NUREG-1801, Vol. 2

Generic Aging Lessons 

Learned (GALL) Report 

Tabulation of Results 

U.S. Nuclear Regulatory Commission 

Office of Nuclear Reactor Regulation 

Washington, DC 20555-0001
NUREG-1801, Vol. 2

Generic Aging Lessons 

Learned (GALL) Report 

Tabulation of Results

Manuscript Completed: April 2001 

Date Published: July 2001 

Division of Regulatory Improvement Programs 

Office of Nuclear Reactor Regulation 

U.S. Nuclear Regulatory Commission 

Washington, DC 20555-0001
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Abstract

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

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

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

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

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

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

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

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

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

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

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

of the GALL report information into the NUREG-1 800, "Standard Review Plan for Review of 

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

should improve the efficiency of the license renewal process.

April 2001 iii NUREG-1801
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NUREG-1801 iv April 2001
TABLE OF CONTENTS 

Abstract ........................................................................................................................ ii 

List of Contributors - 1999-2001 ............................................................................... . ix 

Abbreviations ............................................................................................................... xiii 

Introduction .................................................................................................................. 

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

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

A Pressurized W ater Reactor (PW R) Containments .................................... II A-i 

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

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

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

B Boiling W ater Reactor (BW R) Containments ............................................ II B-i 

B1 Mark I Containments ........................................................................ II 81-1 

B2 Mark II Containments ....................................................................... II 82-1 

B3 Mark III Containments ...................................................................... II 83-1 

B4 Common Components ..................................................................... II 84-1 

II1. Structures and Component Supports ................................................................ Ill-i 

A Class 1 Structures .................................................................................... Ill A-i 

Al Group 1 Structures (BWR Reactor Building, PWR Shield 

Building, Control Room/Building) ..................................................... Ill Al-1 

A2 Group 2 Structures (BWR Reactor Building with Steel 

Superstructure) ................................................................................ Ill A2-1 

A3 Group 3 Structures (Auxiliary Building, Diesel Generator 

Building, Radwaste Building, Turbine Building, Switchgear 

Room, AFW Pumphouse, Utility/Piping Tunnels) ............................. Ill A3-1 

A4 Group 4 Structures (Containment Internal Structures, 

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

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

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

A7 Group 7 Structures (Concrete Tanks) .............................................. Ill A7-1 

A8 Group 8 Structures (Steel Tanks) ..................................................... Ill A8-1 

A9 Group 9 Structures (BW R Unit Vent Stack) ...................................... Ill A9-1 

B Component Supports ................................................................................ Ill B-i 

81 Supports for ASME Piping and Components ................................... III 81-1 

B2 Supports for Cable Trays, Conduit, HVAC Ducts, Tube Track, 

Instrument Tubing, Non-ASME Piping and Components ................. III 82-1 

B3 Anchorage of Racks, Panels, Cabinets, and Enclosures 

for Electrical Equipment and Instrumentation ................................... III 83-1

April 2001 V NUREG-1801
IIl. Structures and Component Supports (continued)

B4 Supports for Emergency Diesel Generator (EDG), 

HVAC System Components, and Other Miscellaneous 

Mechanical Equipment .................................................................... Ill B4-1 

B5 Supports for Platforms, Pipe Whip Restraints, Jet Impingement Shields, Masonry Walls, and Other Miscellaneous Structures .......... Ill B5-1 

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

Al Reactor Vessel (BW R) ............................................................................ IV Al-1 

A2 Reactor Vessel (PW R) ............................................................................. IV A2-1 

B1 Reactor Vessel Intemals (BW R) ............................................................... IV 81-1 

B2 Reactor Vessel Internals (PW R) - W estinghouse ...................................... IV B2-1 

B3 Reactor Vessel Internals (PW R) - Combustion Engineering ..................... IV 83-1 

B4 Reactor Vessel Internals (PW R) - Babcock and W ilcox ............................ IV 84-1 

C1 Reactor Coolant Pressure Boundary (BW R) ............................................. IV C1-1 

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

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

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

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

A Containment Spray System (PW R) .......................................................... V A-1 

B Standby Gas Treatment System (BW R) ................................................. V B-1 

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

D1 Emergency Core Cooling System (PW R) ................................................. V D1-1 

D2 Emergency Core Cooling System (BW R) .............................................. V D2-1 

E Carbon Steel Components ....................................................................... V E-1 

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

A Electrical Cables and Connections Not Subject to 10 CFR 50.49 

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

B Equipment Subject to 10 CFR 50.49 Environmental 

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

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

Al New Fuel Storage ..................................................................................... VII Al-1 

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

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

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

A5 Suppression Pool Cleanup System (BW R) ............................................... 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 W ater System ........................................................ VII C2-1 

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

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

El Chemical and Volume Control System (PW R) .......................................... VII E1-1

NUREG-1801 Vi April 2001
VII. Auxiliary Systems (continued)

E2 Standby Liquid Control System (BW R) .................................................... VII E2-1 

E3 Reactor W ater Cleanup System (BW R) ................................................... VII E3-1 

E4 Shutdown Cooling System (Older BW R) ................................................... VII E4-1 

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

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

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

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

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

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

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

I Carbon Steel Components ....................................................................... VII I-1 

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

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

Bi Main Steam System (PW R) ................................................................... VIII B1-1 

B2 Main Steam System (BW R) ................................................................... VIII B2-1 

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

D1 Feedwater System (PW R) ........................................................................ VIII D1-1 

D2 Feedwater System (BW R) ........................................................................ Viii D2-1 

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

F Steam Generator Blowdown System (PW R) ............................................. VIII F-1 

G Auxiliary Feedwater System (PW R) .......................................................... VIII G-1 

H Carbon Steel Components ....................................................................... VIII H-1 

IX. NOT USED ............................................................................................................ IX-i 

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

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

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

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

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

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

XI.M1 ASME Section XI Inservice Inspection, 

Subsections IW B, IW C, and IW D .............................................................. XI M-1 

XI.M2 W ater Chemistry ....................................................................................... Xl M-10 

XI.M3 Reactor Head Closure Studs .................................................................... XI M-15 

XI.M4 BW R Vessel ID Attachment W elds ........................................................... XI M-17 

XI.M5 BW R Feedwater Nozzle ........................................................................... XI M-20 

XI.M6 BW R Control Rod Drive Return Line Nozzle ............................................. XI M-22 

XI.M7 BW R Stress Corrosion Cracking ............................................................... XI M-24 

XI.M8 BW R Penetrations .................................................................................... XI M-28 

XI.M9 BW R Vessel Internals ............................................................................... XI M-32 

XI.M10 Boric Acid Corrosion ................................................................................. XI M-39 

XI.M1 1 Nickel-Alloy Nozzles and Penetrations ..................................................... XI M-41

April 2001 vii NUREG-1801
Xl. Aging Management Programs (AMPs) (continued)

XI.M12 Thermal Aging Embrittlement of Cast Austenitic 

Stainless Steel (CASS) ............................................................................. XI M-44 XI.M13 Thermal Aging and Neutron Irradiation Embrittlement 

of Cast Austenitic Stainless Steel (CASS) ................................................ Xl M-47 XI.M14 Loose Part Monitoring ............................................................................... XI M-50 

Xi.M15 Neutron Noise Monitoring ......................................................................... Xl M-52 

XI.M16 PW R Vessel Internals ............................................................................... Xl M-55 

XI.M17 Flow-Accelerated Corrosion ...................................................................... XI M-58 

XI.M18 Bolting Integrity ......................................................................................... Xl M-61 XI.M19 Steam Generator Tube Integrity ............................................................... Xl M-64 

XI.M20 Open-Cycle Cooling W ater System .......................................................... XI M-68 

XI.M21 Closed-Cycle Cooling W ater System ........................................................ XI M-71 

XI.M22 Boraflex Monitoring ................................................................................... XI M-73 

XI.M23 Inspection of Overhead Heavy Load and Light Load 

(Related to Refueling) Handling Systems ................................................. XI M-76 XI.M24 Compressed Air Monitoring ...................................................................... XI M-78 XLM25 BW R Reactor W ater Cleanup System ...................................................... XI M-81 

XI.M26 Fire Protection .......................................................................................... Xl M-84 

XI.M27 Fire W ater System .................................................................................... XI M-87 

XI.M28 Buried Piping and Tanks Surveillance ...................................................... XI M-89 XI.M29 Aboveground Carbon Steel Tanks ............................................................ XI M-91 

XI.M30 Fuel Oil Chemistry .................................................................................... Xl M-93 XI.M31 Reactor Vessel Surveillance ..................................................................... XI M-95 

XI.M32 One-Time Inspection ................................................................................ XI M-98 XI.M33 Selective Leaching of Materials ................................................................ XI M-101 XI.M34 Buried Piping and Tanks Inspection .......................................................... XI M-103 

XI.S1 ASME Section XI, Subsection IW E ......................................................... Xl S-1 XI.S2 ASME Section Xl, Subsection IW L .......................................................... XI S-6 

XI.S3 ASME Section Xl, Subsection IW F .......................................................... XI S-10 

XI.S4 10 CFR 50, Appendix J ............................................................................ XI S-14 XI.S5 Masonry W all Program ............................................................................ XI S-17 

XI.S6 Structures Monitoring Program ................................................................ Xl S-19 

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

Associated with Nuclear Power Plants ..................................................... XI S-21 

XI.S8 Protective Coating Monitoring and Maintenance Program ....................... XI S-24 

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

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

XI.E2 Electrical Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Used in Instrumentation Circuits .................... XI E-4 

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

Environmental Qualification Requirements ............................................... XI E-6 

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

NUREG-1801 viii April 2001
LIST OF CONTRIBUTORS - 1999-2001

License Renewal and Standardization Branch 

Office of Nuclear Reactor Regulation 

P. T. Kuo Section Chief 

S. Lee Team Leader

R. Anand 

T. Bloomer 

S. Chey 

M. Comar 

J. Dozier 

R. Franovich 

S. Green 

S. Hoffman 

P. Kang 

E. Kleeh 

S. Koenick 

W. Liu 

S. K. Mitra 

K. Rico 

D. Solorio 

J. Strnisha 

0. Tabatabai-Yazdi 

H. Wang 

Office of Nuclear Reactor

Technical Support 

Technical Coordination (on rotation) 

Clerical Support 

Technical Support (on rotation) 

Technical Coordination 

Technical Coordination (on rotation) 

Clerical Support 

Technical Support 

Technical Coordination 

Technical Coordination (on rotation) 

Technical Support 

Technical Support 

Technical Coordination 

Technical Coordination 

Technical Coordination 

Technical Coordination 

Technical Coordination 

Technical Support 

Reaulation

H. Ashar 

G. Bagchi 

M. Banic 

C. Berlinger 

C. Carpenter 

P. Y. Chen 

T. Cheng 

S. Coffin 

J. Davis 

D. Dorman 

T. Eaton 

B. Elliot 

J. Fair 

D. Frumkin 

G. Galletti 

G. Georgiev 

C. Gratton 

F. Grubelich 

M. Hartzman 

R. Hermann 

A. Hiser 

C. Holden

Structural Engineering 

Technical Coordination 

Materials Engineering 

Technical Coordination 

Materials Engineering 

Technical Coordination 

Structural Engineering 

Materials Engineering 

Materials Engineering 

Quality Assurance 

Plant Systems Engineering 

Materials Engineering 

Mechanical Engineering 

Plant Systems Engineering 

Quality Assurance 

Materials Engineering 

Plant Systems Engineering 

Mechanical Engineering 

Mechanical Engineering 

Materials Engineering 

Materials Engineering 

Electrical Engineering

NUREG-1801

S. . ... . . . . . . la... . .

April 2001 ix
LIST OF CONTRIBUTORS - 1999-2001 (continued) 

Office of Nuclear Reactor Regulation (continued)

S. Hou 

N. lqbal 

D. Jeng 

K. Karwoski 

Y. Kim 

W. Koo 

C. Lauron 

A. Lee 

Y. Li 

J. Ma 

K. Manoly 

J. Medoff 

K. Parczewski 

P. Patnaik 

J. Peralta 

J. Rajan 

P. Shemanski 

E. Sullivan 

J. Tatum 

B. Thomas 

E. Weiss 

S. West 

K. Wichman

Materials Engineering 

Plant Systems Engineering 

Structural Engineering 

Materials Engineering 

Structural Engineering 

Materials Engineering 

Materials Engineering 

Structural Engineering 

Mechanical Engineering 

Structural Engineering 

Structural Engineering 

Materials Engineering 

Chemical Engineering 

Material Engineering 

Quality Assurance 

Mechanical Engineering 

Electrical Engineering 

Materials Engineering 

Plant Systems Engineering 

Plant Systems Engineering 

Plant Systems Engineering 

Plant Systems Engineering 

Materials Engineering

Office of Nuclear Regulatory Research

Team Leader

A. Beranek 

J. Boardman 

J. Costello 

M. Dey 

0. Gormley 

H. Graves 

C. Hsu 

D. Jackson 

B. Jones 

M. Kirk 

R. Lloyd 

M. McNeil 

J. Muscara 

H. Ornstein 

S. Pullani 

A. Serkiz 

K. Shaukat 

M. Wegner

Technical Editor 

Reactor Systems Engineering 

Structural Engineering 

Reliability and Risk Analyst 

Mechanical Engineering 

Structural Engineering 

Mechanical Engineering 

Materials Engineering 

Nuclear Engineering 

Materials Engineering 

Reactor Systems Engineering 

Materials Engineering 

Metallurgical Engineering 

Reactor Systems Engineering 

Reactor Systems Engineering 

Mechanical Engineering 

Mechanical Engineering 

Reactor Systems Engineering

NUREG-1 801 April 2001

J. Vora

X
LIST OF CONTRIBUTORS - 1999-2001 (continued)

- Office of the General Counsel

J. Euchner 

B. Poole 

R. Weisman 

M. Young

Legal Counsel 

Legal Counsel 

Legal Counsel 

Legal Counsel

Argonne National Laboratory

Y. Y. Liu Principal Investigator

K. Brown 

0. Chopra 

D. Diercks 

R. Fabian 

D. Henley 

A. Hull 

L. Kickels 

D. Ma 

J. Robson 

L. Salinas 

K. Schroeder 

R. Seidensticker 

W. Shack 

V. Skonicki 

V. Shah 

B. Shelton 

S. Tam

Technical Editor 

Materials Engineering 

Materials Engineering 

Quality Assurance 

Mechanical Engineering 

Materials Engineering 

Clerical Support 

Mechanical Engineering 

Clerical Support 

Clerical Support 

Clerical Support 

Mechanical Engineering 

Materials Engineering 

Clerical Support 

Materials and Mechanical Engineering 

Reactor and Plant Systems Engineering 

Materials Engineering

Brookhaven National Laboratory

R. Morante 

P. Bezler 

J. Braverman 

G. DeGrassi 

C. Hofmayer 

R. Lofaro 

S. Shteyngart 

S. Signorelli 

M. Subudhi 

M. Villaran 

J. Xu

Principal Investigator 

Mechanical Engineering 

Containment Structures 

Mechanical Engineering 

Structural Engineering 

Electrical Components 

Clerical Support 

Clerical Support 

Mechanical Engineering 

Electrical Engineering 

Structural Engineering

April 2001 xi NUREG-1801
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NUREG-1801 April 2001 xii
ABBREVIATIONS

ACI American Concrete Institute 

ADS automatic depressurization system 

AFW auxiliary feedwater 

ALARA as low as reasonably achievable 

AMP aging management program 

AMR aging management review 

ANSI American National Standards Institute 

ASCE American Society of Civil Engineers 

ASME American Society of Mechanical Engineers 

ASTM American Society for Testing and Materials 

B&PV boiler and pressure vessel 

B&W Babcock & Wilcox 

BWR boiling water reactor 

BWRVIP Boiling Water Reactor Vessel and Internals Project 

CASS cast austenitic stainless steel 

CB core barrel 

CCCW closed-cycle cooling water 

CE Combustion Engineering 

CEA control element assembly 

CEDM control element drive mechanism 

CFR Code of Federal Regulations 

CFS core flood system 

CLB current licensing basis 

CRD control rod drive 

CRDM control rod drive mechanism 

CRDRL control rod drive return line 

CRGT control rod guide tube 

CVCS chemical and volume control system 

DC direct current 

DHR decay heat removal 

DSCSS drywell and suppression chamber spray system 

ECP electrochemical potential 

EDG emergency diesel generator 

EFPD effective full power day 

EPRI Electric Power Research Institute 

EQ environmental qualification 

FAC flow-accelerated corrosion 

FERC Federal Energy Regulatory Commission 

FSAR Final Safety Analysis Report 

FW feedwater 

GALL Generic Aging Lessons Learned 

GE General Electric 

GL generic letter

April 2001 NUREG-1801 xiii
ABBREVIATIONS (continued)

HELBs high-energy line breaks 

HP high pressure 

HPCI high-pressure coolant injection 

HPCS high-pressure core spray 

HPSI high-pressure safety injection 

HVAC heating, ventilation, and air conditioning 

I&C instrumentation and control 

IASCC irradiation assisted stress corrosion cracking 

IC isolation condenser 

ID inside diameter 

IEB inspection and enforcement bulletin 

IEEE Institute of Electrical and Electronics Engineers 

IGA intergranular attack 

IGSCC intergranular stress corrosion cracking 

IN information notice 

INPO Institute of Nuclear Power Operations 

IPA integrated plant assessment 

IR insulation resistance 

IRM intermediate range monitor 

ISI inservice inspection 

ITG Issues Task Group 

LER licensee event report 

LG lower grid 

LOCA loss of coolant accident 

LP low pressure 

LPCI low-pressure coolant injection 

LPCS low-pressure core spray 

LPM loose part monitoring 

LPRM low-power range monitor 

LPSI low-pressure safety injection 

LRT leak rate test 

LWR light water reactor 

MFW main feedwater 

MIC microbiologically influenced corrosion 

MS main steam 

MSR moisture separator/reheater 

MT magnetic particle testing 

NDE nondestructive examination 

NEI Nuclear Energy Institute 

NFPA National Fire Protection Association 

NPAR nuclear plant aging research 

NPS nominal pipe size 

NRC Nuclear Regulatory Commission 

NRMS normalized root mean square

NUREG-1801 xiv April 2001
ABBREVIATIONS (continued)

NSAC Nuclear Safety Analysis Center 

NSSS nuclear steam supply system 

NUMARC Nuclear Management and Resources Council 

OCCW open-cycle cooling water 

OD outside diameter 

ODSCC outside diameter stress corrosion cracking 

OM operation and maintenance 

PT penetrant testing 

PWR pressurized water reactor 

PWSCC primary water stress corrosion cracking 

QA quality assurance 

RCCA rod control cluster assemblies 

RCIC reactor core isolation cooling 

RCP reactor coolant pump 

RCPB reactor coolant pressure boundary 

RCS reactor coolant system 

RG Regulatory Guide 

RHR residual heat removal 

RICSIL rapid information communication services information letter 

RMS root mean square 

RWC reactor water cleanup 

RWST refueling water storage tank 

RWT refueling water tank 

SAW submerged arc weld 

SC suppression chamber 

SCC stress corrosion cracking 

SDC shutdown cooling 

SFP spent fuel pool 

SG steam generator 

S/G standards and guides 

SIL services information letter 

SIT safety injection tank 

SLC standby liquid control 

SOER significant operating experience report 

SRM source range monitor 

SRM staff requirements memorandum 

SRP-LR standard review plan for license renewal 

SS stainless steel 

SSC systems, structures, and components 

TGSCC transgranular stress corrosion cracking 

TLAA time-limited aging analysis

April 2001 XV NUREG-1801
ABBREVIATIONS (continued)

UCS Union of Concerned Scientists 

UHS ultimate heat sink 

USI unresolved safety issue 

UT ultrasonic testing 

UV ultraviolet

NUREG-1801 xvi April 2001
INTRODUCTION

The GALL report, Volume 2 contains 11 chapters and an appendix. The majority of the chapters contain summary descriptions and tabulations of evaluations of aging management programs for a large number of structures and components in the various major plant systems in the light water reactor nuclear power plants. The major plant systems include the containment structures 

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

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

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

system (Chapter VIII). 

Also in Volume 2 of the GALL report, Chapter I addresses the application of the ASME Code for license renewal. Chapter IX is not used. Chapter X contains the time-limited aging analysis evaluation of aging management programs under 10 CFR 54.21 (c)(1)(iii). Chapter Xl contains 

the aging management programs for the structures and mechanical and electrical components. The Appendix of Volume 2 of the GALL report addresses quality assurance (QA) for aging 

management programs. 

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

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

April 2001 NUREG-1801 1
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2 NUREG-1801 April 2001
CHAPTER I 

APPLICATION OF THE ASME CODE

April 2001 1-i NUREG-1 801
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NUREG-1801 I-ii April 2001
APPLICATION OF THE ASME CODE

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

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

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

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

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

(June 12, 1971)]. 

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

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

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

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

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

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

the time the equipment is purchased[.]" 

The SOC also states: 

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

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

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

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

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

the codes at the earliest feasible time." 

In addition, the SOC states: 

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

intended to insure a basic, sound quality level." 

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

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

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

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

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

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

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

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

amendment was in 1999 [64 FR 51,370 (September 22,1999)]. In 1996, the NRC also 

incorporated Subsections IWE and IWL of Section XI of the ASME code into the regulations for 

containment inservice inspection, after evaluating these code requirements and concluding that 

they are effective in managing aging degradation of the containment structures [61 FR 41,303 

(August 8, 1996)]. 

For the purpose of license renewal, the staff has extensively evaluated the appropriate ASME 

Section XI programs based on the ten program elements described in Volume 1 of this report. Except where noted, the staff has determined that the ASME Section XI programs provide 

processes for identifying degradation that is attributable to applicable aging effects and are

April 2001 1-1 NUREG-1801
therefore acceptable for managing the effects of aging during the period of extended operation. Where warranted, NRC indicates that certain parts of the code programs should be augmented to satisfy aging management requirements for license renewal. When future editions of the 

ASME code are incorporated into NRC regulations through rulemakings to amend 10 CFR 50.55a, NRC will, as part of that process, perform an evaluation of these later editions of the ASME code for their adequacy for license renewal by using the 10 elements for program evaluation described in Volume 1 of this report.

NUREG-1 801 April 2001 1-2
CHAPTER II 

CONTAINMENT STRUCTURES

April 2001 1I-i N UREG-1801
This Page Intentionally Left Blank

NUREG-1801

April 2001 II-ii
CONTAINMENT STRUCTURES

A. Pressurized Water Reactor (PWR) Containments 

B. Boiling Water Reactor (BWR) Containments

April 2001 II-iii NUREG-1801
This Page Intentionally Left Blank

NUREG-1 801 ll-iv April 2001
PWR CONTAINMENTS

Al. Concrete Containments (Reinforced and Prestressed) 

A2. Steel Containments 

A3. Common Components

April 2001 11 A-i NUREG-1801
This Page Intentionally Left Blank

NUREG-1801 April 2001 11 A-ii
Al. CONCRETE CONTAINMENTS (REINFORCED AND PRESTRESSED) 

A1.1 Concrete Elements 

A1.2 Steel Elements 

A1.3 Prestressing System

April 2001 II A1-1 NUREG-1 801
Al. CONCRETE CONTAINMENTS (REINFORCED AND PRESTRESSED) 

Systems, Structures, and Components 

This section addresses the elements of PWR concrete containment structures. Concrete 

containment structures are divided into three elements: concrete, steel, and prestressing 

system. 

System Interfaces 

Functional interfaces include the primary containment heating and ventilation system (Vil.F3), containment isolation system (V.C), and containment spray system (V.A). Physical interfaces 

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

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

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

typically provides support to the NSSS components and containment internal structures.

NUREG-1801 April 2001 11 A1-2
( 

II Containment Structures Al. PWR Concrete Containments (Reinforced and Prestressedl

(

0 

0o

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

Al.1-a Concrete elements: Concrete Outside Loss of material Chapter XI.S2, "ASME Section XI, No 

containment (spalling, scaling) Subsection IWL" 

Dome; wall; basemat; ring and cracking / 

girder; buttresses Freeze-thaw As described in NUREG-1557, freeze

thaw does not cause loss of material 

from reinforced concrete in foundations, 

and in above and below grade exterior 

concrete, for plants located in a 

geographic region of negligible 

weathering conditions (weathering index 

<100 day-inch/yr). Loss of material from 

such concrete is not significant at plants 

located in areas in which weathering 

conditions are severe (weathering index 

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

day-inch/yr), provided that the concrete 

mix design meets the air content 

(entrained air 3-6%) and water-to

cement ratio (0.35-0.45) specified in 

ACI 318-63 (or later edition) or ACI 349

85 (or later edition). 

The weathering index is defined in 

ASTM C33-90, Table 3, Footnote E. 

Fig. 1 of ASTM C33-90 illustrates the 

various weathering index regions 

throughout the U.S. A1.1-b Concrete elements: Concrete Outside Increase in Chapter XI.S2, "ASME Section XI, Yes, if 

containment porosity, Subsection IWL" leaching of 

Dome; wall; basemat; ring permeability / calcium 

girder; buttresses Leaching of Accessible Areas: hydroxide 

calcium hydroxide Leaching of calcium hydroxide from is signifi reinforced concrete becomes significant cant for 

only if the concrete is exposed to flowing inaccess

I Iwater. Even if reinforced concrete is ible areas

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11 Containment Structures Al. PWR Concrete Containments/(Reinfore==d nnd Pre~trA~d•

z 

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism _Aging Management Program (AMP) Evaluation 

(continued) 

exposed to flowing water, such leaching 

is not significant if the concrete is 

constructed to ensure that it is dense, 

well-cured, has low permeability, and 

that cracking is well controlled. Cracking 

is controlled through proper 

arrangement and distribution of 

reinforcing bars. All of the above 

characteristics are assured if the 

concrete was constructed with the 

guidance of ACI 201.2R-77. Inspections 

performed in accordance with IWL will 

indicate the absence or presence of 

leaching of calcium hydroxide. 

Inaccessible Areas: 

For below-grade inaccessible areas 

(basemat and concrete wall), a plant specific aging management program is 

required only if the above conditions are 

not satisfied. 

