALL) Report