A1.1-c Concrete elements: Concrete Inside or Increase in Chapter XI.S2, "ASME Section Xl, Yes, if 

outside porosity and Subsection IWL" aggressive Dome; wall; basemat; ring containment permeability, chemical 

girder; buttresses cracking, loss of Accessible Areas: attack is 

material (spalling, For interior and above-grade exterior significant 

scaling) / reinforced concrete, aggressive for 

Aggressive chemical attack is not significant if the inaccess

chemical attack concrete is not exposed to an ible areas 

aggressive environment (pH < 5.5), or to 

chloride or sulfate solutions beyond 

defined limits (> 500 ppm chloride, or > 

1,500 ppm sulfate). Inspections 

performed in accordance with IWL will

0 

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11

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Containment Structures 

Al PWIR C~nnn~rte_ Cnnta•inm~nt• IRainfnreed and Prestressed•

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C. 

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0

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

indicate the absence or presence of 

aggressive chemical attack. 

Inaccessible Areas: 

For below-grade exterior reinforced 

concrete (basemat, embedded walls), a 

plant-specific aging management 

program is required only if the below

grade environment is aggressive (pH < 

5.5, chlorides > 500 ppm, or sulfates > 

1,500 ppm). Examination of 

representative samples of below-grade 

concrete, when excavated for any 

reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of below

grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade 

environment is not aggressive. 

Al.1-d Concrete elements: Concrete Inside or Cracking due to Chapter XI.S2, "ASME Section XI, No 

outside expansion / Subsection IWL" 

Dome; wall; basemat; ring containment Reaction with 

girders; buttresses aggregates As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates performed 

in accordance with ASTM C295-54 or 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

_reinforced concrete. For potentially
11 Containment Structures Al. PWR Concrete Containments (Reinforced and Prestressed• z 

C 

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0 

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0o 

r-3 

0 

0

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

reactive aggregates, aggregate reinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with the 

guidance of ACI 201.2R-77. Inspections 

performed in accordance with IWL will 

indicate the absence or presence of 

surface degradation due to reaction with 

aggregates. Al.1-e Concrete elements: Concrete; Inside or Cracking, loss of Chapter XI.S2, "ASME Section XI, Yes, if 

carbon outside bond, and loss of Subsection IWL" corrosion Dome; wall; basemat; ring steel containment material (spalling, of girders; buttresses; reinforcing scaling) / Accessible Areas: embedded steel Corrosion of For exterior above-grade and interior steel is 

embedded steel embedded steel, corrosion is not significant significant if the steel is not exposed to for 

an aggressive environment (concrete pH inaccess

< 11.5 or chlorides > 500 ppm). ible areas 

Alternatively, if the environment 

surrounding the concrete is not 

aggressive (pH > 5.5, chlorides < 500 

ppm, sulfates < 1,500 ppm), corrosion of 

embedded steel is not significant. If such 

steel is exposed to an aggressive 

environment, corrosion is not significant 

if the concrete in which the steel is 

embedded has a low water-to-cement 

ratio (0.35-0.45), adequate air 

entrainment (3-6%), low permeability, 

and is designed in accordance with ACI 

318-63 (or later edition) or ACI 349-85 

(or later edition). Inspections performed 

in accordance with IWL will indicate the _ absence or presence of visible corrosion
( 

II Containment Structures Al. PWR Concrete Containments (Reinforced end Prestressed•

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

of embedded steel. 

Inaccessible Areas: 

For below-grade exterior reinforced 

concrete (basemat, embedded walls), a 

plant-specific aging management 

program is required only if the below

grade environment is aggressive (pH < 

5.5, chlorides > 500 ppm, or sulfates > 

1,500 ppm). Examination of 

representative samples of below-grade 

concrete, when excavated for any 

reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of below

grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade 

environment is not aggressive. 

Al.1-f Concrete elements: Concrete Inside or Cracks; distortion; Chapter XI.S6, "Structures Monitoring No, if 

outside increase in Program" within the 

Dome; wall; basemat; ring containment component stress scope of 

girder; buttresses level / The initial licensing basis for some the 

Settlement plants included a program to monitor applicant's 

settlement. If no settlement was evident structures 

during the first decade or so, the NRC monitoring 

may have given the licensee approval to program 

discontinue the program. However, if a 

de-watering system is relied upon for 

I control of settlement, then the licensee
z 

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OD 

0

Containment Structures 

Al. PWR Concrete Containments (Reinforced and Prretressed) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

is to ensure proper functioning of the de

watering system through the period of 

extended operation. Al.1-g Concrete elements: Concrete; Flowing water Reduction in Chapter XI.S6, "Structures Monitoring No, if 

porous under foundation Program" within the Foundation; subfoundation concrete foundation strength, cracking, scope of 

differential Erosion of cement from porous concrete the 

settlement / subfoundations beneath containment applicant's Erosion of porous basemats is described in IN 97-11. IN structures 

concrete 98-26 proposes Maintenance Rule monitoring subfoundation Structures Monitoring for managing this program aging effect, if applicable. If a de

watering system is relied upon for 

control of erosion of cement from porous 

concrete subfoundations, then the 

licensee is to ensure proper functioning 

of the de-watering system through the 

period of extended operation. Al.1-h Concrete elements: Concrete Inside or Reduction of Plant-specific aging management Yes, if 

outside strength and program applicable. Dome; wall; basemat; ring containment modulus / 

girder; buttresses Elevated The implementation of 10 CFR 50.55a 

temperature and IWL would not be able to identify the 

(>1 50°F general; reduction of strength and modulus due 

>200°F local) to elevated temperature. Thus, for any portions of concrete containment that 

exceed specified temperature limits, 

further evaluations are warranted. 

Subsection CC-3400 of ASME 

Section III, Division 2, specifies the 

concrete temperature limits for normal 

operation or any other long-term period. The temperatures shall not exceed 

150 0F except for local areas, such as

0 0o
11 Containment Structures 

Al. PWR Concrete Containments (Reinforced and Prestressed)

(

•> 

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0 

.- J2

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

around penetrations, which are not 

allowed to exceed 2000F. If significant 

equipment loads are supported by 

concrete at temperatures exceeding 

1500F, an evaluation of the ability to 

withstand the postulated design loads is 

to be made. 

Higher temperatures than given above 

may be allowed in the concrete if tests 

and/or calculations are provided to 

evaluate the reduction in strength and 

this reduction is applied to the design 

allowables. 

A1.2-a Steel elements: Carbon Inside or Loss of material / Chapter XI.Sl, "ASME Section XI, Yes, if 

steel outside Corrosion Subsection IWE" corrosion 

Liner; liner anchors; integral containment is 

attachments For inaccessible areas (embedded significant 

containment steel shell or liner), loss of for 

material due to corrosion is not inaccess

significant if the following conditions are ible areas 

satisfied: 

1. Concrete meeting the requirements 

of ACI 318 or 349 and the guidance of 201.2R was used for the 

containment concrete in contact with 

the embedded containment shell or 

liner. 

2. The concrete is monitored to ensure 

that it is free of penetrating cracks 

that provide a path for water 

seepage to the surface of the 

containment shell or liner.
11 Containment Structures 

Al. PWR Concrete Containments (Reinforced and Prestressed)

z 

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00 

0 

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0

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

3. The moisture barrier, at the junction 

where the shell or liner becomes 

embedded, is subject to aging 

management activities in 

accordance with IWE requirements. 

4. Borated water spills and water 

ponding on the containment 

concrete floor are not common and 

when detected are cleaned up in a 

timely manner. 

If any of the above conditions cannot be 

satisfied, then a plant-specific aging 

management program for corrosion is 

required. 

Chapter XI.S4, "10 CFR Part 50, No 

Appendix J" and 

If a coatings program is credited for No 

managing loss of material due to 

corrosion during the current licensing 

term (e.g., relief request from IWE), then 

it is to be continued during the period of 

extended operation. See Chapter XI.S8, 

"Protective Coating Monitoring and 

Maintenance Program." A1.3-a Prestressing system: Carbon Inside or Loss of material / Chapter XI.S2, "ASME Section XI, No 

steel outside Corrosion Subsection IWL" 

Tendons; anchorage containment 

components I
(

Containment Structures Al. PWR Concrete Contninments/(Reinforced nnd Preetreem•d•

(V

11 V> 

0 0~

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A1.3-b Prestressing system: Carbon Inside or Loss of prestress / Loss of tendon prestress is a time- Yes, 

steel outside Relaxation; limited aging analysis (TLAA) to be TLAA 

Tendons; anchorage containment shrinkage; creep; evaluated for the period of extended 

components elevated operation. See the Standard Review 

temperature Plan, Section 4.5, "Concrete 

Containment Tendon Prestress" for 

acceptable methods for meeting the 

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

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

for meeting the requirements of 

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

For periodic monitoring of prestress, see 

Chapter XI.S2.

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This Page Intentionally Left Blank 

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A2. STEEL CONTAINMENTS 

A2.1 Steel Elements 

A2.2 Concrete Elements

April 2001 11 A2-1 NUREG-1801
A2. STEEL CONTAINMENTS

Systems, Structures, and Components 

This section addresses the elements of PWR steel containment structures. Steel containment 

structures are divided into two elements: steel and concrete. 

System Interfaces 

Functional interfaces include the primary containment heating and ventilation system (VII.F3), containment isolation system (V.C), and containment spray system (V.A). Physical interfaces exist with any structure, system, or component that either penetrates the containment wall, such 

as the main steam system (VIII.B1) and feedwater system (VIII.D1), or is supported by the containment structure, such as the polar crane (VII.B). The containment structure basemat typically provides support to the NSSS components and containment internal structures.

NUREG-1801 April 2001 11 A2-2
II Containment Structures 

A2. PWR Steel Containments

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation

M 

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C., 

M 

m 

00 

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A2.1-a Steel elements: Ca'rbon Inside or Loss of material / Chapter XI.S1, "ASME Section XI, Yes, if 

steel outside Corrosion Subsection IWE" corrosion 

Dome; wall; embedded floor containment is 

For inaccessible areas (embedded significant 

containment steel shell or liner), loss of for 

material due to corrosion is not inaccess

significant if the following conditions are ible areas 

satisfied: 

1. Concrete meeting the requirements 

of ACI 318 or 349 and the guidance 

of 2011.2R was used for the 

containment concrete in contact with 

the embedded containment shell or 

liner. 

2. The concrete is monitored to ensure 

that it is free of penetrating cracks 

that provide a path for water 

seepage to the surface of the 

containment shell or liner. 

3. The moisture barrier, at the junction 

where the shell or liner becomes 

embedded, is subject to aging 

management activities in 

accordance with IWE requirements. 

4. Borated water spills and water 

ponding on the containment 

concrete floor are not common and 

when detected are cleaned up in a 

timely manner. 

If any of the above conditions cannot be 

satisfied, then a plant-specific aging 

management program for corrosion is 

I required. I
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0,

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II Containment Structures 

A2. PWR Steel Containments 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

Chapter XI.S4, "10 CFR Part 50, No 

Appendix J" and 

If a coatings program is credited for No 

managing loss of material due to 

corrosion during the current licensing 

term (e.g., relief request from IWE), then 

it is to be continued during the period of 

extended operation. See Chapter XI.S8, 

"Protective Coating Monitoring and 

Maintenance Program" 

A2.2-a Concrete elements: Concrete Outside Loss of material Chapter X1:52, "'ASME Section XI, No 

containment (spalling, scaling) Subsection IWL" 

Basemat and cracking 

/Freeze-thaw As described in NUREG-1557, freeze

thaw does not cause loss of material 

from reinforced concrete in foundations, 

and in above and below grade exterior 

concrete, for plants located in a 

geographic region of negligible 

weathering conditions (weathering index 

<100 day-inch/yr). Loss of material from 

such concrete is not significant at plants 

located in areas in which weathering 

conditions are severe (weathering index 

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

day-inch/yr), provided that the concrete 

mix design meets the air content 

(entrained air 3-6%) and water-to

cement ratio (0.35-0.45) specified in ACI 

318-63 (or later edition) or ACI 349-85 

(or later edition). I

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Containment Structures 

A2. PWR Steel Containments 

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

The weathering index is defined in 

ASTM C33-90, Table 3, Footnote E. 

Fig. 1 of ASTM C33-90 illustrates the 

various weathering index regions throughout the U.S. A2.2-b Concrete elements: Concrete Outside Increase in Chapter XI.S2, "ASME Section Xl, Yes, if 

containment porosity, Subsection IWL' leaching of Basemat permeability / calcium 

Leaching of Accessible Areas: hydroxide calcium hydroxide Leaching of calcium hydroxide from is 

reinforced concrete becomes significant significant only if the concrete is exposed to flowing for 

water. Even if reinforced concrete is inaccess

exposed to flowing water, such leaching ible areas 

is not significant if the concrete is 

constructed to ensure that it is dense, 

well-cured, has low permeability, and 

that cracking is well controlled. Cracking is controlled through proper 

arrangement and distribution of 

reinforcing bars. All of the above 

characteristics are assured if the 

concrete was constructed with the 

guidance of ACI 201.2R-77. Inspections 

performed in accordance with IWL will 

indicate the absence or presence of 

leaching of calcium hydroxide. 

Inaccessible Areas: 

For below grade inaccessible areas 

(basemat and concrete wall), a plant

specific aging management program is 

required only if the above conditions are 

not satisfied.
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II Containment Structures 

A2. PWR Steel Containments 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism _Aging Management Program (AMP) Evaluation 

A2.2-c Concrete elements: Concrete Inside or Increase in Chapter XI.S2, "ASME Section XI, Yes, if 

outside porosity and Subsection IWL" aggressive Basemat containment permeability, chemical 

cracking, loss of Accessible Areas: attack is 

material (spalling, For interior and above-grade exterior significant scaling) / reinforced concrete, aggressive for 

Aggressive chemical attack is not significant if the inaccess

chemical attack concrete is not exposed to an ible areas 

aggressive environment (pH < 5.5), or to 

chloride or sulfate solutions beyond 

defined limits (> 500 ppm chloride, or > 

1,500 ppm sulfate). Inspections 

performed in accordance with IWL will 

indicate the absence or presence of 

aggressive chemical attack. 

Inaccessible Areas: 

For below-grade exterior reinforced 

concrete (basemat, embedded walls), a 

plant-specific aging management 

program is required only if the below

grade environment is aggressive (pH < 

5.5, chlorides > 500 ppm, or sulfates > 

1,500 ppm). Examination of 

representative samples of below-grade 

concrete, when excavated for any 

reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of below

grade water chemistry (including 

consideration of potential seasonal 

I variations) is an acceptable approach to

"0 r'o 

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Containment Structures A2. PWR ;tn~l ConntinmAnt•

•> 

•0 

0 

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

demonstrate that the below-grade 

environment is not aggressive. A2.2-d Concrete elements: Concrete Inside or Cracking due to Chapter XI.S2, "ASME Section XI, No 

outside expansion / Subsection IWL" 

Basemat containment Reaction with 

aggregates As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates performed 

in accordance with ASTM C295-54 or 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregate

reinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with the 

guidance of ACI 201.2R-77. Inspections 

performed in accordance with IWL will 

indicate the absence or presence of 

surface degradation due to reaction with 

aggregates. 

A2.2-e Concrete elements: Concrete; Inside or Cracking, loss of Chapter XI.S2, "ASME Section XI, Yes, if 

carbon outside bond, and loss of Subsection IWL" corrosion 

Basemat and reinforcing steel steel containment material (spalling, of 

scaling) / Accessible Areas: embedded 

Corrosion of For exterior above-grade and interior steel is 

embedded steel embedded steel, corrosion is not significant 

significant if the steel is not exposed to for 

an aggressive environment inaccess

(concrete pH < 11.5 or ible areas 

chlorides > 500 ppm). Alternatively, if 

the environment surrounding the 

concrete is non-aggressive (pH > 5.5, _ chlorides < 500 ppm,
z 

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0 

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K 

K.

Containment Structures 

A2. PWR Steel Containments 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism _Aging Management Program (AMP) Evaluation 

(continued) 

sulfates < 1,500 ppm), corrosion of 

embedded steel is not significant. If such 

steel is exposed to an aggressive environment, corrosion is not significant if the concrete in which the steel is 

embedded has a low water-to-cement 

ratio (0.35-0.45), adequate air 

entrainment (3-6%), low permeability, 

and is designed in accordance with 

ACI 318-63 (or later edition) or 

ACI 349-85 (or later edition). Inspections performed in accordance with IWL will 

indicate the absence or presence of 

visible corrosion of embedded steel. 

Inaccessible Areas: 

For below-grade exterior reinforced 

concrete (basemat, embedded walls), a 

plant-specific aging management 

program is required only if the below

grade environment is aggressive (pH < 5.5, chlorides > 500 ppm, or 

sulfates > 1,500 ppm). Examination of representative samples of below-grade 

concrete, when excavated for any 

reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of below

grade water chemistry (including consideration of potential seasonal 

variations) is an acceptable approach to

o) 

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(0 

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9

Containment Structures 

A2. PWR Steel Containments 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

demonstrate that the below-grade environment is not aggressive. A2.2-f Concrete elements: Concrete Inside or Cracks; distortion; Chapter XI.S6, "Structures Monitoring No, if 

outside increase in Program" within the Basemat containment component stress scope of 

level / Settlement The initial Licensing Basis for some the 

plants included a program to monitor applicant's settlement. If no settlement was evident structures 

during the first decade or so, the NRC monitoring 

may have given the licensee approval to program discontinue the program. However, if a 

de-watering system is relied upon for 

control of settlement, then the licensee 

is to ensure proper functioning of the de

watering system through the period of 

extended operation. A2.2-g Concrete elements: Concrete; Flowing water Reduction in Chapter XI.S6, "Structures Monitoring No, if 

porous under foundation Program" within the Foundation; subfoundation concrete foundation strength, cracking, scope of 

differential Erosion of cement from porous concrete the 

settlement / subfoundations beneath containment applicant's Erosion of porous basemats is described in IN 97-11. IN structures 

concrete 98-26 proposes Maintenance Rule monitoring subfoundation Structures Monitoring for managing this program 

aging effect, if applicable. If a de

watering system is relied upon for 

control of erosion of cement from porous concrete subfoundations, then the 

licensee is to ensure proper functioning of the de-watering system through the 

period of extended operation.
z 

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0

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Containment Structures 

A2. PWR Steel Containments 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A2.2-h Concrete elements: Concrete Inside or Reduction of Plant-specific aging management Yes, if 

outside strength and program applicable Basemat containment modulus / 

Elevated The implementation of 10 CFR 50.55a 

temperature and IWL would not be able to identify the 

(>1 50°F general; reduction of strength and modulus due 

>200°F local) to elevated temperature. Thus, for any portions of concrete containment that 

exceed specified temperature limits, 

further evaluations are warranted. 

Subsection CC-3400 of ASME Section 

Ill, Division 2, specifies the concrete 

temperature limits for normal operation 

or any other long-term period. The 

temperatures shall not exceed 150°F 

except for local areas, such as around 

penetrations, which are not allowed to 

exceed 2000F. If significant equipment loads are supported by concrete at 

temperatures exceeding 1500F, an 

evaluation of the ability to withstand the 

postulated design loads is to be made. 

Higher temperatures than given above 

may be allowed in the concrete if tests 

and/or calculations are provided to evaluate the reduction in strength and 

this reduction is applied to the design 

allowables.

0 0
A3. COMMON COMPONENTS

A3.1 Penetration Sleeves, Penetration Bellows, Dissimilar Metal Welds 

A3.2 Personnel Airlock, Equipment Hatch 

A3.3 Seals, Gaskets, and Moisture Barriers (Caulking, Flashing, and Other Sealants)

April 2001 11 A3-1 NUREG-1801
A3. COMMON COMPONENTS

Systems, Structures, and Components 

This section addresses the common components of PWR containments. The common 

components include penetration sleeves and bellows; dissimilar metal welds; personnel airlock; 

equipment hatch; and seals, gaskets, and moisture barriers. 

System Interfaces 

Functional interfaces include the primary containment heating and ventilation system (VII.F3), containment isolation system (V.C), and containment spray system (V.A). Physical interfaces 

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

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

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

typically provides support to the NSSS components and containment internal structures.

NUREG-1801 11 A3-2 April 2001
( 

II

( (

Containment Structures A3. PWR Containment Common Cnmnnn~nt_•

V> 

0O 

0

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A3.1 -a Penetration sleeves Carbon Inside or Loss of material / Chapter XI.S1, "ASME Section Xl, No 

steel; outside Corrosion Subsection IWE," 

dissimilar containment 

metal (Note: IWE examination category E-F, welds surface examination of dissimilar metal 

welds, is optional) 

Chapter XI.S4, "10 CFR Part 50, No 

Appendix J," and 

If a coatings program is credited for No 

managing loss of material due to 

corrosion during the current licensing 

term (e.g., relief request from IWE), then 

it is to be continued during the period of 

extended operation. See Chapter XI.S8, "Protective Coating Monitoring and 

A3.1-b Penetration Maintenance Program" sleeves; Carbon Inside or Cumulative Fatigue is a time-limited aging analysis Yes, penetration bellows Steel; outside fatigue damage / (TLAA) to be evaluated for the period of TLAA stainless containment Fatigue extended operation. See the Standard steel; Review Plan, Section 4.6, "Containment dissimilar (Only if CLB Liner Plate and Penetration Fatigue metal fatigue analysis Analysis" for acceptable methods for welds exists) meeting the requirements of 

A3.1-c Penetration 10 CFR 54.21 (c). sleeves; Carbon Inside or Cracking / Cyclic Chapter XI.S1 "ASME Section Xl, Yes, penetration bellows steel; outside loading Subsection IWE " and Chapter XI.S4, detection stainless containment "10 CFR Part 50, Appendix J" of aging steel; (CLB fatigue effects is to dissimilar analysis does not Evaluation of 10 CFR 50.55a/IWE is be 

metal exist) augmented as follows: evaluated welds (4) Detection of Aging Effects: VT-3 

visual inspection may not detect fine 

cracks.

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11 Containment Structures 

A3. PWR Containment Common Comoonents

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9

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A3.1-d Penetration sleeves; Stainless Inside or Crack initiation Chapter XI.S1, "ASME Section X1, Yes, penetration bellows steel; outside and growth / Subsection IWE" and Chapter XI.S4, detection 

dissimilar containment Stress corrosion "10 CFR Part 50, Appendix J" of aging metal cracking effects is to welds Evaluation of 10 CFR 50.55a/IWE is be 

augmented as follows: evaluated 

(4) Detection of Aging Effects: Stress corrosion cracking (SCC) is a 

concern for dissimilar metal welds. In the 

case of bellows assemblies, SCC may 

cause aging effects particularly if the 

material is not shielded from a corrosive 

environment. Subsection IWE covers 

inspection of these items under 

examination categories E-B, E-F, and 

E-P (10 CFR Part 50, Appendix J 

pressure tests). 10 CFR 50.55a 

identifies examination categories E-B 

and E-F as optional during the current 

term of operation. For the extended 

period of operation, Examination 

Categories E-B & E-F, and additional 

appropriate examinations to detect SCC 

in bellows assemblies and dissimilar 

metal welds are warranted to address 

this issue. 

(10) Operating Experience: 

IN 92-20 describes an instance of 

containment bellows cracking, resulting in loss of leak tightness.

0> 

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11 Containment Structures A3. PWR Containment Common Cmomonents

(

"01 

z 

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0

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A3.2-a Personnel airlock; equipment Carbon Inside or Loss of material / Chapter XI.S1, "ASME Section XI, No 

hatch steel outside Corrosion Subsection IWE," 

containment 

Chapter XI.S4, "10 CFR Part 50, No 

Appendix J," and 

If a coatings program is credited for No 

managing loss of material due to 

corrosion during the current licensing 

term (e.g., relief request from IWE), then 

it is to be continued during the period of 

extended operation. See Chapter XI.S8, 

"Protective Coating Monitoring and 

Maintenance Program." A3.2-b Personnel airlock; equipment Carbon Inside or Loss of leak Chapter XLS4, "10 CFR Part 50, No 

hatch: Steel outside tightness in Appendix J" and 

containment closed position / 

Locks, hinges, and closure Mechanical wear Plant Technical Specifications 

mechanisms of locks, hinges 

and closure 

I mechanisms 

A3.3-a Seals, gaskets, and moisture Various Inside or Loss of sealing; Chapter XI.S1, "ASME Section XI, No 

barriers (caulking, flashing, and outside leakage through Subsection IWE" 

other sealants) containment containment / 

Deterioration of Leak tightness will be monitored by 

seals, gaskets, 10 CFR Part 50, Appendix J Leak Rate 

and moisture Tests for pressure boundary, seals and 

barriers (caulking, gaskets (including O-rings). 

flashing, and 

other sealants)
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= This Page Intentionally Left Blank 

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BWR CONTAINMENTS

B1. Mark I Containments 

B2. Mark II Containments 

B3. Mark III Containments 

B4. Common Components

April 2001 HI B-i NUREG-1801
This Page Intentionally Left Blank

NUREG-1801 11 B-ii April 2001
B1. MARK I CONTAINMENTS 

B13.1 Steel Containments 

B13.1.1 Steel Elements

April 2001 11131-1 NUREG-1801
B1. MARK I CONTAINMENTS

Systems, Structures, and Components 

This section addresses the elements of BWR Mark I containment structures. Mark I steel 

containments are discussed in II.B13.1. 

System Interfaces 

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

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

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

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

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

NSSS components and containment internal structures.

NUREG-1801 11131-2 April 2001
(

Containment Structures 

B1.1 BWR Mark I Steel Containments

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation

Steel elements:

Drywell; torus; drywell head; 

embedded shell and sand 

pocket regions; drywell support 

skirt; torus ring girder; 

downcomers; ECCS suction 

header 

NOTE: Inspection of 

containment supports is 

addressed by ASME 

Section XI, Subsection IWF 

(see lll.B1.3)

Carbon 

steel

Inside or 

outside 

containment

Loss of material / 

Corrosion

B1.1.1-a Chapter XI.S1, "ASME Section XI, 

Subsection IWE" 

For inaccessible areas (embedded 

containment steel shell or liner), loss of 

material due to corrosion is not 

significant if the following conditions are 

satisfied: 

1. Concrete meeting the requirements 

of ACI 318 or 349 and the guidance 

of 201.2R was used for the 

containment concrete in contact with 

the embedded containment shell or 

liner. 

2. The concrete is monitored to ensure 

that it is free of penetrating cracks 

that provide a path for water 

seepage to the surface of the 

containment shell or liner. 

3. The moisture barrier, at the junction 

where the shell or liner becomes 

embedded, is subject to aging 

management activities in 

accordance with IWE requirements. 

4. Borated water spills and water 

ponding on the containment 

concrete floor are not common and 

when detected are cleaned up in a 

timely manner. 

If any of the above conditions cannot be 

satisfied, then a plant-specific aging 

management program for corrosion is 

reauired.

(

Yes, if 

corrosion is 

significant 

for 

inaccess

ible areas
II Containment Structures B1.1 BWR Mark I Steel Containments

z 

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0 Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

Chapter XI.S4, "10 CFR Part 50, No 

Appendix J" 

If a coatings program is credited for No 

managing loss of material due to 

corrosion during the current licensing 

term (e.g., relief request from IWE), then 

it is to be continued during the period of 

extended operation. See Chapter XI.S8, 

"Protective Coating Monitoring and 

Maintenance Program" 

B1.1.1-b Steel elements: Stainless Inside or Cracking /Cyclic Chapter XI.S1 "ASME Section Xl, Yes, 

steel; outside loading Subsection IWE "and Chapter XI.S4, detection 

Torus; vent line; vent header; carbon containment "10 CFR Part 50, Appendix J" of aging vent line bellows; downcomers steel effects is to 

(CLB fatigue Evaluation of 10 CFR 50.55a/IWE is be 

analysis does not augmented as follows: evaluated 

exist) 

(4) Detection of Aging Effects: VT-3 

visual inspection may not detect fine 

cracks. 

B1.1.1-c Steel elements: Stainless Inside or Cumulative Fatigue is a time-limited aging analysis Yes, steel; outside fatigue damage / (TLAA) to be evaluated for the period of TLAA 

Torus; vent line; vent header; carbon containment Fatigue extended operation. See the Standard 

vent line bellows; downcomers steel Review Plan, Section 4.6, "Containment 

(Only if CLB Liner Plate and Penetration Fatigue 

fatigue analysis Analysis" for acceptable methods for 

exists) meeting the requirements of 

10 CFR 54.21 (c).

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Containment Structures 

B1.1 BWR Mark I Steel Containments 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B1.1.1-d Steel elements: Stainless Inside or Crack initiation Chapter XI.S1, "ASME Section Xl, Yes, steel outside and growth / Subsection IWE "and Chapter XI.S4, detection Vent line bellows containment Stress corrosion "10 CFR Part 50, Appendix J" of aging 

cracking effects is to 

Evaluation of 10 CFR 50.55a/IWE is be 

augmented as follows: evaluated 

(4) Detection of Aging Effects: Stress 

corrosion cracking (SCC) is a concern 

for dissimilar metal welds. In the case of 

bellows assemblies, SCC may cause 

aging effects particularly if the material is 

not shielded from a corrosive 

environment. Subsection IWE covers 

inspection of these items under 

examination categories E-B, E-F, and E

P (10 CFR Part 50, Appendix J pressure 

tests). 10 CFR 50.55a identifies 

examination categories E-B and E-F as 

optional during the current term of 

operation. For the extended period of 

operation, Examination Categories E-B 

and E-F, and additional appropriate examinations to detect SCC in bellows 

assemblies and dissimilar metal welds 

are warranted to address this issue. 

(10) Operating Experience: IN 92-20 

describes an instance of containment 

bellows cracking, resulting in loss of leak 

tightness. B1.1.1-e Steel elements: Carbon Inside or Fretting or lockup Chapter XI.S1, "ASME Section XI, No 

steel; outside / Mechanical wear Subsection IWE" 

Drywell head; downcomers graphite containment 

I late I
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B2. MARK II CONTAINMENTS 

B2.1 Steel Containments 

B2.1.1 Steel Elements 

B2.2 Concrete Containments 

B2.2.1 Concrete Elements 

B2.2.2 Steel Elements 

B2.2.3 Prestressing System

April 2001 11132-1 NUREG-1801
B2. MARK II CONTAINMENTS

Systems, Structures, and Components 

This section addresses the elements of BWR Mark 11 containment structures. Mark II steel 

containments are discussed in II.B2.1. Mark II concrete containments are discussed in II.B2.2. 

System Interfaces 

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

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

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

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

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

NSSS components and containment internal structures.

NUREG-1801 11132-2 April 2001
(

C? 

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Containment Structures 

B2.1 BWR Mark II Steel Containments 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B2.1.1-a Steel elements: Carbon Inside or Loss of material / Chapter XI.S1, "ASME Section XI, Yes, if 

steel outside Corrosion Subsection IWE" corrosion is 

Drywell; suppression containment significant 

chamber; drywell head; For inaccessible areas (embedded for 

embedded shell and sand containment steel shell or liner), loss of inaccess

pocket regions; support skirt; material due to corrosion is not ible areas 

downcomer pipes; region significant if the following conditions are 

shielded by diaphragm floor satisfied: 

NOTE: Inspection of 1. Concrete meeting the requirements 

containment supports is of ACI 318 or 349 and the guidance 

addressed by ASME Section of 201.2R was used for the 

XI, Subsection IWF (see containment concrete in contact with 

Ill.B13.3). the embedded containment shell or 

liner. 

2. The concrete is monitored to ensure 

that it is free of penetrating cracks 

that provide a path for water 

seepage to the surface of the 

containment shell or liner. 

3. The moisture barrier, at the junction 

where the shell or liner becomes 

embedded, is subject to aging 

management activities in 

accordance with IWE requirements. 4. Borated water spills and water 

ponding on the containment 

concrete floor are not common and 

when detected are cleaned up in a 

timely manner. 

If any of the above conditions cannot be 

satisfied, then a plant-specific aging 

management program for corrosion is _ _required.
11 Containment Structures B2.1 BWR Mark II Steel Containments

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

Chapter XI.S4, "10 CFR Part 50, No 

Appendix J" 

If a coatings program is credited for No 

managing loss of material due to 

corrosion during the current licensing 

term (e.g., relief request from IWE), then 

it is to be continued during the period of 

extended operation. See Chapter XI.S8, 

"Protective Coating Monitoring and 

Maintenance Program" 

B2.1.1-b Steel elements: Carbon Inside or Cracking/ Chapter XlIS1 "ASME Section XI, Yes, 

steel outside Cyclic loading Subsection IWE " and Chapter XI.S4, detection 

Suppression pool shell, containment "10 CFR Part 50, Appendix J" of aging 

unbraced downcomers (CLB fatigue effects is to 

analysis does not Evaluation of 10 CFR 50.55a/IWE is be 

exist) augmented as follows: evaluated 

(4) Detection of Aging Effects: VT-3 

visual inspection may not detect fine 

cracks. 

B2.1.1-c Steel Elements: Carbon Inside or Cumulative Fatigue is a time-limited aging analysis Yes, 

steel outside fatigue damage / (TLAA) to be evaluated for the period of TLAA 

Suppression pool shell, containment Fatigue extended operation. See the Standard 

unbraced downcomers Review Plan, Section 4.6, "Containment 

(Only if CLB Liner Plate and Penetration Fatigue 

fatigue analysis Analysis" for acceptable methods for 

exists) meeting the requirements of 

10 CFR 54.21 (c). 

B2.1.1-d Steel elements: Carbon Inside or Fretting or lockup Chapter XI.S1, "ASME Section XI, No 

steel outside / Mechanical wear Subsection IWE" 

Drywell head; downcomer containment 

pipes I I I I

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Containment Structures B2.2 BWR Mark II Concrete Containment-=

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Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B2.2.1-a Concrete elements: Concrete Outside Increase in Chapter XI.S2, "ASME Section XI, Yes, if 

containment porosity, Subsection IWL" leaching of 

Containment; basemat permeability / calcium 

Leaching of Accessible Areas: Leaching of calcium hydroxide 

calcium hydroxide hydroxide from reinforced concrete is 

becomes significant only if the concrete significant 

is exposed to flowing water. Even if for 

reinforced concrete is exposed to flowing inaccess

water, such leaching is not significant if ible areas. 

the concrete is constructed to ensure 

that it is dense, well-cured, has low 

permeability, and that cracking is well 

controlled. Cracking is controlled through 

proper arrangement and distribution of 

reinforcing bars. All of the above 

characteristics are assured if the 

concrete was constructed with the 

guidance of ACI 201.2R-77. Inspections performed in accordance with IWL will 

indicate the absence or presence of 

leaching of calcium hydroxide. 

Inaccessible Areas: For below grade 

inaccessible areas (basemat and 

concrete wall), a plant-specific aging 

management program is required only if 

the above conditions are not satisfied. 

B2.2.1-b Concrete elements: Concrete Inside or Increase in Chapter XI.S2, "ASME Section Xl, Yes, if 

outside porosity and Subsection IWL" aggressive Containment; basemat containment permeability, chemical 

cracking, loss of Accessible Areas: attack is 

material (spalling, For interior and above-grade exterior significant 

scaling) / reinforced concrete, aggressive for 

Aggressive chemical attack is not significant if the inaccess _ chemical attack concrete is not exposed to an ible areas
Containment Structures B2.2 BWR Mark II Concrete Containments

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11

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

aggressive environment (pH < 5.5), or to 

chloride or sulfate solutions beyond 

defined limits ( > 500 ppm chloride, or > 

1,500 ppm sulfate). Inspections 

performed in accordance with IWL will 

indicate the absence or presence of 

aggressive chemical attack. 

Inaccessible Areas: 

For below-grade exterior reinforced 

concrete (basemat, embedded walls), a 

plant-specific aging management 

program is required only if the below

grade environment is aggressive (pH < 

5.5, chlorides > 500 ppm, or sulfates > 

1,500 ppm). Examination of 

representative samples of below-grade 

concrete, when excavated for any 

reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of below

grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade 

environment is not aggressive.

I
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Containment Structures B2.2 BWR Mark It Concrete Containments

CD 

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B2.2.1 -c Concrete elements: Concrete Inside or Cracking due to Chapter XI.S2, "ASME Section XI, No 

outside expansion / Subsection IWL" 

Containment; basemat containment Reaction with 

aggregates As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates performed 

in accordance with ASTM C295-54 or 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregate

reinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with the 

guidance of ACt 201.2R-77. Inspections performed in accordance with IWL will 

indicate the absence or presence of 

surface degradation due to reaction with 

aggregates. 

B2.2.1 -d Concrete elements: Concrete; Inside or Cracking, loss of Chapter XI.S2, "ASME Section XI, Yes, if 

carbon outside bond, and loss of Subsection IWL," corrosion 

Containment; basemat; steel containment material (spalling, of 

reinforcing steel scaling) / Accessible Areas: embedded 

Corrosion of For exterior above-grade and interior steel is 

embedded steel embedded steel, corrosion is not significant significant if the steel is not exposed to for 

an aggressive environment (concrete pH inaccess

< 11.5 or chlorides > 500 ppm). ible areas 

Alternatively, if the environment 

surrounding the concrete is non

aggressive (pH > 5.5, chlorides < 500 

ppm, sulfates < 1,500 ppm), corrosion of 

embedded steel is not significant. If such 

steel is exposed to an aggressive 

environment, corrosion is not significant I
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Containment Structures 

B2.2 BWR Mark II Concrete Containments 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

if the concrete in which the steel is 

embedded has a low water-to-cement 

ratio (0.35-0.45), adequate air 

entrainment (3-6%), low permeability, 

and is designed in accordance with ACI 

318-63 (or later edition) or ACI 349-85 

(or later edition). Inspections performed 

in accordance with IWL will indicate the 

absence or presence of visible corrosion 

of embedded steel. 

Inaccessible Areas: 

For below-grade exterior reinforced 

concrete (basemat, embedded walls), a 

plant-specific aging management 

program is required only if the below

grade environment is aggressive (pH < 

5.5, chlorides > 500 ppm, or sulfates > 

1,500 ppm). Examination of 

representative samples of below-grade 

concrete, when excavated for any 

reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of below

grade water chemistry (including consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade environment is not aggressive.
r

11

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Containment Structures B2.2 BWR Mark II Concrete Containments

(

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B2.2.1-e Concrete elements: Concrete Inside or Cracks; distortion; Chapter XI.S6, "Structures Monitoring No, if 

outside increase in Program" within the All containment component stress scope of 

level / The initial Licensing Basis for some the 

Settlement plants included a program to monitor applicant's 

settlement. If no settlement was evident structures 

during the first decade or so, the NRC monitoring 

may have given the licensee approval to program 

discontinue the program. However, if a 

de-watering system is relied upon for 

control of settlement, then the licensee is 

to ensure proper functioning of the de

watering system through the period of 

extended operation B2.2.1 -f Concrete elements: Concrete; Flowing water Reduction in Chapter XI.S6, "Structures Monitoring No, if 

porous under foundation Program" within the Foundation; subfoundation concrete foundation strength, cracking, scope of 

differential Erosion of cement from porous concrete the 

settlement / subfoundations beneath containment applicant's Erosion of porous basemats is described in IN 97-11. IN structures 

concrete 98-26 proposes Maintenance Rule monitoring 

subfoundation Structures Monitoring for managing this program 

aging effect, if applicable. If a de

watering system is relied upon for 

control of erosion of cement from porous 

concrete subfoundations, then the 

licensee is to ensure proper functioning 

of the de-watering system through the 

period of extended operation.

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11 Containment Structures B2.2 BWR Mark II Concrete Containment•

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation B2.2.1-g Concrete elements: Concrete Inside or Reduction of Plant-specific aging management Yes, if 

outside strength and program. applicable Containment; concrete fill in containment modulus / annulus; basemat Elevated The implementation of 10 CFR 50.55a 

temperature and IWL would not be able to identify the 

(>1501F general; reduction of strength and modulus due 

>200°F local) to elevated temperature. Thus, for any portions of concrete containment that 

exceed specified temperature limits, 

further evaluations are warranted. 

Subsection CC-3400 of ASME 

Section III, Division 2, specifies the 

concrete temperature limits for normal 

operation or any other long-term period. 

The temperatures shall not exceed 

150°F except for local areas, such as 

around penetrations, which are not 

allowed to exceed 2000F. If significant equipment loads are supported by 

concrete at temperatures exceeding 

150 0F, an evaluation of the ability to 

withstand the postulated design loads is 

to be made. 

Higher temperatures than given above 

may be allowed in the concrete if tests 

and/or calculations are provided to 

evaluate the reduction in strength and 

this reduction is applied to the design I allowables.
(

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9

Containment Structures 

B2.2 BWR Mark II Concrete Containments 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B2.2.2-a Steel elements: Carbon Inside or Loss of material/ Chapter XI.S1, "ASME Section XI, Yes, if 

steel outside Corrosion Subsection IWE" corrosion is 

Drywell; suppression containment significant chamber; basemat liners; For inaccessible areas (embedded for 

liner anchors; drywell head; containment steel shell or liner), loss of inaccess

downcomer pipes material due to corrosion is not ible areas 

significant if the following conditions are 

NOTE: Inspection of satisfied: 

containment supports is 

addressed by ASME Section 1. Concrete meeting the requirements XI, Subsection IWF (see of ACI 318 or 349 and the guidance Ill.B1 .3). of 201.2R was used for the contain

ment concrete in contact with the 

embedded containment shell or 

liner. 

2. The concrete is monitored to ensure 

that it is free of penetrating cracks 

that provide a path for water 

seepage to the surface of the 

containment shell or liner. 

3. The moisture barrier, at the junction 

where the shell or liner becomes 

embedded, is subject to aging 

management activities in 

accordance with IWE requirements. 

4. Borated water spills and water 

ponding on the containment 

concrete floor are not common and 

when detected are cleaned up in a 

timely manner. 

If any of the above conditions cannot be 

satisfied, then a plant-specific aging 

management program for corrosion is 

I required.

C
11 Containment Structures B2.2 BWR Mnrk II Chnunr~tA Cnontninm~nt: z C: 

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0 

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C 

J\

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

Chapter XI.S4, "10 CFR Part 50, No 

Appendix J" 

If a coatings program is credited for No 

managing loss of material due to 

corrosion during the current licensing 

term (e.g., relief request from IWE), then 

it is to be continued during the period of 

extended operation. See Chapter XI.S8, 

"Protective Coating Monitoring and 

Maintenance Program." 

B2.2.2-b Steel elements: Stainless Inside or Crack initiation Chapter XI.SI, "ASME Section Xl, No 

steel outside and growth / Subsection IWE" and Chapter XI.S4, 

Suppression chamber liner containment Stress corrosion "10 CFR Part 50, Appendix J" 

(interior surface) _ cracking 

B2.2.2-c Steel elements: Carbon Inside or Cracking / Chapter XI.S1, "ASME Section XI, Yes, 

steel outside Cyclic loading Subsection IWE" and Chapter XI.S4, detection 

Vent header; downcomers containment "10 CFR Part 50, Appendix J" of aging 

(CLB fatigue effects is to 

analysis does not Evaluation of 10 CFR 50.55a/IWE is be 

exist) augmented as follows: evaluated 

(4) Detection of Aging Effects: VT-3 

visual inspection may not detect fine 

cracks. 

B2.2.2-d Steel elements: Carbon Inside or Cumulative Fatigue is a time-limited aging analysis Yes, 

steel outside fatigue damage / (TLAA) to be evaluated for the period of TLAA 

Vent header; downcomers containment Fatigue extended operation. See the Standard 

Review Plan, Section 4.6, "Containment 

(Only if CLB Liner Plate and Penetration Fatigue 

fatigue analysis Analysis," for acceptable methods for 

exists) meeting the requirements of 

10 CFR 54.21 (c).

, •
( ( (

_0 

0 

CA)

II Containment Structures 

B2.2 BWR Mark II Concrete Containments 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B2.2.2-e Steel elements: Carbon Inside or Fretting or lockup Chapter XI.S1, "ASME Section XI, No 

steel outside / Mechanical wear Subsection IWE" 

Drywell head; downcomer containment 

pipes 

B2.2.3-a Prestressing system: Carbon Inside or Loss of material / Chapter XI.S2, "ASME Section XI No 

steel outside Corrosion Subsection IWL" 

Tendons; anchorage containment 

components B2.2.3-b Prestressing system: Carbon Inside or Loss of prestress / Loss of tendon prestress is a time- Yes, 

steel outside Relaxation; limited aging analysis (TLAA) to be TLAA Tendons; anchorage containment shrinkage; creep; evaluated for the period of extended 

components elevated operation. See the Standard Review 

temperature Plan, Section 4.5, "Concrete 

Containment Tendon Prestress" for 

acceptable methods for meeting the 

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

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

for meeting the requirements of 

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

For periodic monitoring of prestress, see 

Chapter XI.S2.

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B3. MARK III CONTAINMENTS 

B3.1 Steel Containments 

B3.1.1 Steel Elements 

B3.1.2 Concrete Elements 

B3.2 Concrete Containments 

B3.2.1 Concrete Elements 

B3.2.2 Steel Elements

April 2001 11133-1 NUREG-1801
B3. MARK III CONTAINMENTS

Systems, Structures, and Components 

This section addresses the elements of BWR Mark III containment structures. Mark III steel 

containments are discussed in Il.B3.1. Mark III concrete containments are discussed in !1.B3.2. 

System Interfaces 

Functional interfaces include the primary containment heating and ventilation system (VII.F3), containment isolation system (V.C), and standby gas treatment system (V.B). Physical interfaces exist with any structure, system, or component that either penetrates the containment 

wall, such as the main steam system (VIII.B2) and feedwater system (VIII.D2), or is supported by the containment structure. The containment structure basemat may provide support to the 

NSSS components and containment internal structures.

NUREG-1801 11133-2 April 2001
( ii

Containment Structures B3.1 BWR Mark III Steel Containments

(

z 

C 

m 

0 cc

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B3.1.1-a Steel elements: Carbon Inside oi Loss of material / Chapter XI.S1, "ASME Section Xl, Yes, if 

steel Outside Corrosion Subsection IWE" corrosion is 

Containment shell; Containment significant suppression chamber shell; For inaccessible areas (embedded for 

basemat liner; liner anchors containment steel shell or liner), loss of inaccess

material due to corrosion is not ible areas 

significant if the following conditions are 

satisfied: 

1. Concrete meeting the requirements 

of ACI 318 or 349 and the guidance 

of 201.2R was used for the 

containment concrete in contact with 

the embedded containment shell or 

liner. 

2. The concrete is monitored to ensure 

that it is free of penetrating cracks 

that provide a path for water 

seepage to the surface of the 

containment shell or liner. 

3. The moisture barrier, at the junction 

where the shell or liner becomes 

embedded, is subject to aging 

management activities in 

accordance with IWE requirements. 

4. Borated water spills and water 

ponding on the containment 

concrete floor are not common and 

when detected are cleaned up in a 

timely manner. 

If any of the above conditions cannot be 

satisfied, then a plant-specific aging 

management program for corrosion is 

I required.
11 Containment Structures B3.1 BWR Mark Ill Steel Containments z 

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m OD 

0 

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0 

o? 

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

Chapter XI.S4, "10 CFR Part 50, No 

Appendix J" 

If a coatings program is credited for No 

managing loss of material due to 

corrosion during the current licensing 

term (e.g., relief request from IWE), then 

it is to be continued during the period of 

extended operation. See Chapter XI.S8, 

"Protective Coating Monitoring and 

Maintenance Program" 

B3.1.1-b Steel elements: Stainless Inside or Crack initiation Chapter XI.S1, "ASME Section XI, No 

steel outside and growth / Subsection IWE" and Chapter XI.S4, Suppression chamber shell containment Stress corrosion "10 CFR Part 50, Appendix J" 

(interior surface) cracking B3.1.2-a Concrete elements: Concrete Outside Increase in Chapter XI.S2, "ASME Section XI, Yes, if 

containment porosity, Subsection IWL" leaching of Basemat permeability / calcium 

Leaching of Accessible Areas: hydroxide 

calcium hydroxide Leaching of calcium hydroxide from is 

reinforced concrete becomes significant significant 

only if the concrete is exposed to flowing for 

water. Even if reinforced concrete is inaccess

exposed to flowing water, such leaching ible areas 

is not significant if the concrete is 

constructed to ensure that it is dense, 

well-cured, has low permeability, and 

that cracking is well controlled. Cracking 

is controlled through proper arrangement 

and distribution of reinforcing bars. All of 

the above characteristics are assured if 

the concrete was constructed with the 

guidance of ACI 201.2R-77. Inspections
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II Containment Structures 

B3.1 BWR Mark III Steel Containments 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

"(continued) 

performed in accordance with IWL will 

indicate the absence or presence of 

leaching of calcium hydroxide. 

Inaccessible Areas: 

For below grade inaccessible areas 

(basemat and concrete wall), a plant

specific aging management program is 

required only if the above conditions are 

not satisfied. 

B3.1.2-b Concrete elements: Concrete Inside or Increase in Chapter XI.S2, "ASME Section Xl, Yes, if 

outside porosity and Subsection IWL" aggressive 

Basemat containment permeability, chemical 

cracking, loss of Accessible Areas: attack is 

material (spalling, For interior and above-grade exterior significant 

scaling) / reinforced concrete, aggressive for 

Aggressive chemical attack is not significant if the inaccess

chemical attack concrete is not exposed to an ible areas 

aggressive environment (pH < 5.5), or to 

chloride or sulfate solutions beyond 

defined limits (> 500 ppm chloride, or > 

1,500 ppm sulfate). Inspections 

performed in accordance with IWL will 

indicate the absence or presence of 

aggressive chemical attack. 

Inaccessible Areas: 

For below-grade exterior reinforced 

concrete (basemat, embedded walls), a 

plant-specific aging management 

program is required only if the below

grade environment is aggressive (pH < 

5.5, chlorides > 500 ppm, or sulfates > 

11,500 ppm). Examination of I
11 Containment Structures 

B3.1 BWR Mark III Steel Containments

z C 

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"1V 

oN 

a

(,

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

representative samples of below-grade 

concrete, when excavated for any 

reason, is to be included as part of a 

plant-specific program. If the below

grade environment is not aggressive, 

this aging effect is not significant. 

Periodic monitoring of below-grade 

water chemistry (including consideration 

of potential seasonal variations) is an 

acceptable approach to demonstrate 

that the below-grade environment is not 

aggressive. B3.1.2-c Concrete elements: Concrete Inside or Cracking due to Chapter XI.S2, "ASME Section XI, No 

outside expansion / Subsection IWL" 

Basemat; concrete fill in containment Reaction with 

annulus aggregates As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates performed 

in accordance with ASTM C295-54 or 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregate

reinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with the 

guidance of ACI 201.2R-77. Inspections 

performed in accordance with IWL will 

indicate the absence or presence of 

surface degradation due to reaction with 

aggregates.

t
( ( (

Containment Structures 

B3.1 BWR Mark III Steel Containments 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B3.1.2-d Concrete elements: Concrete; Inside or Cracking, loss of Chapter XI.S2, "ASME Section XI, Yes, if 

carbon outside bond, and loss of Subsection IWL" corrosion 

Basemat; reinforcing steel steel containment material (spalling, of 

scaling) / Accessible Areas: embedded 

Corrosion of For exterior above-grade and interior steel is 

embedded steel embedded steel, corrosion is not significant 

significant if the steel is not exposed to for 

an aggressive environment (concrete pH inaccess

< 11.5 or chlorides > 500 ppm). ible areas 

Alternatively, if the environment 

surrounding the concrete is non

aggressive (pH > 5.5, chlorides < 500 

ppm, sulfates < 1,500 ppm), corrosion of 

embedded steel is not significant. If such 

steel is exposed to an aggressive 

environment, corrosion is not significant 

if the concrete in which the steel is 

embedded has a low water-to-cement 

ratio (0.35-0.45), adequate air 

entrainment (3-6%), low permeability, 

and is designed in accordance with ACI 

318-63 (or later edition) or ACI 349-85 

(or later edition). Inspections performed 

in accordance with IWL will indicate the 

absence or presence of visible corrosion 

of embedded steel. 

Inaccessible Areas: 

For below-grade exterior reinforced 

concrete (basemat, embedded walls), a 

plant-specific aging management 

program is required only if the below

grade environment is aggressive (pH < 

5.5, chlorides > 500 ppm, or sulfates > 

11,500 ppm). Examination of
11 Containment Structures B3.1 BWR Mark III Steel Containments

z C 

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Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

"(continued) 

representative samples of below-grade 

concrete, when excavated for any 

reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of below

grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade 

environment is not aggressive. B3.1.2-e Concrete elements: Concrete Inside or Cracks; distortion; Chapter XI.S6, "Structures Monitoring No, if 

outside increase in Program" within the 

Basemat containment component stress scope of 

level / The initial Licensing Basis for some the 

Settlement plants included a program to monitor applicant's 

settlement. If no settlement was evident structures 

during the first decade or so, the NRC monitoring 

may have given the licensee approval to program 

discontinue the program. However, if a 

de-watering system is relied upon for 

control of settlement, then the licensee is 

to ensure proper functioning of the de

watering system through the period of 

extended operation.
( ( (

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m 

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Containment Structures 

B3.1 BWR Mark III Steel Containments 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B3.1.2-f Concrete elements: Concrete; Flowing water Reduction in Chapter XI.S6, "Structures Monitoring Noif 

porous under foundation Program" within the Foundation; subfoundation concrete foundation strength, cracking, scope of 

differential Erosion of cement from porous concrete the 

settlement / subfoundations beneath containment applicant's Erosion of porous basemats is described in IN 97-11. structures 

concrete IN 98-26 proposes Maintenance Rule monitoring subfoundation Structures Monitoring for managing this program 

aging effect, if applicable. If a de

watering system is relied upon for 

control of erosion of cement from porous 

concrete subfoundations, then the 

licensee is to ensure proper functioning 

of the de-watering system through the 

period of extended operation. B3.1.2-g Concrete elements: Concrete Inside or Reduction of Plant-specific aging management Yes, if 

outside strength and program applicable Basemat; concrete fill in containment modulus / 

annulus Elevated The implementation of 10 CFR 50.55a 

temperature and IWL would not be able to identify the 

(>150°F general; reduction of strength and modulus due 

>200°F local) to elevated temperature. Thus, for any 

portions of concrete containment that 

exceed specified temperature limits, 

further evaluations are warranted. 

Subsection CC-3400 of ASME Section 

III, Division 2, specifies the concrete 

temperature limits for normal operation 

or any other long-term period. The 

temperatures shall not exceed 150OF 

except for local areas, such as around 

penetrations, which are not allowed to 

exceed 2000F. If significant equipment loads are supported by concrete at 

temperatures exceeding 1500F, an
11 Containment Structures 

B3.1 BWR Mark III Steel Containments

K

z 

m 

Co

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

evaluation of the ability to withstand the 

postulated design loads is to be made. 

Higher temperatures than given above 

may be allowed in the concrete if tests 

and/or calculations are provided to 

evaluate the reduction in strength and 

this reduction is applied to the design J__ _allowables.

00 

o 

0

( /
( 

II

(

Containment Structures B3.2 BWR Mark III Concrete Containments

(

0 

Z 

w 

m 

0

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B3.2.1 -a Concrete elements: Concrete Outside Loss of material Chapter XI.S2, "ASME Section Xl, No 

containment (spalling, scaling) Subsection IWL" 

Dome; wall; basemat and cracking / 

Freeze-thaw As described in NUREG-1557, freeze

thaw does not cause loss of material 

from reinforced concrete in foundations, 

and in above and below grade exterior 

concrete, for plants located in a 

geographic region of negligible 

weathering conditions (weathering index 

<100 day-inch/yr). Loss of material from 

such concrete is not significant at plants 

located in areas in which weathering 

conditions are severe (weathering index 

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

day-inch/yr), provided that the concrete 

mix design meets the air content 

(entrained air 3-6%) and water-to

cement ratio (0.35-0.45) specified in ACI 

318-63 (or later edition) or ACI 349-85 

(or later edition). The weathering index is 

defined in ASTM C33-90, Table 3, 

Footnote E. Fig. 1 of ASTM C33-90 

illustrates the various weathering index 

regions throughout the U.S. 

B3.2.1-b Concrete elements: Concrete Outside Increase in Chapter XI.S2, "ASME Section Xl, Yes, if 

containment porosity, Subsection IWL" leaching of 

Dome; wall; basemat permeability/ calcium 

Leaching of Accessible Areas: Leaching of calcium hydroxide 

calcium hydroxide hydroxide from reinforced concrete is 

becomes significant only if the concrete significant 

is exposed to flowing water. Even if for 

reinforced concrete is inaccess

exposed to flowing water, such leaching ible areas 

I is not significant if the concrete is
11 Containment Structures 

B3.2 BWR Mark III Cnnc~re~te rnntainm-anta

z 

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03 

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

constructed to ensure that it is dense, 

well-cured, has low permeability, and 

that cracking is well controlled. Cracking 

is controlled through proper arrangement 

and distribution of reinforcing bars. All of 

the above characteristics are assured if 

the concrete was constructed with the 

guidance of ACl 201.2R-77. Inspections 

performed in accordance with IWL will 

indicate the absence or presence of 

leaching of calcium hydroxide. 

Inaccessible Areas: 

For below grade inaccessible areas 

(basemat and concrete wall), a plant specific aging management program is 

required only if the above conditions are 

not satisfied. B3.2.1-c Concrete elements: Concrete Inside or Increase in Chapter Xi.S2, "ASME Section XI, Yes, if 

outside porosity and Subsection IWL" aggressive Dome; wall; basemat containment permeability, chemical 

cracking, loss of Accessible Areas: For interior and attack is 

material (spalling, above-grade exterior reinforced significant scaling) / concrete, aggressive chemical attack is for 

Aggressive not significant if the concrete is not inaccess

chemical attack exposed to an aggressive environment ible areas 

(pH < 5.5), or to chloride or sulfate 

solutions beyond defined limits ( > 500 

ppm chloride, or > 1,500 ppm sulfate). 

Inspections performed in accordance 

with IWL will indicate the absence or 

presence of aggressive chemical attack.

/
(

Containment Structures 

B3.2 BWR Mark III Concrete Containments 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

Inaccessible Areas: For below-grade exterior reinforced concrete (basemat, 

embedded walls), a plant-specific aging 

management program is required only if 

the below-grade environment is 

aggressive (pH < 5.5, chlorides > 500 

ppm, or sulfates > 1,500 ppm). 

Examination of representative samples 

of below-grade concrete, when 

excavated for any reason, is to be 

included as part of a plant-specific 

program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of below

grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade environment is not aggressive. 

B3.2.1-d Concrete elements: Concrete Inside or Cracking due to Chapter XI.S2, "ASME Section Xl, No 

outside expansion / Subsection IWL" 

Dome; wall; basemat containment Reaction with 

aggregates As described in NUREG-1557, 

investigations, tests, and petrographic examinations of aggregates performed 

in accordance with ASTM C295-54 or 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregate

reinforced concrete reaction is not 

significant if the concrete was
11 Containment Structures B3.2 BWR Mark III Concrete Containments

z 

C 

m 

0 

a, 

0 

w• 

CA 

0

K

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism A9ing Management Program (AMP) Evaluation 

(continued) 

constructed in accordance with the 

guidance of ACI 201.2R-77. Inspections 

performed in accordance with IWL will 

indicate the absence or presence of 

surface degradation due to reaction with 

aggregates. 

B3.2.1-e Concrete elements: Concrete; Inside or Cracking, loss of Chapter XI.S2, "ASME Section XI, Yes, if 

carbon outside bond, and loss of Subsection IWL" corrosion 

Dome; wall; basemat; steel containment material (spalling, of 

reinforcing steel scaling) / Accessible Areas: For exterior above- embedded 

Corrosion of grade and interior embedded steel, steel is 

embedded steel corrosion is not significant if the steel is significant 

not exposed to an aggressive for 

environment (concrete pH < 11.5 or inaccess

chlorides > 500 ppm). Alternatively, if the ible areas 

environment surrounding the concrete is 

non-aggressive (pH > 5.5, chlorides < 

500 ppm, sulfates < 1,500 ppm), 

corrosion of embedded steel is not 

significant. If such steel is exposed to an 

aggressive environment, corrosion is not 

significant if the concrete in which the 

steel is embedded has a low water-to

cement ratio (0.35-0.45), adequate air 

entrainment (3-6%), low permeability, 

and is designed in accordance with ACI 

318-63 (or later edition) or ACI 349-85 

(or later edition). Inspections performed 

in accordance with IWL will indicate the 

absence or presence of visible corrosion 

of embedded steel.
K

11 Containment Structures B3.2 BWR Mark III Concrete Containments

(

V 

0 

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M. 

C13 

z a 

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

Inaccessible Areas: For below-grade 

exterior reinforced concrete (basemat, 

embedded walls), a plant-specific aging 

management program is required only if 

the below-grade environment is 

aggressive (pH < 5.5, chlorides > 500 

ppm, or sulfates > 1,500 ppm). 

Examination of representative samples 

of below-grade concrete, when 

excavated for any reason, is to be 

included as part of a plant-specific 

program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of below

grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade 

I_ environment is not aggressive. B3.2.1-f Concrete elements: Concrete Inside or Cracks; distortion; Chapter XI.S6, "Structures Monitoring No, if 

outside increase in Program" within the 

All containment component stress scope of 

level / The initial Licensing Basis for some the 

Settlement plants included a program to monitor applicant's 

settlement. If no settlement was evident structures 

during the first decade or so, the NRC monitoring 

may have given the licensee approval to program 

discontinue the program. However, if a 

de-watering system is relied upon for 

control of settlement, then the licensee is 

to ensure proper functioning of the
11 Containment Structures B3.2 BWR Mark III Cnnd~r~tA C~nntainmennt_,

z 

m 

0 30 

w 

co 

o 

0 

0•

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

dewatering system through the period of 

extended operation. B3.2.1-g Concrete elements: Concrete; Flowing water Reduction in Chapter XI.S6, "Structures Monitoring No, if 

porous under foundation Program" within the Foundation; subfoundation concrete foundation strength, cracking, scope of 

differential Erosion of cement from porous concrete the 

settlement / subfoundations beneath containment applicant's Erosion of porous basemats is described in IN 97-11. IN structures 

concrete 98-26 proposes Maintenance Rule monitoring 

subfoundation Structures Monitoring for managing this program 

aging effect, if applicable. If a de

watering system is relied upon for 

control of erosion of cement from porous 

concrete subfoundations, then the 

licensee is to ensure proper functioning 

of the de-watering system through the 

period of extended operation. B3.2.1-h Concrete elements: Concrete Inside or Reduction of Plarnt-specific aging management Yes, if 

outside strength and program applicable Dome; wall; basemat containment modulus / 

Elevated The implementation of 10 CFR 50.55a 

temperature and IWL would not be able to identify the 

(>150°F general; reduction of strength and modulus due 

>200°F local) to elevated temperature. Thus, for any 

portions of concrete containment that 

exceed specified temperature limits, 

further evaluations are warranted. 

Subsection CC-3400 of ASME Section 

III, Division 2, specifies the concrete 

temperature limits for normal operation 

or any other long-term period. The 

temperatures shall not exceed 150°F 

except for local areas, such as around 

penetrations, which are not allowed to
( ( (

Containment Structures 

B3.2 BWR Mark III Concrete Containments 

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

exceed 2000F. If significant equipment 

loads are supported by concrete at 

temperatures exceeding 1500F, an 

evaluation of the ability to withstand the 

postulated design loads is to be made. 

Higher temperatures than given above 

may be allowed in the concrete if tests 

and/or calculations are provided to 

evaluate the reduction in strength and 

this reduction is applied to the design 

allowables. 

B3.2.2-a Steel elements: Carbon Inside or Loss of material / Chapter XI.S1, "ASME Section Xl, Yes, if 

steel outside Corrosion Subsection IWE" corrosion is 

Containment liner; containment significant suppression chamber liner; For inaccessible areas (embedded for 

basemat liner; liner anchors containment steel shell or liner), loss of inaccess

material due to corrosion is not ible areas 

significant if the following conditions are 

satisfied: 

1. Concrete meeting the requirements 

of ACI 318 or 349 and the guidance of 201.2R was used for the 

containment concrete in contact with 

the embedded containment shell or 

liner. 

2. The concrete is monitored to ensure 

that it is free of penetrating cracks 

that provide a path for water 

seepage to the surface of the 

containment shell or liner.
I1 Containment Structures B3.2 BWR Mark III Concrete Containments

z 

C 

m 

0 

00 

.0

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

3. The moisture barrier, at the junction 

where the shell or liner becomes 

embedded, is subject to aging 

management activities in 

accordance with IWE requirements. 4. Borated water spills and water 

ponding on the containment 

concrete floor are not common and 

when detected are cleaned up in a 

timely manner. 

If any of the above conditions cannot be 

satisfied, then a plant-specific aging 

management program for corrosion is 

required. 

Chapter XI.S4, "10 CFR Part 50, No 

Appendix J" 

If a coatings program is credited for No 

managing loss of material due to 

corrosion during the current licensing 

term (e.g., relief request from IWE), then 

it is to be continued during the period of 

extended operation. See Chapter XI.S8, 

"Protective Coating Monitoring and 

Maintenance program" B3.2.2-b Steel elements: Stainless Inside or Crack initiation Chapter XI.S1, "ASME Section XI, No 

steel outside and growth / Subsection IWE" and Chapter XI.S4, Suppression chamber liner containment Stress corrosion "10 CFR Part 50, Appendix J" 

.(interior surface) cracking

l,
B4. COMMON COMPONENTS

B4.1 Penetration Sleeves, Penetration Bellows, Dissimilar Metal Welds 

B4.2 Personnel Airlock, Equipment Hatch, Control Rod Drive (CRD) Hatch 

B4.3 Seals, Gaskets, and Moisture Barriers

April 2001 II 14-1 NUREG-1801
B4. COMMON COMPONENTS

Systems, Structures, and Components 

This section addresses the common components of BWR containments. The common 

components include penetration sleeves and bellows; dissimilar metal welds; personnel airlock; 

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

System Interfaces 

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

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

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

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

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

NSSS components and containment internal structures.

NUREG-1801 11134-2 April 2001
Containment Structures B4 BWR Containment Common Components 11 0 

r\3 

0 

0

(

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.1 -a Penetration sleeves Carbon Inside or Loss of material / Chapter XI.S1, "ASME Section Xl, No 

steel; outside Corrosion Subsection IWE" 

dissimilar containment 

metal (Note: IWE examination category E-F, 

welds surface examination of dissimilar metal 

welds, is optional) 

Chapter XI.S4, "10 CFR Part 50, No Appendix J" 

If a coatings program is credited for No 

managing loss of material due to 

corrosion during the current licensing 

term (e.g., relief request from IWE), then 

it is to be continued during the period of 

extended operation. See Chapter XI.S8, 

"Protective Coating Monitoring and 

Maintenance Program" 

B4.1 -b Penetration sleeves; Carbon Inside or Cumulative Fatigue is a time-limited aging analysis Yes, 

penetration bellows steel, outside fatigue damage / (TLAA) to be evaluated for the period of TLAA 

stainless containment Fatigue extended operation. See the Standard 

steel; Review Plan, Section 4.6, "Containment 

dissimilar (Only if CLB Liner Plate and Penetration Fatigue 

metal fatigue analysis Analysis," for acceptable methods for 

welds exists) meeting the requirements of 

.__10 CFR 54.21 (c).

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11 Containment Structures 

B4 BWR Cnntainment r.nmmnn (~nmnnn nto

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.1 -c Penetration sleeves; Carbon Inside or Cracking / Cyclic Chapter XI.S1 "ASME Section XI, Yes, penetration bellows steel; outside loading Subsection IWE "and Chapter XI.S4, detection 

stainless containment "10 CFR Part 50, Appendix J" of aging steel effects is to 

dissimilar (CLB fatigue Evaluation of 10 CFR 50.55a/IWE is be 

metal analysis does not augmented as follows: evaluated 

welds exist) 

(4) Detection of Aging Effects: 

VT-3 visual inspection may not detect 

fine cracks. B4.1-d Penetration sleeves; Stainless Inside or Crack initiation Chapter XI.S1, "ASME Section XI, Yes, penetration bellows steel; outside and growth / Subsection IWE" and Chapter XI.S4, detection 

dissimilar containment Stress corrosion "10 CFR Part 50, Appendix J" of aging metal cracking effects is to 

welds Evaluation of 10 CFR 50.55a/IWE is be 

augmented as follows: evaluated 

(4) Detection of Aging Effects: 

Stress corrosion cracking (SCC) is a 

concern for dissimilar metal welds. In the 

case of bellows assemblies, SCC may 

cause aging effects particularly if the 

material is not shielded from a corrosive 

environment. Subsection IWE covers 

inspection of these items under 

examination categories E-B, E-F, and 

E-P (10 CFR Part 50, Appendix J 

pressure tests). 10 CFR 50.55a 

identifies examination categories E-B 

and E-F as optional during the current 

term of operation. For the extended 

period of operation, Examination 

Categories E-B & E-F, and additional 

appropriate examinations to detect SCC 

in bellows assemblies and dissimilar

-o 

0

,
(

11 Containment Structures B4 BWR Containment Common Comoonents

(

-0 

N1

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

(continued) 

metal welds are warranted to address 

this issue. 

(10) Operating Experience: 

IN 92-20 describes an instance of 

containment bellows cracking, resulting in loss of leak tightness. B4.2-a Personnel airlock; equipment Carbon Inside or Loss of material / Chapter XI.S1, "ASME Section XI, No 

hatch; CRD hatch steel outside Corrosion Subsection IWE" 

containment 

Chapter XI.S4, "10 CFR Part 50, No 

Appendix J" 

If a coatings program is credited for No 

managing loss of material due to 

corrosion during the current licensing 

term (e.g., relief request from IWE), then 

it is to be continued during the period of 

extended operation. See Chapter XI.S8, 

"Protective Coating Monitoring and 

Maintenance Program." B4.2-b Personnel airlock; equipment Carbon Inside or Loss of leak Chapter XI.S4, "10 CFR Part 50, No 

hatch; CRD hatch: steel outside tightness in Appendix J" and 

containment closed position / 

Locks, hinges, and closure Mechanical wear Plant Technical Specifications 

mechanisms of locks, hinges 

and closure 

mechanisms

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Containment Structures 

B4 BWR Containment Common Components 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.3-a Seals, gaskets, and moisture Various Inside or Loss of sealing; Chapter XI.S1, "ASME Section XI, No 

barriers (caulking, flashing, outside leakage through Subsection IWE" 

and other sealants) containment containment / 

Deterioration of Leak tightness will be monitored by seals, gaskets, 10 CFR Part 50, Appendix J Leak Rate 

and moisture Tests for pressure boundary, seals and 

barriers (caulking, gaskets (including O-rings). flashing, and 

other sealants)

U, 

4 

-D
CHAPTER III 

STRUCTURES AND COMPONENT SUPPORTS

April 2001 1II-i NUREG-1801
This Page Intentionally Left Blank

NUREG-1801 IIl-ii April 2001
STRUCTURES AND COMPONENT SUPPORTS

Chapter III A: 

Chapter III B:

Class 1 Structures 

Component Supports

April 2001 III-iii NUREG-1801
This Page Intentionally Left Blank

NUREG-1801 April 2001 Ill-iv
CLASS 1 STRUCTURES 

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

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

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

Bldg., Switchgear Rm., AFW Pumphouse, Utility/Piping Tunnels) 

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) 

A8. Group 8 Structures (Steel Tanks) 

A9. Group 9 Structures (BWR Unit Vent Stack)

April 2001 III A-i NUREG-1801
This Page Intentionally Left Blank

NUREG-1801 III A-ii April 2001
Al. GROUP 1 STRUCTURES (BWR REACTOR BLDG., PWR SHIELD BLDG., CONTROL 

RMJBLDG.) 

A1.1 Concrete Elements 

A1.2 Steel Elements 

A1.3 Masonry Walls

April 2001 III A1-1 NUREG-1801
Al. GROUP 1 STRUCTURES (BWR REACTOR BLDG., PWR SHIELD BLDG., CONTROL 

RMJBLDG.) 

Systems, Structures, and Components 

Class 1 structures are organized into nine groups and are discussed separately under 

subheadings Al through A9. This section addresses the elements of BWR reactor building, 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-1 801 III A1-2 April 2001
lii

(

Structures and Component Supports A1l I~rnun 1 Rtru~turA• IRWR R~Antotr Bid, .. PWR Shield Rlda.. Control Room/Bldd.l

f\3 

0 

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

Al.1-a Concrete: Reinforced Weather Loss of material Chapter XI.S6, "Structures Monitoring No, if within 

Exterior above and below concrete exposed (spalling, scaling) Program" the scope of 

grade; foundation and cracking the 

Freeze-thaw As described in NUREG-1557, freeze- applicant's 

thaw does not cause loss of material structures 

from reinforced concrete in foundations, monitoring 

and in above- and below-grade exterior program 

concrete, for plants located in a 

geographic region of negligible 

weathering conditions (weathering 

index <100 day-inch/yr). Loss of 

material from such concrete is not 

significant at plants located in areas in 

which weathering conditions are severe 

(weathering index >500 day-inch/yr) or 

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

provided that the concrete mix design 

meets the air content (entrained air 

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

(0.35-0.45) specified in ACI 318-63 or 

ACI 349-85. Therefore, if these 

conditions are satisfied, aging 

management is not required. 

The weathering index is defined in 

ASTM C33-90, Table 3, Footnote E. 

Fig. 1 of ASTM C33-90 illustrates the 

various weathering index regions 

throughout the U.S.

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mi. uroup I Structures twHi Reactor ua .W R ne., hielontrol Room Bldg.) 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

Al.1-b Concrete: Reinforced Flowing water Increase in Chapter XI.S6, "Structures Monitoring No, if wiihin Exterior above and below concrete porosity and Program" the scope of grade; foundation permeability, loss the 

of strength / As described in NUREG-1557, leaching applicant's Leaching of of calcium hydroxide from reinforced structures 

calcium hydroxide concrete becomes significant only if the monitoring 

concrete is exposed to flowing water, program 

Even if reinforced concrete is exposed 

to flowing water, such leaching is not 

significant if the concrete is constructed 

to ensure that it is dense, well-cured, 

has low permeability, and that cracking is well controlled. Cracking is controlled 

through proper arrangement and 

distribution of reinforcing bars. All of the 

above characteristics are assured if the 

concrete was constructed with the 

guidance of ACI 201.2R-77. Therefore, 

if these conditions are satisfied, aging 

management is not required.
(

III Structures and Component Supports

( (

V 

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0O 

0 

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

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

Al. 1 -c Concrete: Reinforced Any Expansion and Chapter XI.S6, "Structures Monitoring No, if within 

All concrete cracking / Program" the scope of 

Reaction with the 

aggregates As described in NUREG-1557, applicant's 

investigations, tests, and petrographic structures 

examinations of aggregates performed monitoring in accordance with ASTM C295-54 or program 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregate

reinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with 

ACI 201.2R-77. Therefore, if these 

conditions are satisfied, aging 

management is not required.

z 

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Structures Al. GrouD and Component Supports 1 Structures tBWR Reactor Bldn . PWR Rhlh~ld Rlrdn (~nntr,•l P,,•m/l~l,j,,,

III z C 

m 

00 IR Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A1.1-d Concrete: Reinforced Exposure to Cracking, loss of Chapter XI.S6, "Structures Monitoring No, if within Interior and above-grade concrete aggressive bond, loss of Program" the scope of exterior environment material (spalling, the 

scaling) / As described in NUREG-1557, applicant's Corrosion of corrosion of exterior above-grade and structures 

embedded steel interior embedded steel is not monitoring significant if the steel is not exposed to program 

an aggressive environment (concrete 

pH <11.5 or chlorides >500 ppm). If 

such steel is exposed to an aggressive 

environment, corrosion is not significant if the concrete in which the steel is 

embedded has a low water-to-cement 

ratio (0.35-0.45), adequate air 

entrainment (3-6%), low permeability, 

and is designed in accordance with 

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

these conditions are satisfied, aging 

management is not required.

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Structures and Component Supports

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0. Al. Group 1 Structures (BWR Reactor Bid ., PWR Snield Blag., uontroi Room /,ag._ 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

Al.1-e Concrete: Reinforced Exposure to Cracking, loss of A plant-specific aging management Yes, if an 

Below-grade exterior; concrete aggressive bond, loss of program is required only if the below- aggressive 

foundation environment material (spalling, grade environment is aggressive below-grade 

scaling) / (pH < 5.5, chlorides >500ppm, or environment 

Corrosion of sulfates > 1500 ppm). Examination of exists 

embedded steel representative samples of below-grade 

concrete, when excavated for any 

reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of 

below-grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade 

environment is not aggressive. 

Al.1-f Concrete: Reinforced Exposure to Increase in Chapter XLS6, "Structures Monitoring No, if within 

Interior and above-grade concrete aggressive porosity and Program" the scope of 

exterior environment permeability, the 

cracking, loss of As described in NUREG-1557, applicant's 

material (spalling, aggressive chemical attack on interior structures 

scaling) / and above-grade exterior reinforced monitoring 

Aggressive concrete is not significant if the program 

chemical attack concrete is not exposed to an 

aggressive environment (pH <5.5), or to 

chloride or sulfate solutions beyond 

defined limits (>500 ppm chloride, or 

>1500 ppm sulfate). Therefore, if these 

conditions are satisfied, aging 

management is not required.

z 

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III Structures and Component Supports z 

C: 

m 

0O 9

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0

K

Al. Caroup 1 Structures (•WR Reactor Bldg., PWR Shield Bldg., Control Room/Bldg.) 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation Al.1-g Concrete: Reinforced Exposure to' Increase in A plant-specific aging management Yes, if an Below-grade exterior; concrete aggressive porosity and program is required only if the below- aggressive foundation environment permeability, grade environment is aggressive below-grade 

cracking, loss of (pH < 5.5, chlorides >500 ppm, or environment 

material (spalling, sulfates >1500 ppm). Examination of exists 

scaling) / representative samples of below-grade Aggressive concrete, when excavated for any 

chemical attack reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of 

below-grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade environment is not aggressive. Al.1-h Concrete: Reinforced Soft soil; Cracks; Chapter XI.S6, "Structures Monitoring No, if within All concrete changes in distortion; Program" the scope of 

groundwater increase in the 

conditions component stress The initial Licensing Basis for some applicant's level / plants included a program to monitor structures 

Settlement settlement. If no settlement was evident monitoring during the first decade or so, the NRC program 

may have given the licensee approval 

to discontinue the program. However, if 

a de-watering system is relied upon for 

control of settlement, then the licensee 

is to ensure proper functioning of the 

de-watering system through the period I of extended operation.
( (i

III Structures and Component Supports Al. Group 1 Structures (BWR Rsn~tntr Rldn__ PWR •hh=IdI

C 

Co

(

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation Al.1-i Concrete: Reinforced Flowing water Reducti'on in Chapter XI.S6, "Structures Monitoring No, if within Foundation; concrete; under foundation Program" the scope of subfoundation porous foundation strength, cracking, the 

concrete differential Erosion of cement from porous applicant's settlement / concrete subfoundations beneath structures 

Erosion of porous containment basemats is described in monitoring 

concrete IN 97-11. IN 98-26 proposes program subfoundation Maintenance Rule Structures 

Monitoring for managing this aging 

effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous concrete 

subfoundations, then the licensee is to 

ensure proper functioning of the de

watering system through the period of 

extended operation. Al.1-j Concrete: Reinforced Outside Reduction of Plant-specific aging management Yes, if All concrete containment strength and program applicable 

modulus / 

Elevated For any concrete elements that exceed 

temperature specified temperature limits, further 

(>1 50°F general; evaluations are warranted. Appendix A 

>200°F local) of ACI 349-85 specifies the concrete 

temperature limits for normal operation 

or any other long-term period. The 

temperatures shall not exceed 150OF 

except for local areas which are allowed 

to have increased temperatures not to 

I exceed 2000F.

z 

C 

:z m 0n 

OD 

0
III Structures and Component Supports z 

C 

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G) 

0 

0

0 

0

K

1. Group 1 Structures (BWR Reactor Bid ., PWR Shield Bldg., Control RoomBldg.) 

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A1.2-a Steel components: Carbon Various Loss of material / Chapter XI.S6, "Structures Monitoring No, if within All structural steel steel Corrosion Program" the scope of 

the 

If protective coatings are relied upon to applicant's 

manage the effects of aging, the structures 

structures monitoring program is to monitoring include requirements to address program 

protective coating monitoring and 

maintenance. A1.3-a Masonry walls: Concrete Ambient Cracking / Chapter Xl.S5, "Masonry Wall Program" No 

All block environment Restraint; 

inside building shrinkage; creep; 

aggressive 

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

A2.1 Concrete Elements 

A2.2 Steel Elements 

A2.3 Masonry Walls

April 2001 III A2-1 NUREG-1801
A2. GROUP 2 STRUCTURES (BWR REACTOR BLDG. WITH STEEL SUPERSTRUCTURE) 

Systems, Structures, and Components 

Class 1 structures are organized into nine groups and are discussed separately under 

subheadings Al through A9. This section addresses the elements of 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-1 801 III A2-2 April 2001
(

III Structures and Component Supports A2. Groun 2 Stru•tuires RWR Reactor Rlln B ;tl fk Qf I Q..iv I,.. ,,.i

(

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0 0o

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A2.1-a Concrete: Reinforced Weather Loss of material Chapter XI.S6, "Structures Monitoring No, if within 

Exterior above and below concrete exposed (spalling, scaling) Program" the scope of grade; foundation and cracking / the 

Freeze-thaw As described in NUREG-1557, freeze- applicant's 

thaw does not cause loss of material structures 

from reinforced concrete in foundations, monitoring 

and in above- and below-grade exterior program 

concrete, for plants located in a 

geographic region of negligible 

weathering conditions (weathering 

index <100 day-inch/yr). Loss of 

material from such concrete is not 

significant at plants located in areas in 

which weathering conditions are severe 

(weathering index >500 day-inch/yr) or 

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

provided that the concrete mix design 

meets the air content (entrained air 

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

(0.35-0.45) specified in ACI 318-63 or 

ACI 349-85. Therefore, if these 

conditions are satisfied, aging 

management is not required. 

The weathering index is defined in 

ASTM C33-90, Table 3, Footnote E. 

Fig. 1 of ASTM C33-90 illustrates the 

various weathering index regions throughout the U.S.

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G. uroup z .iructures UWH Hleactor Bid with Steel Superstructure 

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A2.1-b Concrete: Reinforced Flowing water Increase in Chapter XI.S6, "Structures Monitoring No, if within Exterior above and below concrete porosity and Program" the scope of grade; foundation permeability, loss the 

of strength / As described in NUREG-1557, leaching applicant's Leaching of of calcium hydroxide from reinforced structures 

calcium hydroxide concrete becomes significant only if the monitoring concrete is exposed to flowing water. program Even if reinforced concrete is exposed 

to flowing water, such leaching is not 

significant if the concrete is constructed 

to ensure that it is dense, well-cured, 

has low permeability, and that cracking 

is well controlled. Cracking is controlled 

through proper arrangement and 

distribution of reinforcing bars. All of the 

above characteristics are assured if the 

concrete was constructed with the 

guidance of ACI 201.2R-77. Therefore, if these conditions are satisfied, aging management is not required.______

o 0

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III Structures and Component Supports A2. Group 2 Structures (BWR Reactor Bldg with Steel Su erstructure) 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A2.1-c Concrete: Reinforced Any Expansion and Chapter XI.S6, "Structures Monitoring No, if within 

All concrete cracking / Program" the scope of 

Reaction with the 

aggregates As described in NUREG-1557, applicant's 

investigations, tests, and petrographic structures 

examinations of aggregates performed monitoring 

in accordance with ASTM C295-54 or program 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregate

reinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with 

ACI 201.2R-77. Therefore, if these 

conditions are satisfied, aging 

management is not required.

z 

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m XJ 

00 

Cý
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m 

0)

III Structures and Component Supports A2. Group 2 Structures (BWR Reactor Bidg. with Steel Su erstructure) 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A2.1-d Concrete: Reinforced Exposure to Cracking, loss of Chapter XI.S6, "Structures Monitoring No, if within Interior and above-grade concrete aggressive bond, loss of Program" the scope of exterior environment material (spalling, the 

scaling) / As described in NUREG-1557, applicant's Corrosion of corrosion of exterior above-grade and structures 

embedded steel interior embedded steel is not monitoring 

significant if the steel is not exposed to program 

an aggressive environment (concrete 

pH <11.5 or chlorides >500 ppm). If 

such steel is exposed to an aggressive 

environment, corrosion is not significant 

if the concrete in which the steel is 

embedded has a low water-to-cement 

ratio (0.35-0.45), adequate air 

entrainment (3-6%), low permeability, 

and is designed in accordance with 

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

these conditions are satisfied, aging 

management is not required.

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0?
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III Structures and Component Supports A2. Group 2 Structures (BWR Reactor BIdn with SteeI Su erctrtfilrg

ro 

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m 

0 cO 

C?

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A2.1 -e Concrete: Reinforced Exposure to Cracking, loss of A plant-specific aging management Yes, if an 

Below-grade exterior; concrete aggressive bond, loss of program is required only if the below- aggressive foundation environment material (spalling, grade environment is aggressive below-grade 

scaling) / (pH <5.5, chlorides >500 ppm, or environment 

Corrosion of sulfates >1500 ppm). Examination of exists 

embedded steel representative samples of below-grade 

concrete, when excavated for any 

reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of 

below-grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade 

environment is not aggressive. A2.1-f Concrete: Reinforced Exposure to Increase in Chapter XI.S6, "Structures Monitoring No, if within 

Interior and above-grade concrete aggressive porosity and Program" the scope of 

exterior environment permeability, the 

cracking, loss of As described in NUREG-1557, applicant's 

material (spalling, aggressive chemical attack on interior structures 

scaling) / and above-grade exterior reinforced monitoring 

Aggressive concrete is not significant if the program 

chemical attack concrete is not exposed to an 

aggressive environment (pH <5.5), or to 

chloride or sulfate solutions beyond 

defined limits (>500 ppm chloride, or 

>1500 ppm sulfate). Therefore, if these 

conditions are satisfied, aging 

management is not required.
III Structures and Component Supports A2. Group 2 Structures (BWR Reactor Bld . with Steel Su erstructurel

z 

C 

m 

OD 

R

SOTI SOil; 

changes in 

ground-water 

conditions

Cracks; distortion; 

increase in 

component stress 

level/ 

Settlement

L ____________ I

Chapter XI.S6, "Structures Monitoring 

Program" 

The initial Licensing Basis for some 

plants included a program to monitor 

settlement. If no settlement was evident 

during the first decade or so, the NRC 

may have given the licensee approval 

to discontinue the program. However, if 

a de-watering system is relied upon for 

control of settlement, then the licensee 

is to ensure proper functioning of the 

de-watering system through the period of etendd opration.

of opertion exende 

No, if within 

the scope of 

the 

applicant's 

structures 

monitoring 

program

(

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A2.1-g Concrete: Reinforced Exposure to Increase in A plant-specific aging management Yes, if an Below-grade exterior; concrete aggressive porosity and program is required only if the below- aggressive foundation environment permeability, grade environment is aggressive below-grade cracking, loss of (pH <5.5, chlorides >500ppm, or environment 

material (spalling, sulfates >1 500ppm). Examination of exists 

scaling) / representative samples of below-grade Aggressive concrete, when excavated for any 

chemical attack reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of 

below-grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade environment is not aggressive.

Ko 

0 

0R

,'t *I -I %All I VMS All r-einforced 

concrete
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III Structures and Component Supports A2. Group 2 Structures (BWR Reactor Bldg. with Steel Su erstructure) 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A2.1 -i Concrete: Reinforced Flowing water Reduction in Chapter XI.S6, "Structures Monitoring No, if within Foundation; concrete; under foundation Program" the scope of subfoundation porous foundation strength, cracking, the 

concrete differential Erosion of cement from porous applicant's 

settlement / concrete subfoundations beneath structures 

Erosion of porous containment basemats is described in monitoring 

concrete IN 97-11. IN 98-26 proposes program 

subfoundation Maintenance Rule Structures 

Monitoring for managing this aging 

effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous concrete 

subfoundations, then the licensee is to 

ensure proper functioning of the de

watering system through the period of 

extended operation. A2.1-j Concrete: Reinforced Outside Reduction of Plant-specific aging management Yes, if All concrete containment strength and program applicable 

modulus / 

Elevated For any concrete elements that exceed 

temperature specified temperature limits, further 

(>1 50'F general; evaluations are warranted. Appendix A 

>200°F local) of ACI 349-85 specifies the concrete 

temperature limits for normal operation 

or any other long-term period. The 

temperatures shall not exceed 150OF 

except for local areas which are 

allowed to have increased 

temperatures not to exceed 2000 F.

z 

m 

O0 !
Structures and Component Supports A2. Group 2 Structures (BWR Reactor BIdo. with Steel R~in •r~trm~ntmlr==•

III z 

C 

00 

0 

ITI 

0 

0

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A2.2-a Steel components: Carbon Various Loss of material / Chapter XI.S6, "Structures Monitoring No, if within All structural steel steel Corrosion Program" the scope of 

the 

If protective coatings are relied upon to applicant's 

manage the effects of aging, the structures 

structures monitoring program is to monitoring include requirements to address program 

protective coating monitoring and 

maintenance. A2.3-a Masonry walls: Concrete Ambient Cracking / Chapter XI.S5, "Masonry Wall Program" No 

All block environment Restraint; 

inside building shrinkage; creep; 

aggressive 

environment

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

RADWASTE BLDG., TURBINE BLDG., SWITCHGEAR RM., AFW PUMPHOUSE, 

UTILITY/PIPING TUNNELS) 

A3.1 Concrete Elements 

A3.2 Steel Elements 

A3.3 Masonry Walls

April 2001 III A3-1 NUREG-1801
A3. GROUP 3 STRUCTURES (AUXILIARY BLDG., DIESEL GENERATOR BLDG., 

RADWASTE BLDG., TURBINE BLDG., SWITCHGEAR RM., AFW PUMPHOUSE, 

UTILITY/PIPING TUNNELS) 

Systems, Structures, and Components 

Class 1 structures are organized into nine groups and are discussed separately under 

subheadings Al through A9. This section addresses the elements of auxiliary building, diesel 

generator building, radwaste building, turbine building, switchgear room, AFW pumphouse, and 

utility/piping tunnels. 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 III A3-2 April 2001
III Structures and Component Supports 

A3. Group 3 Structures (Auxiliary, Diesel Generator, Radwaste, and Turbine Buildings; Switchgear Room, AFW Pumphouse, 

Utility/Piping Tunnels) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A3.1-a Concrete: Reinforced Weather Loss of material Chapter XI.S6, "Structures Monitoring No, if within 

Exterior above and below concrete exposed (spalling, scaling) Program" the scope of 

grade; foundation and cracking / the 

Freeze-thaw As described in NUREG-1557, freeze- applicant's 

thaw does not cause loss of material structures 

from reinforced concrete in foundations, monitoring 

and in above- and below-grade exterior program 

concrete, for plants located in a 

geographic region of negligible 

weathering conditions (weathering 

index <100 day-inch/yr). Loss of 

material from such concrete is not 

significant at plants located in areas in 

which weathering conditions are severe 

(weathering index >500 day-inch/yr) or 

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

provided that the concrete mix design 

meets the air content (entrained air 

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

(0.35-0.45) specified in ACI 318-63 or 

ACI 349-85. Therefore, if these 

conditions are satisfied, aging 

management is not required. 

The weathering index is defined in 

ASTM C33-90, Table 3, Footnote E. 

Fig. 1 of ASTM C33-90 illustrates the 

various weathering index regions 

throughout the U.S.
z 

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III Structures and Component Supports 

A3. Group 3 Structures (Auxiliary, Diesel Generator, Radwaste, and Turbine Buildings; Switchgear Room, AFW Pumphouse, 

Utility/Piping Tunnels) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A3.1 -b Concrete: Reinforced Flowing water Increase in Chapter XI.S6, "Structures Monitoring No, if within 

Exterior above and below concrete porosity and Program" the scope of 

grade; foundation permeability, loss the 

of strength / As described in NUREG-1557, leaching applicant's 

Leaching of of calcium hydroxide from reinforced structures 

calcium hydroxide concrete becomes significant only if the monitoring 

concrete is exposed to flowing water. program 

Even if reinforced concrete is exposed 

to flowing water, such leaching is not 

significant if the concrete is constructed 

to ensure that it is dense, well-cured, 

has low permeability, and that cracking 

is well controlled. Cracking is controlled 

through proper arrangement and 

distribution of reinforcing bars. All of the 

above characteristics are assured if the 

concrete was constructed with the 

guidance of ACl 201.2R-77. Therefore, 

if these conditions are satisfied, aging 

I management is not required.

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Structures and Component Supports A3. Group 3 Structures (Auxiliary, Diesel Generator, Radwaste, and Turbine Buildings; Switchgear Room, AFW Pumphouse, Utility/Piping Tunnels) 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A3.1 -c Concrete: Reinforced Any Expansion and Chapter XI.S6, "Structures Monitoring No, if within 

All concrete cracking / Program" the scope of 

Reaction with the 

aggregates As described in NUREG-1557, applicant's 

investigations, tests, and petrographic structures 

examinations of aggregates performed monitoring 

in accordance with ASTM C295-54 or program 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregate

reinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with 

ACI 2011.2R-77. Therefore, if these 

conditions are satisfied, aging 

management is not required.

z C 

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III Structures and Component Supports A3. Group 3 Structures (Auxiliary, Diesel Generator, Radwaste, and Turbine Buildings; Switchgear Room, AFW Pumphouse, 

Utility/Piping Tunnels) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A3.1 -d Concrete: Reinforced Exposure to Cracking, loss of Chapter XI.S6, "Structures Monitoring No, if within 

Interior and above-grade concrete aggressive bond, loss of Program" the scope of 

exterior environment material (spalling, the 

scaling) / As described in NUREG-1557, applicant's 

Corrosion of corrosion of exterior above-grade and structures 

embedded steel interior embedded steel is not monitoring significant if the steel is not exposed to program 

an aggressive environment (concrete 

pH <11.5 or chlorides >500 ppm). If 

such steel is exposed to an aggressive 

environment, corrosion is not significant 

if the concrete in which the steel is 

embedded has a low water-to-cement 

ratio (0.35-0.45), adequate air 

entrainment (3-6%), low permeability, 

and is designed in accordance with 

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

these conditions are satisfied, aging 

I management is not required.
( ( (

0_

III Structures and Component Supports 

A3. Group 3 Structures (Auxiliary, Diesel Generator, Radwaste, and Turbine Buildings; Switchgear Room, AFW Pumphouse, 

Utility/Piping Tunnels) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A3.1 -e Concrete: Reinforced Exposure to Cracking, loss of A plant-specific aging management Yes, if an 

Below-grade exterior; concrete aggressive bond, loss of program is required only if the below- aggressive 

foundation environment material (spalling, grade environment is aggressive below-grade 

scaling) / (pH <5.5, chlorides >500 ppm, or environment 

corrosion of sulfates >1 500ppm). Examination of exists 

embedded steel representative samples of below-grade 

concrete, when excavated for any 

reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of 

below-grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade 

environment is not aggressive. 

A3.1-f Concrete: Reinforced Exposure to Increase in Chapter XI.S6, "Structures Monitoring No, if within 

Interior and above-grade concrete aggressive porosity and Program" the scope of 

exterior environment permeability, the 

cracking, loss of As described in NUREG-1557, applicant's 

material (spalling, aggressive chemical attack on interior structures 

scaling) / and above-grade exterior reinforced monitoring 

Aggressive concrete is not significant if the program 

chemical attack concrete is not exposed to an 

aggressive environment (pH <5.5), or to 

chloride or sulfate solutions beyond 

defined limits (>500 ppm chloride, or 

>1500 ppm sulfate). Therefore, if these 

conditions are satisfied, aging 

management is not required.

z 

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Structures and Component Supports A3. Group 3 Structures (Auxiliary, Diesel Generator, Radwaste, and Turbine Buildings; Switchgear Room, AFW Pumphouse, Utility/Piping Tunnels) 

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A3.1-g Concrete: Reinforced Exposure to Increase in A plant-specific aging management Yes, if an Below-grade exterior; concrete aggressive porosity and program is required only if the below- aggressive foundation environment permeability, grade environment is aggressive below-grade cracking, loss of (pH <5.5, chlorides >500 ppm, or environment 

material (spalling, sulfates >1500 ppm). Examination of exists 

scaling) / representative samples of below-grade 

Aggressive concrete, when excavated for any chemical attack reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of 

below-grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade 

environment is not aggressive. A3.1-h Concrete: Reinforced Soft soil; Cracks; distortion; Chapter XI.S6, "Structures Monitoring No, if within All concrete changes in increase in Program" the scope of 

ground-water component stress the 

conditions level / The initial Licensing Basis for some applicant's Settlement plants included a program to monitor structures 

settlement. If no settlement was evident monitoring 

during the first decade or so, the NRC program 

may have given the licensee approval to discontinue the program. However, if 

a de-watering system is relied upon for 

control of settlement, then the licensee 

is to ensure proper functioning of the 

de-watering system through the period I of extended operation.
(. ( 

C

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0 Co 

z 

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00 9 0

III Structures and Component Supports 

A3. Group 3 Structures (Auxiliary, Diesel Generator, Radwaste, and Turbine Buildings; Switchgear Room, AFW Pumphouse, 

Utility/Piping Tunnels) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A3.1-i Concrete: Reinforced Flowing water Reduction in Chapter XI.S6, "Structures Monitoring No, if within 

Foundation; concrete; under foundation Program" the scope of 

subfoundation porous foundation strength, cracking, the 

concrete differential Erosion of cement from porous applicant's 

settlement / concrete subfoundations beneath structures 

Erosion of porous containment basemats is described in monitoring 

concrete IN 97-11. IN 98-26 proposes program 

subfoundation Maintenance Rule Structures 

Monitoring for managing this aging 

effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous concrete 

subfoundations, then the licensee is to 

ensure proper functioning of the de

watering system through the period of 

extended operation. 

A3.1 -j Concrete: Reinforced Outside Reduction of Plant-specific aging management Yes, if 

All concrete containment strength and program applicable 

modulus / 

Elevated For any concrete elements that exceed 

temperature specified temperature limits, further 

(>1 50°F general; evaluations are warranted. Appendix A 

>200°F local) of ACI 349-85 specifies the concrete 

temperature limits for normal operation 

or any other long-term period. The 

temperatures shall not exceed 150OF 

except for local areas which are 

allowed to have increased 

temperatures not to exceed 2000 F.
z 

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III Structures and Component Supports A3. Group 3 Structures (Auxiliary, Diesel Generator, Radwaste, and Turbine Buildings; Switchgear Room, AFW Pumphouse, Utility/Piping Tunnels) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A3.2-a Steel components: Carbon Various Loss of material / Chapter XI.S6, "Structures Monitoring No, if within 

All structural steel steel Corrosion Program" the scope of 

the 

If protective coatings are relied upon to applicant's 

manage the effects of aging, the structures 

structures monitoring program is to monitoring 

include requirements to address program 

protective coating monitoring and 

maintenance. 

A3.3-a Masonry walls: Concrete Ambient Cracking / Chapter XI.S5, "Masonry Wall Program" No 

All block environment Restraint; 

inside building shrinkage; creep; 

aggressive 

I environment
A4. GROUP 4 STRUCTURES (CONTAINMENT INTERNAL STRUCTURES, EXCLUDING 

REFUELING CANAL) 

A4.1 Concrete Elements 

A4.2 Steel Elements

April 2001 III A4-11 NUREG-1801
A4. GROUP 4 STRUCTURES (CONTAINMENT INTERNAL STRUCTURES, EXCLUDING 

REFUELING CANAL) 

Systems, Structures, and Components 

Class 1 structures are organized into nine groups and are discussed separately under 

subheadings Al through A9. This section addresses the elements of containment internal 

structures, excluding refueling canal. For this group, the applicable structural elements are 

identified: concrete and steel elements. The aging management review is presented for each 

applicable combination of structural element and aging effect. 

System Interfaces 

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

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

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

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

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

parts of the systems that provide plant cooling water and residual heat removal.

NUREG-1 801 III A4-2 April 2001
( (

III Structures and Component Supports 

A4. Group 4 Structures (Containment Internal Structures.

(

Exciudino Refuelina] Canall -o 

o'

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A4.1 -a Concrete: Reinforced Inside Increase in Chapter XI.S6, "Structures Monitoring No, if within 

All concrete containment, porosity and Program" the scope of 

exposure to permeability, the 

aggressive cracking, loss of As described in NUREG-1557, applicant's environment material (spalling, aggressive chemical attack on interior structures 

scaling) / and above-grade exterior reinforced monitoring Aggressive concrete is not significant if the program 

chemical attack concrete is not exposed to an 

aggressive environment (pH <5.5), or to 

chloride or sulfate solutions beyond 

defined limits (>500 ppm chloride, or 

>1500 ppm sulfate). Therefore, if these 

conditions are satisfied, aging 

management is not required. A4.1-b Concrete: Reinforced Inside Expansion and Chapter XI.S6, "Structures Monitoring No, if within 

All concrete containment cracking / Program" the scope of 

Reaction with the 

aggregates As described in NUREG-1557, applicant's 

investigations, tests, and petrographic structures 

examinations of aggregates performed monitoring 

in accordance with ASTM C295-54 or program 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregate

reinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with 

ACI 201.2R-77. Therefore, if these 

conditions are satisfied, aging I management is not required. z 

C 

m 

M 

if, 

CD 

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III Structures and Component Supports A4. GrouD 4 Structures (Containment Internal Struictures Ehrxlminn Rafarnlin rannall

z 

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300 

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K

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A4.1 -c Concrete: Reinforced Inside Reduction of Plant-specific aging management Yes, if 

All concrete containment strength and program applicable 

modulus / 

Elevated For any concrete elements that exceed 

temperature specified temperature limits, further 

(>1 50°F general; evaluations are warranted. Appendix A 

>200°F local) of ACl 349-85 specifies the concrete 

temperature limits for normal operation 

or any other long-term period. The 

temperatures shall not exceed 150OF 

except for local areas which are 

allowed to have increased 

temperatures not to exceed 2000F. A4.1 -d Concrete: Reinforced inside Cracking, loss of Chapter XI.S6, "Structures Monitoring No, if within All concrete containment, bond, loss of Program" the scope of 

exposure to material (spalling, the 

aggressive scaling) / As described in NUREG-1557, applicant's environment Corrosion of corrosion of exterior above-grade and structures 

embedded steel interior embedded steel is not monitoring significant if the steel is not exposed to program 

an aggressive environment (concrete 

pH <11.5 or chlorides >500 ppm). If 

such steel is exposed to an aggressive 

environment, corrosion is not significant if the concrete in which the steel is 

embedded has a low water-to-cement 

ratio (0.35-0.45), adequate air 

entrainment (3-6%), low permeability, 

and is designed in accordance with 

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

these conditions are satisfied, aging 

management is not required.

Co 

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III Structures and Component Supports A4. Grnoin .•trlrtfira (E'onnainm~pn# In # ,l ,,

(

M. 

PO .... . -... ........... . .... , *~*n~5IIUI .- ,s ~JII •,u M~I .U, O UA0192u.0 nfIUe .n. .,danal) 

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A4.2-a Steel components: carbon Inside Loss of material / Chapter XI.S6, "Structures Monitoring No, if within All structural steel steel containment Corrosion Program" the scope of 

the If protective coatings are relied upon to applicant's 

manage the effects of aging, the structures 

structures monitoring program is to monitoring include requirements to address program protective coating monitoring and maintenance. 

A4.2-b Steel components: Lubrite Inside Lock-up / Wear Chapter XlIS6, "Structures Monitoring No, if within Radial beam seats in BWR containment Program" the scope of drywell; RPV support shoes the for PWR with nozzle applicant's supports structures 

monitoring 

program

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

A5.1 Concrete Elements 

A5.2 Steel Elements 

A5.3 Masonry Walls

April 2001 NUREG-1801 III A5-11
A5. GROUP 5 STRUCTURES (FUEL STORAGE FACILITY, REFUELING CANAL) 

Systems, Structures, and Components 

Class 1 structures are organized into nine groups and are discussed separately under 

subheadings Al through A9. This section addresses the elements of 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 III A5-2 April 2001
\,

III Structures and Component Supports A5. Grouip 5 Structures (Fuel Storaae Facility. Rafu~linn C anal•

V 

0 

C'

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A5.1-a Concrete Reinforced Weather Loss of Material Chapter XI.S6, "Structures Monitoring No, if within 

Exterior above and below concrete exposed (spalling, scaling) Program" the scope of 

grade; foundation and cracking the 

Freeze-thaw As described in NUREG-1557, freeze- applicant's 

thaw does not cause loss of material structures 

from reinforced concrete in foundations, monitoring 

and in above- and below-grade exterior program 

concrete, for plants located in a 

geographic region of negligible weathering conditions (weathering 

index <100 day-inch/yr). Loss of 

material from such concrete is not 

significant at plants located in areas in 

which weathering conditions are severe 

(weathering index >500 day-inch/yr) or 

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

provided that the concrete mix design 

meets the air content (entrained air 

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

(0.35-0.45) specified in ACI 318-63 or 

ACI 349-85. Therefore, if these 

conditions are satisfied, aging 

management is not required. 

The weathering index is defined in 

ASTM C33-90, Table 3, Footnote E. 

Fig. 1 of ASTM C33-90 illustrates the 

various weathering index regions 

throughout the U.S.

Z C: 

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Structures and Component Supports A5. Grouw, 5 Structures (Fuel Storeas Farillitv. R~fuAIinn O nlnI

III z C 

m 

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0 

0"I

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A5.1-b Concrete: Reinforced Flowing 'water Increase in Chapter XI.S6, "Structures Monitoring No, if within Exterior above and below concrete porosity and Program" the scope of grade; foundation permeability, loss the 

of strength / As described in NUREG-1 557, leaching applicant's Leaching of of calcium hydroxide from reinforced structures 

calcium hydroxide concrete becomes significant only if the monitoring 

concrete is exposed to flowing water, program 

Even if reinforced concrete is exposed to flowing water, such leaching is not 

significant if the concrete is constructed 

to ensure that it is dense, well-cured, 

has low permeability, and that cracking 

is well controlled. Cracking is controlled 

through proper arrangement and 

distribution of reinforcing bars. All of the 

above characteristics are assured if the 

concrete was constructed with the 

guidance of ACl 201.2R-77. Therefore, 

if these conditions are satisfied, aging 

management is not required.

-o 

"0 0
Structures and Component Supports 

A5. Group 5 Structures (Fuel Storaae Facil tv, Refuelina C nal)

III V 

0 

0 

i,

(

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A5.1-c Concrete: Reinforced Any Expansion and Chapter Xi.S6, "Structures Monitoring No, if within 

All concrete cracking / Program" the scope of 

Reaction with the 

aggregates As described in NUREG-1557, applicant's investigations, tests, and petrographic structures 

examinations of aggregates performed monitoring in accordance with ASTM C295-54 or program 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregate

reinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with 

ACI 201.2R-77. Therefore, if these 

conditions are satisfied, aging 

management is not required.

z 

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Structures and Component Supports A5. GrouD 5 Structures (Fuel Storaoe FaciltIv. Refuelina C anal•

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0 

0

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Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A5.1 -d Concrete: Reinforced Exposure to Cracking, loss of Chapter XI.S6, "Structures Monitoring No, if within Interior and above-grade concrete aggressive bond, loss of Program" the scope of exterior environment material (spalling, the 

scaling) / As described in NUREG-1557, applicant's Corrosion of corrosion of exterior above-grade and structures 

embedded steel interior embedded steel is not monitoring 

significant if the steel is not exposed to program 

an aggressive environment (concrete 

pH <11.5 or chlorides >500 ppm). If 

such steel is exposed to an aggressive 

environment, corrosion is not significant if the concrete in which the steel is 

embedded has a low water-to-cement 

ratio (0.35-0.45), adequate air 

entrainment (3-6%), low permeability, and is designed in accordance with 

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

these conditions are satisfied, aging 

management is not required.
(

M._ 

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III Structures and Component Supports A5. Group 5 Structures (Fuel Storage Facility, Refueling C nal) 

Structure and/or Aging Effect? Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A5.1 -e Concrete: Reinforced Exposure to Cracking, loss of A plant-specific aging management Yes, if an 

Fuel storage facility below concrete aggressive bond, loss of program is required only if the below- aggressive grade exterior; foundation environment material (spalling, grade environment is aggressive below-grade 

scaling) / (pH <5.5, chlorides >500 ppm, or environment 

Corrosion of sulfates >1500 ppm). Examination of exists 

embedded steel representative samples of below-grade 

concrete, when excavated for any 

reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of 

below-grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade 

environment is not aggressive. A5.1 -f Concrete: Reinforced Exposure to Increase in Chapter XlIS6, "Structures Monitoring No, if within 

Interior and above-grade concrete aggressive porosity and Program" the scope of exterior environment permeability, the 

cracking, loss of As described in NUREG-1557, applicant's material (spalling, aggressive chemical attack on interior structures 

scaling) / and above-grade exterior reinforced monitoring 

Aggressive concrete is not significant if the program chemical attack concrete is not exposed to an 

aggressive environment (pH <5.5), or to 

chloride or sulfate solutions beyond 

defined limits (>500 ppm chloride, or 

>1500 ppm sulfate). Therefore, if these 

conditions are satisfied, aging 

management is not required.
III Structures and Component Supports A5. Group 5 Structures (FuAI •tnrann FII=Pitiu IRufuwillnn i' annl\

z 

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M 

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00 

0 

OD 

co 

V 

0 "0

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Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A5. 1-g Concrete: Reinforced Exposure to Increase in A plant-specific aging management Yes, if an Fuel storage facility below concrete aggressive porosity and program is required only if the below- aggressive grade exterior; foundation environment permeability, grade environment is aggressive below-grade cracking, loss of (pH <5.5, chlorides >500 ppm, or environment 

material (spalling, sulfates >1500 ppm). Examination of exists scaling) / representative samples of below-grade Aggressive concrete, when excavated for any 

chemical attack reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of 

below-grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade 

A5.1 environment is not aggressive. -h Concrete: Reinforced Soft soil; Cracks; distortion; Chapter XI.S6, "Structures Monitoring No, if within All concrete changes in increase in Program" the scope of 

ground-water component stress the conditions level / The initial Licensing Basis for some applicant's Settlement plants included a program to monitor structures 

settlement. If no settlement was evident monitoring during the first decade or so, the NRC program 

may have given the licensee approval 

to discontinue the program. However, if 

a de-watering system is relied upon for 

control of settlement, then the licensee 

is to ensure proper functioning of the 

de-watering system through the period of extended operation.
(

III

(

Structures and Component Supports A5. Group 5 Structures (Fuel Storaae Faculitv. Refuelina C anal)

(

0 

0 

(D

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A5.1 -i Concrete: Reinforced Flowing water Reduction in Chapter XI.S6, "Structures Monitoring No, if within 

Foundation; concrete; under foundation Program" the scope of 

subfoundation porous foundation strength, cracking, the 

concrete differential Erosion of cement from porous applicant's 

settlement / concrete subfoundations beneath structures 

Erosion of porous containment basemats is described in monitoring 

concrete IN 97-11. IN 98-26 proposes program subfoundation Maintenance Rule Structures 

Monitoring for managing this aging 

effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous concrete 

subfoundations, then the licensee is to 

ensure proper functioning of the de

watering system through the period of 

extended operation. A5.1-j Concrete: Reinforced Outside Reduction of Plant-specific aging management Yes, if 

All concrete containment strength and program applicable 

modulus / 

Elevated For any concrete elements that exceed 

temperature specified temperature limits, further 

(>1 50°F general; evaluations are warranted. Appendix A 

>200°F local) of ACI 349-85 specifies the concrete 

temperature limits for normal operation 

or any other long-term period. The 

temperatures shall not exceed 150OF 

except for local areas which are 

allowed to have increased 

I temperatures not to exceed 2000 F.

z 

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9 

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Structures and Component Supports A5. Grouo 5 Structures (Fuel Storaae Facilitv. Refueilna C ,nnli

*0 

0 

"0

(,

III z 

m 0 

0 

01 

0

Structure and/or Aging Effect' Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A5.2-a Steel components: Carbon Various Loss of material / Chapter XI.S6, "Structures Monitoring No, if within 

All structural steel steel Corrosion Program" the scope of 

the 

If protective coatings are relied upon to applicant's 

manage the effects of aging, the structures 

structures monitoring program is to monitoring 

include requirements to address program protective coating monitoring and 

-maintenance. 

A5.2-b Steel components: Stainless Exposed to Crack initiation Chapter XI.M2, 'Water Chemistry No 

Liners steel water and growth, Loss Program" and monitoring of the spent 

of material / fuel pool water level 

Stress corrosion 

cracking and 

crevice corrosion A5.3-a Masonry walls: Concrete Ambient Cracking / Chapter XI.S5, "Masonry Wall Program" No 

Fuel storage facility block environment Restraint; 

inside building shrinkage; creep; 

aggressive 

environment I
A6. GROUP 6 STRUCTURES (WATER-CONTROL STRUCTURES)

A6.1 Concrete Elements 

A6.2 Steel Elements 

A6.3 Masonry Walls 

A6.4 Earthen Water-Control Structures

April 2001 III A6-1 NUREG-1801
A6. GROUP 6 STRUCTURES (WATER-CONTROL STRUCTURES)

Systems, Structures, and Components 

Class 1 structures are organized into nine groups and are discussed separately under subheadings Al through A9. 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 III A6-2 April 2001

I I
III Structures and Component Supports A6. Grouo 6 Structures (Water-Control Structures)

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation

I3> 

CD 

Z 

C: 

m 

0') 

R OD 

o3 

m

Reinforced Weather 

concrete exposed

Loss of material 

(spalling, scaling) 

and cracking / 

Freeze-thaw

A6.1 -a

(.

Concrete: 

Exterior above and below 

grade; foundation; interior 

slab

Chapter XI.S7, "Regulatory Guide No

1.127, Inspection of Water-Control 

Structures Associated with Nuclear 

Power Plants" or the FERC / US Army 

Corp of Engineers dam inspections and 

maintenance 

As described in NUREG-1557, freeze

thaw does not cause loss of material 

from reinforced concrete in foundations, 

and in above- and below-grade exterior 

concrete, for plants located in a 

geographic region of negligible 

weathering conditions (weathering 

index <100 day-inch/yr). Loss of 

material from such concrete is not 

significant at plants located in areas in 

which weathering conditions are severe 

(weathering index >500 day-inch/yr) or 

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

provided that the concrete mix design 

meets the air content (entrained air 

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

(0.35-0.45) specified in ACI 318-63 or 

ACI 349-85. Therefore, if these 

conditions are satisfied, aging 

management is not required. 

The weathering index is defined in 

ASTM C33-90, Table 3, Footnote E. 

Fig. 1 of ASTM C33-90 illustrates the 

various weathering index regions 

throuqhout the U.S. I I
z 

C 

m 

0')

K. K. K

III Structures and Component Supports A6. Group 6 Structures ýWater-Control Structures) 

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A6.1 -b Concrete: Reinforced Flowing water Increase in Chapter XI.S7, "Regulatory Guide No Exterior above and below concrete porosity and 1.127, Inspection of Water-Control grade; foundation; interior permeability, loss Structures Associated with Nuclear 

slab of strength / Power Plants" or the FERC / US Army Leaching of Corp of Engineers dam inspections and 

calcium hydroxide maintenance 

As described in NUREG-1557, leaching of calcium hydroxide from reinforced 

concrete becomes significant only if the 

concrete is exposed to flowing water. 

Even if reinforced concrete is exposed 

to flowing water, such leaching is not 

significant if the concrete is constructed 

to ensure that it is dense, well-cured, 

has low permeability, and that cracking is well controlled. Cracking is controlled 

through proper arrangement and 

distribution of reinforcing bars. All of the 

above characteristics are assured if the 

concrete was constructed with the 

guidance of ACI 201.2R-77. Therefore, 

if these conditions are satisfied, aging 

management is not required.

V,• 

o' 

0 

0-
( ( (

V> 

"03 

0 

0)

III Structures and Component Supports 

A6. Group 6 Structures (Water-Control Structures) 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A6.1-c Concrete: Reinforced Any Expansion and Chapter XI.S7, "Regulatory Guide No 

All concrete cracking / 1.127, Inspection of Water-Control 

Reaction with Structures Associated with Nuclear 

aggregates Power Plants" or the FERC / US Army 

Corp of Engineers dam inspections and 

maintenance 

As described in NUREG-1557, 

investigations, tests, and petrographic 

examinations of aggregates performed 

in accordance with ASTM C295-54 or 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially reactive aggregates, aggregate

reinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with 

ACI 201.2R-77. Therefore, if these 

conditions are satisfied, aging 

management is not required.

z 

C 

m 

OD 0
z 

C 

m 

0 

0o 

0) 

.--

_0 

M.

(

III Structures and Component Supports 

A6. Group 6 Structures (Water-Control Structures) 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A6.1 -d Concrete: Reinforced Exposure to Cracking, loss of Chapter Xi.S7, "Regulatory Guide No 

All concrete aggressive bond, loss of 1.127, Inspection of Water-Control 

environment material (spalling, Structures Associated with Nuclear 

scaling) / Power Plants" or the FERC / US Army Corrosion of Corp of Engineers dam inspections and 

embedded steel maintenance 

As described in NUREG-1557, 

corrosion of exterior above-grade and 

interior embedded steel is not 

significant if the steel is not exposed to 

an aggressive environment (concrete 

pH <11.5 or chlorides >500 ppm). If 

such steel is exposed to an aggressive 

environment, corrosion is not significant 

if the concrete in which the steel is 

embedded has a low water-to-cement 

ratio (0.35-0.45), adequate air 

entrainment (3-6%), low permeability, 

and is designed in accordance with 

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

these conditions are satisfied, aging 

management is not required.
( ( (

9o 

j 

0 

a>

III Structures and Component Supports 

A6. Group 6 Structures (Water-Control Structures) 

Structure and/or Aging Effect? Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A6.1-e Concrete: Reinforced Exposure to Increase in ChapterXI.S7, "Regulatory Guide No 

All concrete aggressive porosity and 1.127, Inspection of Water-Control 

environment permeability, Structures Associated with Nuclear 

cracking, loss of Power Plants" or the FERC / US Army 

material (spalling, Corp of Engineers dam inspections and 

scaling) / maintenance 

Aggressive 

chemical attack As described in NUREG-1557, 

aggressive chemical attack on interior 

and above-grade exterior reinforced 

concrete is not significant if the 

concrete is not exposed to an 

aggressive environment (pH <5.5), or to 

chloride or sulfate solutions beyond 

defined limits (>500 ppm chloride, or 

>1500 ppm sulfate). Therefore, if these 

conditions are satisfied, aging 

management is not required.

z 

C 

m 

0, 0
III Structures and Component Supports A6. Group 6 Structures (Water-Control StructureslI

z C 

m 

co 

CO 

0) 

"o 

_. 

0

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A6.1 -f Concrete: Reinforced Soft soil; Cracks; distortion; Chapter XI.S7, "Regulatory Guide No All concrete changes in increase in 1.127, Inspection of Water-Control 

ground-water component stress Structures Associated with Nuclear 

conditions level / Power Plants" or the FERC / US Army Settlement Corp of Engineers dam inspections and 

maintenance 

The initial Licensing Basis for some 

plants included a program to monitor 

settlement. If no settlement was evident 

during the first decade or so, the NRC 

may have given the licensee approval 

to discontinue the program. However, if 

a de-watering system is relied upon for 

control of settlement, then the licensee 

is to ensure proper functioning of the de-watering system through the period 

of extended operation. A6.1 -g Concrete: Reinforced Flowing water Reduction in Chapter XI.S6, "Structures Monitoring No, if within Foundation; concrete; under foundation Program" the scope of subfoundation porous foundation strength, cracking, the 

concrete differential Erosion of cement from porous applicant's settlement / concrete subfoundations beneath structures 

Erosion of porous containment basemats is described in monitoring 

concrete IN 97-11. IN 98-26 proposes program subfoundation Maintenance Rule Structures 

Monitoring for managing this aging effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous concrete 

subfoundations, then the licensee is to 

ensure proper functioning of the de

watering system through the period of 

extended operation.
(

III

(

Structures and Component Supports AR. r' Zrn A Qn-firgs ... Waa .1ntiQ fi

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A6.1-h Concrete: Reinforced Flowing water Loss of material/ Chapter XI.S7, "Regulatory Guide No 

Exterior above and below concrete Abrasion; 1.127, Inspection of Water-Control 

grade; foundation; interior cavitation Structures Associated with Nuclear 

slab Power Plants" or the FERC / US Army 

Corp of Engineers dam inspections and 

maintenance 

A6.2-a Steel components: Carbon Various Loss of material / Chapter XI.S7, "Regulatory Guide No 

All structural steel steel Corrosion 1.127, Inspection of Water-Control 

Structures Associated with Nuclear 

Power Plants" or the FERC / US Army 

Corp of Engineers dam inspections and 

maintenance 

If protective coatings are relied upon to 

manage the effects of aging, this AMP 

is to include requirements to address 

protective coating monitoring and 

maintenance. 

A6.3-a Masonry walls: Concrete Various Cracking/ Chapter XI.S5, "Masonry Wall Program" No 

Intake structure; cooling block Restraint; 

tower shrinkage; creep; 

aggressive 

environment 

A6.4-a Earthen water-control Various Weather Loss of material, Chapter XI.S7, "Regulatory Guide No 

structures: exposed, loss of form / 1.127, Inspection of Water-Control 

Dams, embankments, standing and Erosion, Structures Associated with Nuclear 

reservoirs, channels, canals flowing water settlement, Power Plants " or the FERC / US Army 

sedimentation, Corp of Engineers dam inspections and 

frost action, maintenance. 

waves, currents, 

surface runoff, 

I_____ _seepage I I
z C 

m 

00 

0 

•, This Page Intentionally Left Blank 

0o 

0 

0 

0
A7. GROUP 7 STRUCTURES (CONCRETE TANKS)

A7.1 Concrete Elements 

A7.2 Steel Elements

April 2001 III A7-1 NUREG-1801
A7. GROUP 7 STRUCTURES (CONCRETE TANKS)

Systems, Structures, and Components 

Class 1 structures are organized into nine groups and are discussed separately under 

subheadings Al through A9. This section addresses the elements of concrete tanks. 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 III A7-2 April 2001
IlI

/,

Structures and Component Supports A7. Grouo 7 Structures (Concrete Tnnks•

(

M..

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A7.1 -a Concrete: Reinforced Weather Loss of material Chapter XI.$6, "Structures Monitoring No, if within 

Exterior above and below concrete exposed (spalling, scaling) Program" the scope of 

grade; foundation and cracking / the 

Freeze-thaw As described in NUREG-1557, freeze- applicant's 

thaw does not cause loss of material structures 

from reinforced concrete in foundations, monitoring 

and in above- and below-grade exterior program 

concrete, for plants located in a 

geographic region of negligible 

weathering conditions (weathering 

index <100 day-inch/yr). Loss of 

material from such concrete is not 

significant at plants located in areas in 

which weathering conditions are severe 

(weathering index >500 day-inch/yr) or 

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

provided that the concrete mix design 

meets the air content (entrained air 

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

(0.35-0.45) specified in ACI 318-63 or 

ACI 349-85. Therefore, if these 

conditions are satisfied, aging 

management is not required. 

The weathering index is defined in 

ASTM C33-90, Table 3, Footnote E. 

Fig. 1 of ASTM C33-90 illustrates the 

various weathering index regions throughout the U.S.

Z C 

:0 

m 

00
Structures and Component Supports A7. Group 7 Structures (Concrete Tanksb III z 

C 

m 

r'n 

o~,

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A7.1 -b Concrete: Reinforced Flowing water Increase in Chapter XI.S6, "Structures Monitoring No, if within Exterior above and below concrete porosity and Program" the scope of grade; foundation permeability, loss the 

of strength / As described in NUREG-1557, leaching applicant's Leaching of of calcium hydroxide from reinforced structures 

calcium hydroxide concrete becomes significant only if the monitoring 

concrete is exposed to flowing water, program 

Even if reinforced concrete is exposed 

to flowing water, such leaching is not 

significant if the concrete is constructed 

to ensure that it is dense, well-cured, 

has low permeability, and that cracking 

is well controlled. Cracking is controlled 

through proper arrangement and 

distribution of reinforcing bars. All of the 

above characteristics are assured if the 

concrete was constructed with the 

guidance of ACI 201.2R-77. Therefore, 

if these conditions are satisfied, aging 

management is not required.

-o 

"03 

0.
( ( (

0> 

"-0 

01

III Structures and Component Supports 

A7. Group 7 Structures (Concrete Tanks) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A7.1-c Concrete: Reinforced Any Expansion and Chapter XI.S6, "Structures Monitoring No, if within 

All concrete cracking / Program" the scope of 

Reaction with the 

aggregates As described in NUREG-1557, applicant's 

investigations, tests, and petrographic structures 

examinations of aggregates performed monitoring 

in accordance with ASTM 0295-54 or program 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregate

reinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with 

ACI 201.2R-77. Therefore, if these 

conditions are satisfied, aging 

I management is not required.

z C 

M 0 •0 

OD
z C 

m 

"0, 

0

"0 

•0 M..

( K.

III Structures and Component Supports 

A7. Group 7 Structures (Concrete Tanks) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A7.1-d Concrete: Reinforced Exposure to Cracking, loss of Chapter XI.S6, "Structures Monitoring No, if within 

Exterior above grade concrete aggressive bond, loss of Program" the scope of 

environment material (spalling, the 

scaling) / As described in NUREG-1557, applicant's 

Corrosion of corrosion of exterior above-grade and structures 

embedded steel interior embedded steel is not monitoring 

significant if the steel is not exposed to program 

an aggressive environment (concrete 

pH <11.5 or chlorides >500 ppm). If 

such steel is exposed to an aggressive environment, corrosion is not significant 

if the concrete in which the steel is 

embedded has a low water-to-cement 

ratio (0.35-0.45), adequate air 

entrainment (3-6%), low permeability, 

and is designed in accordance with 

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

these conditions are satisfied, aging 

I management is not required.
(

III

(

Structures and Component Supports A7. GrouD 7 Structures (Concrete Tanksl

(

0 

N1> 

24 

z 

M m 

0 

co 

0

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A7.1-e Concrete: Reinforced Exposure to Cracking, loss of A plant-specific aging management Yes, if an 

Exterior below grade; concrete aggressive bond, loss of program is required only if the below- aggressive foundation environment material (spalling, grade environment is aggressive below-grade 

scaling) / (pH <5.5, chlorides >500 ppm, or environment 

Corrosion of sulfates >1500 ppm). Examination of exists 

embedded steel representative samples of below-grade 

concrete, when excavated for any 

reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of 

below-grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade 

environment is not aggressive. A7.1-f Concrete: Reinforced Exposure to Increase in Chapter XI.S6, "Structures Monitoring No, if within 

Exterior above grade concrete aggressive porosity and Program" the scope of 

environment permeability, the 

cracking, loss of As described in NUREG-1557, applicant's 

material (spalling, aggressive chemical attack on interior structures 

scaling) / and above-grade exterior reinforced monitoring 

Aggressive concrete is not significant if the program 

chemical attack concrete is not exposed to an 

aggressive environment (pH <5.5), or to 

chloride or sulfate solutions beyond 

defined limits (>500 ppm chloride, or 

>1500 ppm sulfate). Therefore, if these 

conditions are satisfied, aging 

management is not required.
z 

C 

m 

0, 

R

( K

III Structures and Component Supports A7. Group 7 Structures (Concrete Tanks) 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A7.1 -g Concrete: Reinforced Exposure to Increase in A plant-specific aging management Yes, if an Exterior below grade; concrete aggressive porosity and program is required only if the below- aggressive foundation environment permeability, grade environment is aggressive below-grade cracking, loss of (pH <5.5, chlorides >500 ppm, or environment 

material (spalling, sulfates >1 500ppm). Examination of exists scaling) / representative samples of below-grade Aggressive concrete, when excavated for any 

chemical attack reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of 

below-grade water chemistry (including consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade 

environment is not aggressive. A7.1-h Concrete: Reinforced Soft soil; Cracks; distortion; Chapter XI.S6, "Structures Monitoring No, if within All concrete changes in increase in Program" the scope of 

groundwater component stress the 

conditions level / The initial Licensing Basis for some applicant's Settlement plants included a program to monitor structures 

settlement. If no settlement was evident monitoring during the first decade or so, the NRC program 

may have given the licensee approval 

to discontinue the program. However, if 

a de-watering system is relied upon for control of settlement, then the licensee 

is to ensure proper functioning of the 

de-watering system through the period Sof extended operation.

N 

0 

9
( ( (

z C> 

M 

00 

,

C 

m G) 

0

III Structures and Component Supports 

A7. Group 7 Structures (Concrete Tanks) 

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A7.11-i Concrete: Reinforced Flowing water Reduction in Chapter XI.S6, "Structures Monitoring No, if within 

Foundation; concrete; under foundation Program" the scope of 

subfoundation porous foundation strength, cracking, the 

concrete differential Erosion of cement from porous applicant's 

settlement / concrete subfoundations beneath structures 

Erosion of porous containment basemats is described in monitoring 

concrete IN 97-11. IN 98-26 proposes program 

subfoundation Maintenance Rule Structures 

Monitoring for managing this aging 

effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous concrete 

subfoundations, then the licensee is to 

ensure proper functioning of the de

watering system through the period of 

extended operation. A7.2-a Steel components: Carbon Various Loss of material / Chapter XI.S6, "Structures Monitoring No, if within 

All structural steel steel Corrosion Program" the scope of 

the 

If protective coatings are relied upon to applicant's 

manage the effects of aging, the structures 

structures monitoring program is to monitoring 

include requirements to address program 

protective coating monitoring and 

maintenance. A7.2-b Steel components: Stainless Exposed to Crack initiation Plant-specific aging management Yes 

Liner steel fluid and growth, loss program 

environment of material / 

(water, fuel) Stress corrosion 

cracking, crevice 

corrosion
z 

c 

m 

o 

OD 

This Page Intentionally Left Blank 

r.3 

0 

0
A8. GROUP 8 STRUCTURES (STEEL TANKS) 

A8.1 Concrete Elements 

A8.2 Steel Elements

April 2001 III A8-1 NUREG-1801
A8. GROUP 8 STRUCTURES (STEEL TANKS)

Systems, Structures, and Components 

Class 1 structures are organized into nine groups and are discussed separately under 

subheadings Al through A9. This section addresses the elements of steel tanks. 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 III A8-2 April 2001

I I
(

III Structures and Component Supports

9D 

0 

0 

0> 

co~

A8. uroup u Structures (Steel anKs) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A8.1-a Concrete: Reinforced Weather Loss of material Chapter XI.S6, "Structures Monitoring No, if within 

Foundation concrete exposed (spalling, scaling) Program" the scope of 

and cracking / the 

Freeze-thaw As described in NUREG-1557, freeze- applicant's 

thaw does not cause loss of material structures 

from reinforced concrete in foundations, monitoring 

and in above- and below-grade exterior program 

concrete, for plants located in a 

geographic region of negligible 

weathering conditions (weathering 

index <100 day-inch/yr). Loss of 

material from such concrete is not 

significant at plants located in areas in 

which weathering conditions are severe 

(weathering index >500 day-inch/yr) or 

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

provided that the concrete mix design 

meets the air content (entrained air 

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

(0.35-0.45) specified in ACI 318-63 or 

ACI 349-85. Therefore, if these 

conditions are satisfied, aging 

management is not required. 

The weathering index is defined in 

ASTM C33-90, Table 3, Footnote E. 

Fig. 1 of ASTM C33-90 illustrates the 

various weathering index regions throughout the U.S.

Z 

C) co 

30 

CO
Structures and Component Supports 

A8. Group 8 Structures (Steel Tanks)

III z 

m O) 

o, R 

0

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A8.1 -b Concrete: Reinforced Flowing water Increase in Chapter XI.S6, "Structures Monitoring No, if within Foundation concrete porosity and Program" the scope of 

permeability, loss the 

of strength / As described in NUREG-1557, leaching applicant's Leaching of of calcium hydroxide from reinforced structures 

calcium hydroxide concrete becomes significant only if the monitoring 

concrete is exposed to flowing water. program Even if reinforced concrete is exposed 

to flowing water, such leaching is not 

significant if the concrete is constructed 

to ensure that it is dense, well-cured, 

has low permeability, and that cracking is well controlled. Cracking is controlled 

through proper arrangement and 

distribution of reinforcing bars. All of the 

above characteristics are assured if the 

concrete was constructed with the 

guidance of ACI 201.2R-77. Therefore, 

if these conditions are satisfied, aging 

management is not required.

N> 

0 "0

(
III

(

Structures and Component Supports 

AR (Zrnuin R Qtur, lrotam,• f~tc-I T-nkoa

(

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A8.1 -c Concrete: Reinforced Any Expansion and Chapter XI.S6, "Structures Monitoring No, if within 

Foundation concrete cracking / Program" the scope of 

Reaction with the 

aggregates As described in NUREG-1557, applicant's 

investigations, tests, and petrographic structures 

examinations of aggregates performed monitoring 

in accordance with ASTM C295-54 or program 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregate

reinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with 

ACl 201.2R-77. Therefore, if these 

conditions are satisfied, aging 

management is not required. 

A8.1-d Concrete: Reinforced Exposure to Cracking, loss of A plant-specific aging management Yes, if an 

Foundation concrete aggressive bond, loss of program is required only if the below- aggressive 

environment material (spalling, grade environment is aggressive below-grade scaling) / (pH <5.5, chlorides >500 ppm, or environment 

Corrosion of sulfates >1500 ppm). Examination of exists 

embedded steel representative samples of below-grade 

concrete, when excavated for any 

reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of 

below-grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade environment is not aggressive. I
III Structures and Component Supports z C 

m 

0 X M

(

RL. Uroup U Structures iteell anKs) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A8.1-e Concrete: Reinforced Exposure to Increase in A plant-specific aging management Yes, if an 

Foundation concrete aggressive porosity and program is required only if the below- aggressive 

environment permeability, grade environment is aggressive below-grade 

cracking, loss of (pH <5.5, chlorides >500 ppm, or environment 

material (spalling, sulfates >1500 ppm). Examination of exists 

scaling) / representative samples of below-grade 

Aggressive concrete, when excavated for any 

chemical attack reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of 

below-grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade environment is not aggressive. A8.1-f Concrete: Reinforced Soft soil; Cracks; distortion; Chapter XI.S6, "Structures Monitoring No, if within 

Foundation concrete changes in increase in Program" the scope of 

groundwater component stress the 

conditions level / The initial Licensing Basis for some applicant's 

Settlement plants included a program to monitor structures 

settlement. If no settlement was evident monitoring 

during the first decade or so, the NRC program 

may have given the licensee approval 

to discontinue the program. However, if 

a de-watering system is relied upon for 

control of settlement, then the licensee 

is to ensure proper functioning of the 

de-watering system through the period of extended operation.

No 

0 CD
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III

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Structures and Component Supports

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Ad. Group 1 Structures qI•eeil anKs 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A8.1-g Concrete: Reinforced Flowing water Reduction in Chapter XI.S6, "Structures Monitoring No, if within 

Foundation; concrete; under foundation Program" the scope of 

subfoundation porous foundation strength, cracking, the 

concrete differential Erosion of cement from porous applicant's 

settlement / concrete subfoundations beneath structures 

Erosion of porous containment basemats is described in monitoring 

concrete IN 97-11. IN 98-26 proposes program 

subfoundation Maintenance Rule Structures 

Monitoring for managing this aging 

effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous concrete 

subfoundations, then the licensee is to 

ensure proper functioning of the de

watering system through the period of 

extended operation. 

A8.2-a Steel components: Carbon Various Loss of material / Chapter XI.S6, "Structures Monitoring No, if within 

All structural steel steel Corrosion Program" the scope of 

the 

If protective coatings are relied upon to applicant's 

manage the effects of aging, the structures 

structures monitoring program is to monitoring 

include requirements to address program 

protective coating monitoring and 

I_ _ Imaintenance. 

A8.2-b Steel components: Stainless Exposed to Crack initiation Plant-specific aging management Yes 

Liner steel fluid and growth, loss program 

environment of material / 

Stress corrosion 

cracking, crevice 

corrosion
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A9. GROUP 9 STRUCTURES (BWR UNIT VENT STACK) 

A9.1 Concrete Elements

April 2001 III A9-1 NUREG-1801
A9. GROUP 9 STRUCTURES (BWR UNIT VENT STACK)

Systems, Structures, and Components 

Class 1 structures are organized into nine groups and are discussed separately under 

subheadings Al through A9. This section addresses the elements of BWR unit vent stack. For 

this group, the applicable structural elements are 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 III A9-2 April 2001
(

III

(

Structures and Component Supports 

AO 0rn..n Q tr"t,-t.rna £RWD I VInit n .tnI-1

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A9.1 -a Concrete: Reinforced Weather Loss of material Chapter XI.S6, "Structures Monitoring No, if within 

Above and below grade; concrete exposed (spalling, scaling) Program" the scope of 

foundation and cracking / the 

Freeze-thaw As described in NUREG-1557, freeze- applicant's 

thaw does not cause loss of material structures 

from reinforced concrete in foundations, monitoring 

and in above- and below-grade exterior program 

concrete, for plants located in a 

geographic region of negligible 

weathering conditions (weathering 

index <100 day-inch/yr). Loss of 

material from such concrete is not 

significant at plants located in areas in 

which weathering conditions are severe 

(weathering index >500 day-inch/yr) or 

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

provided that the concrete mix design 

meets the air content (entrained air 

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

(0.35-0.45) specified in ACI 318-63 or 

ACI 349-85. Therefore, if these 

conditions are satisfied, aging 

management is not required. 

The weathering index is defined in 

ASTM C33-90, Table 3, Footnote E. 

Fig. 1 of ASTM C33-90 illustrates the 

various weathering index regions 

throughout the U.S.

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III Structures and Component Supports 

A9. Group 9 Structures (BWR Unit Vent Stack) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A9.1 -b Concrete: Reinforced Flowing water Increase in Chapter XI.S6, "Structures Monitoring No, if within 

Above and below grade; concrete porosity and Program" the scope of 

foundation permeability, loss the 

of strength / As described in NUREG-1557, leaching applicant's 

Leaching of of calcium hydroxide from reinforced structures 

calcium hydroxide concrete becomes significant only if the monitoring 

concrete is exposed to flowing water. program 

Even if reinforced concrete is exposed 

to flowing water, such leaching is not 

significant if the concrete is constructed 

to ensure that it is dense, well-cured, 

has low permeability, and that cracking is well controlled. Cracking is controlled 

through proper arrangement and 

distribution of reinforcing bars. All of the 

above characteristics are assured if the 

concrete was constructed with the 

guidance of ACl 201.2R-77. Therefore, 

if these conditions are satisfied, aging 

I management is not required.
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Structures and Component Supports ACQ frnui~n 0 •trnnt,.ua~e IRWI I Inlt lIlnn e€o6 .A•,

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Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A9.1 -c Concrete: Reinforced Any Expansion and Chapter XI.S6, "Structures Monitoring No, if within 

Above and below grade; concrete cracking / Program" the scope of 

foundation Reaction with the 

aggregates As described in NUREG-1557, applicant's 

investigations, tests, and petrographic structures 

examinations of aggregates performed monitoring 

in accordance with ASTM C295-54 or program 

ASTM C227-50 can demonstrate that 

those aggregates do not react within 

reinforced concrete. For potentially 

reactive aggregates, aggregate

reinforced concrete reaction is not 

significant if the concrete was 

constructed in accordance with 

ACl 201.2R-77. Therefore, if these 

conditions are satisfied, aging 

management is not required.

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Structures and Component Supports A9. Groul, 9 Structures (BWR Unit Vent Strn~k•

III z 

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Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A9.1-d Concrete: Reinforced Exposure to Cracking, loss of Chapter XI.S6, "Structures Monitoring No, if within Above grade concrete aggressive bond, loss of Program" the scope of 

environment material (spalling, the 

scaling) / As described in NUREG-1557, applicant's Corrosion of corrosion of exterior above-grade and structures 

embedded steel interior embedded steel is not monitoring significant if the steel is not exposed to program 

an aggressive environment (concrete 

pH <11.5 or chlorides >500 ppm). If 

such steel is exposed to an aggressive 

environment, corrosion is not significant 

if the concrete in which the steel is 

embedded has a low water-to-cement 

ratio (0.35-0.45), adequate air 

entrainment (3-6%), low permeability, 

and is designed in accordance with 

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

these conditions are satisfied, aging 

management is not required.

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A9.1-e Concrete: Reinforced Exposure to Cracking, loss of A plant-specific aging management Yes, if an 

Below grade; foundation concrete aggressive bond, loss of program is required only if the below- aggressive 

environment material (spalling, grade environment is aggressive below-grade 

scaling) / (pH <5.5, chlorides >500 ppm, or environment 

Corrosion of sulfates >1500 ppm). Examination of exists 

embedded steel representative samples of below-grade 

concrete, when excavated for any 

reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of 

below-grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade 

environment is not aggressive. 

A9.1 -f Concrete: Reinforced Exposure to Increase in Chapter XI.S6, "Structures Monitoring No, if within 

Above grade concrete aggressive porosity and Program" the scope of 

environment permeability, the 

cracking, loss of As described in NUREG-1557, applicant's 

material (spalling, aggressive chemical attack on interior structures 

scaling) / and above-grade exterior reinforced monitoring 

Aggressive concrete is not significant if the program 

chemical attack concrete is not exposed to an 

aggressive environment (pH <5.5), or to 

chloride or sulfate solutions beyond 

defined limits (>500 ppm chloride, or 

>1500 ppm sulfate). Therefore, if these 

conditions are satisfied, aging 

management is not required.
III Structures and Component Supports 

AQ rrn"ia Q0 _trlMll'ae (AWO I Ait IInt * Of.IA

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A9.1 -g Concrete: Reinforced Exposure to Increase in A plant-specific aging management Yes, if an 

Below grade; foundation concrete aggressive porosity and program is required only if the below- aggressive 

environment permeability, grade environment is aggressive below-grade cracking, loss of (pH <5.5, chlorides >500 ppm, or environment 

material (spalling, sulfates >1500 ppm). Examination of exists 

scaling) / representative samples of below-grade 

Aggressive concrete, when excavated for any chemical attack reason, is to be included as part of a 

plant-specific program. 

If the below-grade environment is not 

aggressive, this aging effect is not 

significant. Periodic monitoring of 

below-grade water chemistry (including 

consideration of potential seasonal 

variations) is an acceptable approach to 

demonstrate that the below-grade environment is not aggressive. A9.1-h Concrete: Reinforced Soft soil; Cracks; distortion; Chapter XI.S6, "Structures Monitoring No, if within All concrete changes in increase in Program" the scope of 

groundwater component stress the 

conditions level / The initial Licensing Basis for some applicant's Settlement plants included a program to monitor structures 

settlement. If no settlement was evident monitoring 

during the first decade or so, the NRC program 

may have given the licensee approval 

to discontinue the program. However, if 

a de-watering system is relied upon for 

control of settlement, then the licensee 

is to ensure proper functioning of the 

de-watering system through the period 1 of extended operation.
III Structures and Component Supports

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A9.1-i Concrete: Reinforced Flowing water Reduction in Chapter XI.S6, "Structures Monitoring No, if within Foundation; concrete; under foundation Program" the scope of subfoundation porous foundation strength, cracking, the 

concrete differential Erosion of cement from porous applicant's settlement / concrete subfoundations beneath structures 

Erosion of porous containment basemats is described in monitoring Concrete IN 97-11. IN 98-26 proposes program subfoundation Maintenance Rule Structures 

Monitoring for managing this aging effect, if applicable. If a de-watering 

system is relied upon for control of 

erosion of cement from porous concrete 

subfoundations, then the licensee is to 

ensure proper functioning of the de

watering system through the period of 

extended operation.

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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

April 2001 III B-i NUREG-1801
This Page Intentionally Left Blank

NUREG-1801 III B3-ii April 2001
B1. SUPPORTS FOR ASME PIPING AND COMPONENTS

B1.1 Class 1 

B1.1.1 Support Members; Welds; Bolted Connections; Support Anchorage to 

Building Structure 

B1.1.2 High Strength Bolting for NSSS Component Supports 

B1.1.3 Constant/Variable Load Spring Hangers; Guides; Stops; Sliding Surfaces; 

Design Clearances; Vibration Isolators 

61.1.4 Building Concrete at Locations of Expansion and Grouted Anchors; Grout 

Pads for Support Base Plates 

B1.2 Class 2 and 3 

B1.2.1 Support Members; Welds; Bolted Connections; Support Anchorage to 

Building Structure 

B1.2.2 Constant/Variable Load Spring Hangers; Guides; Stops; Sliding Surfaces; 

Design Clearances; Vibration Isolators 

B1.2.3 Building Concrete at Locations of Expansion and Grouted Anchors; Grout 

Pads for Support Base Plates 

B1.3 Class MC (BWR Containment Supports) 

B1.3.1 Support Members; Welds; Bolted Connections; Support Anchorage to 

Building Structure 

B1.3.2 Guides; Stops; Sliding Surfaces; Design Clearances 

B1.3.3 Building Concrete at Locations of Expansion and Grouted Anchors; Grout 

Pads for Support Base Plates

April 2001 111131-1 NUREG-1801
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 (Ill.B13.1), Class 2 and 3 (ill.B1 .2), and Class MC (Ill.B13.3). 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 111131-2 April 2001
(

Ill. Structures and Components Supports

(

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E1.1 Supports for ASME Class 1 Piping and Components 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation B1.1.1-a Support members; welds; Carbon Inside Loss of material / Chapter XI.S3, "ASME Section Xl, No 

bolted connections; support steel containment Environmental Subsection IWF" 

anchorage to building corrosion (i.e., 

structure pitting corrosion, 

general corrosion, 

etc.) 

B1.1.1-b Support members; welds; Carbon Inside PWR Loss of material / Chapter XI.M10, "Boric Acid Corrosion" No 

bolted connections; support steel containment Boric acid 

anchorage to building corrosion 

structure 

B1.1.1-c Support members; welds; Carbon Inside Cumulative Fatigue is a time-limited aging analysis Yes, bolted connections; support steel containment fatigue damage / (TLAA) to be evaluated for the period of TLAA 

anchorage to building Fatigue extended operation. See the Standard 

structure Review Plan, Section 4.3, "Metal 

(only if a CLB Fatigue" for acceptable methods for 

fatigue analysis meeting the requirements of 

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

B1.1.2-a High strength bolting for Low alloy Inside Cracking / Stress Chapter XI.M18, "Bolting Integrity" No 

NSSS component supports steel, yield containment corrosion cracking 

strength 

>150 ksi

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Structures and Components Supports B1.1 Suinoorts for ASME Class 1 Pinina and Comoonents

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B1i .1.3-a Constant and variable load Steel and Inside Loss of' Chapter XI.S3, "ASME Section XI, No 

spring hangers; guides; non-steel containment mechanical Subsection IWF" 

stops; sliding surfaces; materials function / 

design clearances; (e.g., Corrosion, 

vibration isolators lubrite distortion, dirt, 

plates, overload, fatigue 

vibration due to vibratory 

isolators, and cyclic thermal 

etc.) loads; elastomer 

hardening 

B1.1.4-a Building concrete at Reinforced Inside Reduction in Chapter XI.S6, "Structures Monitoring No, if within 

locations of expansion and concrete; containment concrete anchor Program" the scope of 

grouted anchors; grout grout capacity due to the 

pads for support base local concrete applicant's 

plates degradation / structures 

Service-induced monitoring 

cracking or other program 

concrete aging 

I_ mechanisms
( (. (

Ill. Structures and Components Supports B1.2 Supports for ASME Class 2 and 3 PIping and Components 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B1.2.1-a Support members; welds; Carbon Inside or Loss of material / Chapter XI.S3, "ASME Section Xl, No 

bolted connections; steel outside Environmental Subsection IWF" 

support anchorage to containment corrosion (i.e. 

building structure pitting corrosion, 

general corrosion) 

B1.2.1-b Support members; welds; Carbon Inside PWR Loss of material / Chapter XI.M1 0, "Boric Acid Corrosion" No 

bolted connections; steel containment Boric acid 

support anchorage to corrosion 

building structure 

B1.2.1-c Support members; welds; Carbon Inside or Cumulative Fatigue is a time-limited aging analysis Yes, 

bolted connections; steel outside fatigue damage / (TLAA) to be evaluated for the period of TLAA 

support anchorage to containment Fatigue extended operation. See the Standard 

building structure Review Plan, Section 4.3, "Metal 

(only if a CLB Fatigue" for acceptable methods for 

fatigue analysis meeting the requirements of 

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

B13.2.2-a Constant and variable Steel and Inside or Loss of Chapter XI.S3, "ASME Section XI, No 

load spring hangers; non-steel outside mechanical Subsection IWF" 

guides; stops; sliding materials containment function / 

surfaces; design (e.g., Corrosion, 

clearances; vibration lubrite distortion, dirt, 

isolators plates, overload, fatigue 

vibration due to vibratory 

isolators, and cyclic thermal 

etc.) loads; elastomer 

_hardening 

B1.2.3-a Building concrete at Reinforced Inside or Reduction in Chapter XI.S6, "Structures Monitoring No, if within 

locations of expansion and concrete; outside concrete anchor Program" the scope of 

grouted anchors; grout grout containment capacity due to the 

pads for support base local concrete applicant's 

plates degradation / structures 

Service-induced monitoring 

cracking or other program 

concrete aging 

mechanisms I
III. Structures and Components Supports B1.3 Supports for ASME Class MC Components (BWR downcomer bracing; # I I . . . . . . . . . . .. . . .. ..

z C 

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B1.3.1-a Support members; welds; Carbon Inside or" Loss of material/ Chapter XI.S3, "ASME Section XI, No 

bolted connections; steel outside Environmental Subsection IWF" 

support anchorage to containment corrosion (i.e. building structure pitting corrosion, 

general corrosion, 

etc.) B1.3.1-b Support members; welds; Carbon Inside or Cumulative Fatigue is a time-limited aging analysis Yes, bolted connections; steel outside fatigue damage / (TLAA) to be evaluated for the period of TLAA 

support anchorage to containment Fatigue extended operation. See the Standard building structure Review Plan, Section 4.3, "Metal 

(only if a CLB Fatigue" for acceptable methods for 

fatigue analysis meeting the requirements of 

exists) 10 CFR 54.21(c)(1). B1.3.2-a Guides; stops; sliding Steel and Inside or Loss of Chapter XI.S3, "ASME Section XI, No 

surfaces; design non-steel outside mechanical Subsection IWF" 

clearances materials containment function / 

(e.g., Corrosion, 

lubrite distortion, dirt, 

plates, overload, fatigue 

etc.) due to vibratory 

and cyclic thermal 

loads; elastomer 

hardening B1.3.3-a Building concrete at Reinforced Inside or Reduction in Chapter XI.S6, "Structures Monitoring No, if within locations of expansion concrete; outside concrete anchor Program" the scope of and grouted anchors; grout containment capacity due to the 

grout pads for support local concrete applicant's base plates degradation / structures 

Service-induced monitoring cracking or other program 

concrete aging mechanisms
B2. SUPPORTS FOR CABLE TRAYS, CONDUIT, HVAC DUCTS, TUBETRACK, 

INSTRUMENT TUBING, NON-ASME PIPING AND COMPONENTS 

B2.1 Support Members; Welds; Bolted Connections; Support Anchorage to Building 

Structure 

B2.2 Building Concrete at Locations of Expansion and Grouted Anchors; Grout Pads for 

Support Base Plates

April 2001 111132-1 NUREG-1801
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, HVAC ducts, tube 

track, 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 111132-2 April 2001
IlI. Structures and Component Supports B2 Supports for Cable Trays, Conduit, HVAC Ducts, Tube Track, Instrument Tubing, Non-ASME PiDina and Comnonents -o 

I'

0._

(

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation B2.1-a Support members; welds; Carbon Inside or Loss of material / Chapter XI.S6, "Structures Monitoring No, if within bolted connections; Support steel outside Environmental Program" the scope of anchorage to building containment corrosion (i.e., the structure pitting corrosion, applicant's 

general corrosion, structures 

etc.) monitoring 

B2.1 program -b Support members; welds; Carbon Inside PWR Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

bolted connections; support steel containment Boric acid 

anchorage to building corrosion 

structure 

B2.2-a Building concrete at locations Reinforced Inside or Reduction in Chapter XI.S6, "Structures Monitoring No, if within of expansion and grouted concrete; outside concrete anchor Program" the scope of anchors; grout pads for grout; containment capacity due to the support base plates masonry local concrete applicant's 

degradation / structures 

Service-induced monitoring cracking or other program 

concrete aging 

mechanisms I

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

FOR ELECTRICAL EQUIPMENT AND INSTRUMENTATION 

B3.1 Support Members; Welds; Bolted Connections; Support Anchorage to Building 

Structure 

B3.2 Building Concrete at Locations of Expansion and Grouted Anchors; 

Grout Pads for Support Base Plates

April 2001 111133-1 NUREG-1801
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-1 801 April 2001 111133-2
( III

Structures and Component Supports B3 Anchoraae of Racks. Panels. Cabinets, and Enclosures for Electrical Enuinment and In~trumnntntinn N1 

03 1P 

CO 

cJ3

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B3.1 -a Support members; welds; Carbon Inside or Loss of material / Chapter XI.S6, "Structures Monitoring No, if within 

bolted connections; support steel outside Environmental Program" the scope of 

anchorage to building containment corrosion (i.e., the 

structure pitting corrosion, applicant's 

general corrosion, structures 

etc.) monitoring 

program B3.1-b Support members; welds; Carbon Inside PWR Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

bolted connections; support steel containment Boric acid 

anchorage to building corrosion 

structure 

B3.2-a Building concrete at locations Reinforced Inside or Reduction in Chapter XI.S6, "Structures Monitoring No, if within 

of expansion and grouted concrete; outside concrete anchor Program" the scope of 

anchors; grout pads for grout; containment capacity due to the 

support base plates masonry local concrete applicant's 

degradation / structures 

Service-induced monitoring 

cracking or other program 

concrete aging mechanisms I

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B4. SUPPORTS FOR EMERGENCY DIESEL GENERATOR (EDG), HVAC SYSTEM 

COMPONENTS, AND OTHER MISCELLANEOUS MECHANICAL EQUIPMENT 

B4.1 Support Members; Welds; Bolted Connections; Support Anchorage to Building 

Structure 

B4.2 Vibration Isolation Elements 

B4.3 Building Concrete at Locations of Expansion and Grouted Anchors; Grout Pads for 

Support Base Plates

April 2001 111134-1 NUREG-1801
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 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 III B4-2 April 2001

I I
(

III. Structures and Components Supports 

B4 Supports for Emergency Diesel Generator (EDG), HVAC System Components, and Other Miscellaneous MechaniclEnul no•ment

0 

01

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.1 -a Support members; welds; Carbon Inside or Loss of material / Chapter XI.S6, "Structures Monitoring No, if within 

bolted connections; support steel outside Environmental Program" the scope of 

anchorage to building containment corrosion (i.e., the 

structure pitting corrosion, applicant's 

general corrosion, Structures 

etc.) Monitoring 

Program 

B4.1-b Support members; welds; Carbon Inside PWR Loss of material / Chapter XI.M10, "Boric Acid Corrosion" No 

bolted connections; support steel containment Boric acid 

anchorage to building corrosion 

structure 

B4.2-a Vibration isolation elements Non- Inside or Reduction or loss Chapter XI.S6, "Structures Monitoring No, if within 

metallic outside of isolation Program" the scope of 

(e.g., containment function / the 

Rubber) Radiation applicant's 

hardening, structures 

temperature, monitoring 

humidity, program 

sustained 

vibratory loading B4.3-a Building concrete at locations Reinforced Inside or Reduction in Chapter XI.S6, "Structures Monitoring No, if within 

of expansion and grouted concrete; outside concrete anchor Program" the scope of 

anchors; grout pads for grout containment capacity due to the 

support base plates local concrete applicant's 

degradation / structures 

Service-induced monitoring 

cracking or other program 

concrete aging mechanisms

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B5. SUPPORTS FOR PLATFORMS, PIPE WHIP RESTRAINTS, JET IMPINGEMENT 

SHIELDS, MASONRY WALLS, AND OTHER MISCELLANEOUS STRUCTURES 

B5.1 Support Members; Welds; Bolted Connections; Support Anchorage to Building 

Structure 

B5.2 Building Concrete at Locations of Expansion and Grouted Anchors; Grout Pads for 

Support Base Plates

April 2001 111135-1 NUREG-1 801
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 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 111135-2 April 2001
IlI.

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Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation B5.1 -a Support members; welds; Carbon Inside or Loss of material / Chapter XI.S6, "Structures Monitoring No, if within bolted connections; support steel outside Environmental Program" the scope of anchorage to building structure containment corrosion (i.e., the 

pitting corrosion, applicant's general corrosion, structures 

etc.) monitoring 

program B5.1-b Support members; welds; Carbon Inside PWR Loss of material / Chapter XI.M10, "Boric Acid Corrosion" No 

bolted connections; support steel containment Boric acid 

anchorage to building corrosion 

structure 

B5.2-a Building concrete at locations Reinforced Inside or Reduction in Chapter XI.S6, "Structures Monitoring No, if within of expansion and grouted concrete; Outside concrete anchor Program" the scope of anchors; grout pads for grout containment capacity due to the support base plates local concrete applicant's 

degradation / structures 

Service-induced monitoring cracking or other program 

concrete aging 

mechanisms

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Structures and Components Supports B5 Supports Masonrv Walls. for Platforms, Pipe Whip Restraints, Jet Impingement Shields, and Other MisPellanenu• •trur~htiia•
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CHAPTER IV 

REACTOR VESSEL, INTERNALS, AND REACTOR 

COOLANT SYSTEM

April 2001 NUREG-1801 IV-i
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NUREG-1 801 IV-ii April 2001
MAJOR PLANT SECTIONS 

Al. Reactor Vessel (Boiling Water Reactor) 

A2. Reactor Vessel (Pressurized Water Reactor) 

Bi. 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 

Cl. Reactor Coolant Pressure Boundary (Boiling Water Reactor) 

C2. Reactor Coolant System and Connected Lines (Pressurized Water Reactor) 

Dl. Steam Generator (Recirculating) 

D2. Steam Generator (Once-Through)

April 2001 IV-iii NUREG-1801
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NUREG-1801 IV-iv April 2001

I I
Al. REACTOR VESSEL (BOILING WATER REACTOR)

A1.1 Top Head Enclosure 

A1.1.1 Top Head 

A1.1.2 Nozzles (Vent, Top Head Spray or Reactor Core Isolation Cooling 

[RCIC], and Spare) 

A1.1.3 Head Flange 

A1.1.4 Closure Studs and Nuts 

A1.1.5 Vessel Flange Leak Detection Line 

A1.2 Vessel Shell 

A1.2.1 Vessel Flange 

A1.2.2 Upper Shell 

A1.2.3 Intermediate Nozzle Shell 

A1.2.4 Intermediate Beltline Shell 

A1.2.5 Lower Shell 

A1.2.6 Beltline Welds 

A1.2.7 Attachment Welds 

A1.3 Nozzles 

A1.3.1 Main Steam 

A1.3.2 Feedwater 

A1.3.3 Control Rod Drive (CRD) Return Line 

A1.3.4 Low Pressure Coolant Injection (LPCI) or Residual Heat Removal (RHR) 

Injection Mode 

A1.4 Nozzles Safe Ends 

A1.4.1 High Pressure Core Spray (HPCS) 

A1.4.2 Low Pressure Core Spray (LPCS) 

A1.4.3 CRD Return Line 

A1.4.4 Recirculating Water (Inlet and Outlet) 

A1.4.5 LPCI or RHR Injection Mode 

A1.5 Penetrations 

A1.5.1 CRD Stub Tubes 

A1.5'2 Instrumentation 

A1.5.3 Jet Pump Instrument 

A1.5.4 Standby Liquid Control 

A1.5.5 Flux Monitor 

A1.5.6 Drain Line 

A1.6 Bottom Head 

A1.7 Support Skirt and Attachment Welds

April 2001 IV.A1 -1 NUREG-1 801
Al. REACTOR VESSEL (BOILING WATER REACTOR)

Systems, Structures, and Components 

This section comprises the boiling water reactor (BWR) pressure vessel and consists of the 

vessel shell and flanges; attachment welds; the 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 CRD stub tubes, instrumentation, standby liquid control, flux monitor, 

and drain lines; and control rod drive mechanism housings. The support skirt and attachment 

welds for vessel supports 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 structures and components that comprise 

the reactor vessel are governed by Group A Quality Standards. 

System Interfaces 

The systems that interface with the reactor vessel include the reactor vessel internals (IV.B1), the reactor coolant pressure boundary (IV.C1), the emergency core cooling system (V.D2), and 

standby liquid control system (VII.E2).

NUREG-1 801 IV.A1 -2 April 2001
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IV Reactor Vessel, Internals, and Reactor Coolant System Al. Reactor Vessel (Boiling Water Reactor 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

Al.1-a Top head enclosure (without SA302- 2880C Loss of material/ Chapter XI.M1, "ASME Section Xl No cladding) Gr B, (5500F) steam General, pitting, Inservice Inspection, Subsections IWB, A1.1.1 Top head SA533- and crevice IWC, and IWD," for Class 1 components A1.1.2 Nozzles (vent, top head spray Gr B, corrosion and Chapter XI.M2, "Water Chemistry," 

or RCIC, and spare) SA336 for BWR water in BWRVIP-29 

(EPRI TR-1 03515) 

Al.1-b Top head enclosure SA302- 2880C (5500F) Cumulative Fatigue is a time-limited aging analysis Yes, A1.1.3 Head flange Gr B, steam fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

SA533- Fatigue extended operation, and, for Class 1 

Gr B, components, environmental effects on 

SA336, fatigue are to be addressed. See the 

with or Standard Review Plan, Section 4.3 

without "Metal Fatigue," for acceptable methods 

stainless- for meeting the requirements of 

steel 10 CFR 54.21 (c)(1)(i) and (ii), and for 

cladding addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

10 CFR 54.21 (c)(l )(iii). A1.1-c Top head enclosure SA193- Air, Crack initiation Chapter XI.M3, "Reactor Head Closure No 

A1.1.4 Closure studs and nuts Gr. B7, leaking and growth/ Studs" 

SA540- reactor Stress corrosion 

Gr. B23/24, coolant water cracking, SA320- and/or steam intergranular 

Gr. L43 at 2880C stress corrosion 

(AISI 4340), (550°F) cracking 

SA1 94

Gr. 7; 

maximum 

tensile 

strength 

<1172 

MPa (<170 Ksi)
IV Reactor Vessel, Internals, and Reactor Coolant System A4 n } I ~' l A f•_ _&_

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Li~il.;iu./lu VU•ui D VVals nea.Vui)t _ _ssel ___________or 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

Al.1-d Top head enclosure Stainless Leaking Cra6k initiation A plant-specific aging management Yes, 

A1.1.5 Vessel flange leak detection steel, reactor and growth/ program is to be evaluated because plant line Ni alloys coolant water Stress corrosion existing programs may not be able to specific 

and/or steam cracking, mitigate or detect crack initiation and 

up to 2880C intergranular growth due to SCC of vessel flange leak 

(5500F) stress corrosion detection line. 

cracking 

A1.2-a Vessel shell SA302- 2880C (5500F) Cumulative Fatigue is a time-limited aging analysis Yes, A1.2.1 Vessel flange Gr B, steam fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

A1.2.2 Upper shell SA533- Fatigue extended operation, and, for Class 1 

Gr B, components, environmental effects on 

SA336 fatigue are to be addressed. See the 

with Standard Review Plan, Section 4.3 

stainless "Metal Fatigue," for acceptable methods 

steel for meeting the requirements of 

cladding 10 CFR 54.21 (c)(1)(i) and (Ji), and for 

addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

10 CFR 54.21 (c)(1)(iii). Al.2-b Vessel shell SA302- 288°C (5500F) Cumulative Fatigue is a time-limited aging analysis Yes, 

Al.2.3 Intermediate nozzle shell Gr B, reactor fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

Al.2.4 Intermediate beltline shell SA533- coolant water Fatigue extended operation, and, for Class 1 

Al.2.5 Lower shell Gr B with components, environmental effects on 

Al.2.6 Beltline welds 308, 309, max 5x10 9 fatigue are to be addressed. See the 

308L, 309L n/cm2.s Standard Review Plan, Section 4.3 

cladding "Metal Fatigue," for acceptable methods 

for meeting the requirements of 10 CFR 

54.21 (c)(1)(i) and (ii), and for addressing 

environmental effects on fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 10 CFR 

____________ ~54.21 (c)(l )(iii). _ _ _ _ _
IV

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Reactor Vessel, Internals, and Reactor Coolant System •> 

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Al. Reactor Vessel (Boiling Water Reactor_ 

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A1.2-c Vessel shell SA302- 288°C (550OF) Loss of fracture Neutron irradiation embrittlement is a Yes, A1.2.4 Intermediate beltline shell Gr B, reactor toughness/ time dependent aging mechanism to be TLAA 

A1.2.6 Beltline welds SA533- coolant water Neutron irradiation evaluated for the period of extended 

Gr B with embrittlement operation for all ferritic materials that 

308, 309, 5x10 8 - 5x10 9 have a neutron fluence exceeding 

308L, 309L n/cm2.s 1017 n/cm2 (E >1 MeV) at the end of the 

cladding; license renewal term. Aspects of this 

and low- evaluation may involve a TLAA. In 

alloy steel accordance with approved BWRVIP-74, weldments the TLAA is to evaluate the Impact of 

neutron embrittlement on: (a) the 

adjusted reference temperature, the 

plant's pressure-temperature limits, (b) the need for inservice inspection of 

circumferential welds, and (c) the Charpy 

upper shelf energy or the equivalent 

margins analyses performed in 

accordance with 10 CFR 50, Appendix G. Additionally, the applicant is 

to monitor axial beltline weld 

embrittlement. One acceptable method 

is to determine that the mean RTNDT of 

the axial beltline welds at the end of the 

extended period of operation is less than 

the value specified by the staff in its May 7, 2000 letter. See the Standard Review 

Plan, Section 4.2 "Reactor Vessel 

Neutron Embrittlement" for acceptable 

methods for meeting the requirements of 

10 CFR 54.21 (c).

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism _Aging Management Program (AMP) Evaluation 

A1.2-d Vessel shell SA302- 2880C (5500F) Loss of fracture Chapter XI.M31, "Reactor Vessel Yes, plant A1.2.4 Intermediate beltline shell Gr B, reactor toughness/ Surveillance" specific A1.2.6 Beltline welds SA533- coolant water Neutron irradiation 

Gr B with embrittlement 

308, 309, 5x10 8 - 5x10 9 

308L, 309L n/cm2 .s 

cladding; 

and low

alloy steel 

weldments 

A1.2-e Vessel shell Stairiless 2880C Crack initiation Chapter XI.M4, "BWR Vessel ID No 

A1.2.7 Attachment welds steel, (5500F) and growth/ Attachment Welds," and 

Inconel reactor Stress corrosion 

182 coolant water cracking, Chapter XI.M2, "Water Chemistry," intergranular for BWR water in BWRVIP-29 (EPRI 

stress corrosion TR-1 03515) 

cracking 

A1.3-a Nozzles SA508-CI2 2880C (550TF) Cumulative Fatigue is a time-limited aging analysis Yes, 

A1.3.1 Main steam with or steam fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

without Fatigue extended operation, and, for Class 1 

stainless- components, environmental effects on 

steel fatigue are to be addressed. See the 

cladding Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 

10 CFR 54.21 (c)(1)(i) and (ii), and for 

addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

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

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Structure and/or Aging Effect! Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

Al .3-b Nozzles SA508-CI2 Up to 2880C Crack initiation Chapter XI.M5, "BWR Feedwater No 

A1.3.2 Feedwater with or (550°F), and growth/ Nozzle" 

without reactor Cyclic loading stainless coolant water 

steel 

cladding . A1.3-c Nozzles SA508-Cl2 Up to 2880C Crack initiation Chapter XI.M6, "BWR Control Rod Drive No A1.3.3 Control rod drive return line with or (550°F), and growth/ Return Line Nozzle" 

without reactor Cyclic loading 

stainless coolant water 

steel cladding 

A1.3-d Nozzles SA508-Cl2 Up to 2880C Cumulative Fatigue is a time-limited aging analysis Yes, A1.3.2 Feedwater with or (550°F), fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

A1.3.3 Control rod drive return line without reactor Fatigue extended operation, and, for Class 1 

stainless coolant water components, environmental effects on 

steel fatigue are to be addressed. See the 

cladding Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 

10 CFR 54.21 (c)(1)(i) and (ii), and for 

addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

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

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Al. Reactor Vessel (Boiling Water Reactor) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Proqram (AMP) Evaluation 

Al.3-e Nozzles SA508-C12 Up to 2880

0 Loss'of fracture Neutron irradiation embrittlement is a Yes, A1.3.4 Low pressure coolant reactor toughness/ time-limited aging analysis (TLAA) to be TLAA 

injection or RHR injection coolant water Neutron irradiation evaluated for the period of extended 

mode embrittlement operation for all ferritic materials that 

5x108 - 5x10 9 have a neutron fluence greater than 

n/cm 2"s 1017 n/cm2 (E >1 MeV) at the end of the 

license renewal term. In accordance with 

approved BWRVIP-74, the TLAA is to 

evaluate the impact of neutron 

embrittlement on: (a) the adjusted reference temperature, the plant's 

pressure-temperature limits, (b) the 

Charpy upper shelf energy, and (c) the 

equivalent margins analyses performed in accordance with 10 CFR 50, Appendix 

G. The applicant may choose to 

demonstrate that the materials of the 

nozzles are not controlling for the TLAA 

evaluations. See the Standard Review 

Plan, Section 4.2 "Reactor Vessel 

Neutron Embrittlement" for acceptable methods for meeting the requirements of 

10 CFR 54.21(c). Al.4-a Nozzle safe ends Stainless Up to 288°C Crack initiation Chapter XI.M7, "BWR Stress Corrosion No 

A1.4.1 High pressure core spray steel, (550°F), and growth/ Cracking," and 

A1.4.2 Low pressure core spray SB-1 66 reactor Stress corrosion 

A1.4.3 Control rod drive return line (Inconel coolant water cracking, Chapter XI.M2, "Water Chemistry," for 

A1.4.4 Recirculating water 182 butter, intergranular BWR water in BWRVIP-29 (EPRI A1.4.5 Low pressure coolant and stress corrosion TR-103515) 

injection or RHR injection Inconel 82 cracking mode or 182 1weld) II
Reactor Vessel, Internals, and Reactor Coolant System Al. Reactor Vessel (Bollina Water Reactor~ IV

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A1.4-b Nozzle safe ends Stainless Up to 2880C Cumulative Fatigue is a time-limited aging analysis Yes, A1.4.3 Control rod drive return line steel, (550°F), fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

SB-166 reactor Fatigue extended operation, and, for Class 1 

(Inconel coolant water components, environmental effects on 

182 butter, fatigue are to be addressed. See the 

and Standard Review Plan, Section 4.3 

Inconel 82 "Metal Fatigue," for acceptable methods 

or 182 for meeting the requirements of 

weld) 10 CFR 54.21 (c)(1)(i) and (ii), and for 

addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

10 CFR 54.21 (c)(1)(iii). Al.5-a Penetrations Stainless Up to 2880C Crack initiation Chapter XI.M8, "BWR Penetrations," and No 

A1.5.1 Control rod drive stub tubes steel, (550°F), and growth/ A1.5.2 Instrumentation SB-1 67 reactor Stress corrosion Chapter XI.M2, "Water Chemistry," for 

A1.5.3 Jet pump instrument coolant water cracking, BWR water in BWRVIP-29 (EPRI A1.5.4 Standby liquid control intergranular TR-1 03515) 

A1.5.5 Flux monitor stress corrosion 

A1.5.6 Drain line cracking, cyclic 

1 loading I I

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Al. Reactor Vessel (Bolling Water Reactor 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A1.5-b Penetrations Stainless Up to 288°C Cumulative Fatigue is a time-limited aging analysis Yes, 

A1.5.1 Control rod drive stub tubes steel, (550°F), fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

A1.5.2 Instrumentation SB-i 67 reactor Fatigue extended operation, and, for Class 1 

A1.5.3 Jet pump instrument coolant water components, environmental effects on 

A1.5.4 Standby liquid control fatigue are to be addressed. See the 

A1.5.5 Flux monitor Standard Review Plan, Section 4.3 

A1.5.6 Drain line "Metal Fatigue," for acceptable methods 

for meeting the requirements of 10 CFR 

54.21 (c)(1)(i) and (ii), and for addressing 

environmental effects on fatigue. 

See Chapter X.Ml of this report for 

meeting the requirements of 

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

Al.6-a Bottom head SA302- Up to 2880C Cumulative Fatigue is a time-limited aging analysis Yes, 

Gr B, (550°F) fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

SA533- reactor Fatigue extended operation, and, for Class 1 

Gr B with coolant water components, environmental effects on 

308, 309, fatigue are to be addressed. See the 

308L, 309L Standard Review Plan, Section 4.3 

cladding "Metal Fatigue," for acceptable methods 

for meeting the requirements of 

10 CFR 54.21 (c)(1)(i) and (ii), and for 

addressing environmental effects on 

fatigue. 

See Chapter X.Ml of this report for 

meeting the requirements of 

1 _10 CFR 54.21 (c)(1)(iii). 

A1.7-a Support skirt and attachment SA533- Ambient Cumulative Fatigue is a time-limited aging analysis Yes, 

welds Gr B temperature fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

(Welds air Fatigue extended operation. See the Standard 

low-alloy Review Plan, Section 4.3 "Metal 

steel) Fatigue," for acceptable methods for 

meeting the requirements of 

10 CFR 54.21 (c)(1).

( (
A2. REACTOR VESSEL (PRESSURIZED WATER REACTOR) 

A2.1 Closure Head 

A2.1.1 Dome 

A2.1.2 Head Flange 

A2.1.3 Stud Assembly 

A2.1.4 Vessel Flange Leak Detection Line 

A2.2 Control Rod Drive (CRD) Head Penetration 

A2.2.1 Nozzle 

A2.2.2 Pressure Housing 

A2.2.3 Flange Bolting 

A2.3 Nozzles 

A2.3.1 Inlet 

A2.3.2 Outlet 

A2.3.3 Safety Injection (on some) 

A2.4 Nozzle Safe Ends 

A2.4.1 Inlet 

A2.4.2 Outlet 

A2.4.3 Safety Injection (on some) 

A2.5 Shell 

A2.5.1 Upper (Nozzle) Shell 

A2.5.2 Intermediate and Lower Shell 

A2.5.3 Vessel Flange 

A2.5.4 Bottom Head 

A2.6 Core Support Pads/Core Guide Lugs 

A2.7 Penetrations 

A2.7.1 Instrument Tubes (Bottom Head) 

A2.7.2 Head Vent Pipe (Top Head) 

A2.7.3 Instrument Tubes (Top Head) 

A2.8 Pressure Vessel Support 

A2.8.1 Skirt Support 

A2.8.2 Cantilever/Column Support 

A2.8.3 Neutron Shield Tank

April 2001 IV.A2-1 NUREG-1801
A2. REACTOR VESSEL (PRESSURIZED WATER REACTOR)

Systems, Structures, and Components 

This section comprises 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. 

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 Babcox 

and Wilcox designs), the reactor coolant system and connected lines (IV.C2), and the 

emergency core cooling system (V.D1).

NUREG-1801 IV.A2.-2 April 2001
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A2. Reactor Vessel (Pressurized Water Reactor) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A2.1-a Closure head Dome and Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

A2.1.1 Dome flange: chemically Boric acid 

A2.1.2 Head flange SA302- treated corrosion of 

A2.1.3 Stud assembly Gr B, borated water external surfaces 

(external surfaces) SA533- or steam up to 

Gr B; stud 3400C (6440F) 

assembly: 

SA540

Gr. B23/ 

24, 

SA320

Gr. L43 

(alloy 4340) 

A2.1 -b Closure head SA302- Chemically Cumulative Fatigue is a time-limited aging analysis Yes, 

A2.1.1 Dome Gr B, treated fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

SA533- borated water Fatigue extended operation, and, for Class 1 

Gr B, or steam up to components, environmental effects on 

SA508-64 340°C (644°F) fatigue are to be addressed. See the 

class 2 Standard Review Plan, Section 4.3 

with "Metal Fatigue," for acceptable methods 

stainless for meeting the requirements of 

steel 10 CFR 54.21 (c)(1)(i) and (ii), and for 

cladding addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

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

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IV Reactor Vessel, Internals, and Reactor Coolant System 

A2. Reactor Vessel (Pressurized Water ReacLtor) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A2.1 -c Closure head SA540- Air, leaking Crack initiation Chapter XI.M3, "Reactor Head Closure No 

A2.1.3 Stud assembly Gr. B23/ chemically and growth/ Studs" 

24, treated Stress corrosion 

SA320- borated water cracking 

Gr. L43 or steam up to 

(alloy 340°C (644°F) 

4340), 

SA1 93-6 

maximum 

tensile 

strength 

<1172 

MPa (<170 Ksi) 

A2.1-d Closure head SA540- Air, leaking Loss of material/ Chapter XI.M3, "Reactor Head Closure No 

A2.1.3 Stud assembly Gr. B23/ chemically Wear Studs" 

24, treated 

SA320- borated water 

Gr. L43 or steam up to 

(alloy 340°C (644°F) 

4340), 

SAl 93-6 

maximum 

tensile 

strength 

<1172 

MPa 

(<170 Ksi)

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(

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0 Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A2.1-e Closure head SA540- Air, leaking Cumulative Fatigue is a time-limited aging analysis Yes A2.1.3 Stud assembly B23 and chemically fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

B24, treated Fatigue extended operation. See the Standard 

SA320- borated water Review Plan, Section 4.3 "Metal 

L43, or steam up to Fatigue," for acceptable methods for 

SA1 93-6 3400C (644°F) meeting the requirements of 

1_ _ 10 CFR 54.21(c)(1). A2.1 -f Closure head Stainless Leaking Crack initiation A plant-specific aging management Yes, plant A2.1.4 Vessel flange leak detection steel chemically and growth/ program is to be evaluated because specific line treated Stress corrosion existing programs may not be capable of 

borated water cracking mitigating or detecting crack initiation 

or steam up to and growth due to SCC in the vessel 

340°C (644°F) flange leak detection line. A2.2-a Control rod drive head SB-166, Chemically Crack initiation Chapter XI.M1 1, "Ni-alloy Nozzles and No 

penetration SB-1 67 treated and growth/ Penetrations," and 

A2.2.1 Nozzle (alloy 600) borated water Primary water 

up to 3400C stress corrosion Chapter XI.M2, "Water Chemistry," for (6440F) cracking PWR primary water in EPRI TR-1 05714 A2.2-b Control rod drive head Type 403 Chemically Crack initiation Chapter XI.M1, "ASME Section Xl No 

penetration and 316 treated and growth/ Inservice Inspection, Subsections IWB, A2.2.2 Pressure housing stainless borated water Stress corrosion IWC, and IWD," for Class 1 components 

steel; type up to 3400C cracking and 

304 (644°F) stainless Chapter XI.M2, "Water Chemistry," for 

steel or PWR primary water in EPRI TR-1 05714 

cast 

austenitic 

stainless 

steel CF-8; 

SA 508 

class 2 

with alloy 

82/182 1cladding I

z C 

m 

G) 

co 0
IV Reactor Vessel, Internals, and Reactor Coolant System A 0 *~~• %Il 1 I 0 ~Aee YlnA~ Wa~tgr 102ga, A•|rl

z 

C 

m 

co 

0) 

o 

00 

0.,.

(K

Ii•A. nl~ca.if .tJ, VQ@O~i • lO i ll q; ||~l• **- . I* __________ 

Structure and/or Aging Effect/ Further 

item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A2.2-c Controi rod drive head Type 403 Chemically Cumulative Fatigue is a time-limited aging analysis Yes, 

penetration and 316 treated fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

A2.2.1 Nozzle stainless borated water Fatigue extended operation, and, for Class 1 

A2.2.2 Pressure housing steel; type up to 340°C components, environmental effects on 

304 (644°F) fatigue are to be addressed. See the 

stainless Standard Review Plan, Section 4.3 

steel or "Metal Fatigue," for acceptable methods 

cast for meeting the requirements of 

austenitic 10 CFR 54.21 (c)(1)(i) and (ii), and for 

stainless addressing environmental effects on 

steel CF-8 fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

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

A2.2-d Control rod drive head Cast Chemically Loss of fracture Chapter Xi.M12 "Thermal Aging No 

penetration austenitic treated toughness/ Embrittlement of Cast Austenitic 

A2.2.2 Pressure housing stainless borated water Thermal aging Stainless Steel (CASS)" 

steel up to 3400C embrittlement 

CF-8 (6440F) 

A2.2-e Control rod drive head Stainless Air, leaking Crack initiation Chapter XI.M18, "Bolting Integrity" No 

penetration steel chemically and growth/ 

A2.2.3 Flange bolting (SA 453) treated Stress corrosion 

borated water cracking 

or steam up to 

3400C (6440F) 

A2.2-f Control rod drive head Stainless Air with metal Loss of material/ Chapter XI.M1 8, "Bolting Integrity" No 

penetration steel temperature Wear 

A2.2.3 Flange bolting (SA 453) up to 3400C 

(6440F) 

A2.2-g Control rod drive head Stainless Air with metal Loss of preload/ Chapter XI.M1 8, "Bolting Integrity" No 

penetration steel temperature Stress relaxation 

A2.2.3 Flange bolting (SA 453) up to 3400C 

I __ I_ _(644 0F) __
(

IV

(

Reactor Vessel, Internals, and Reactor Coolant System A2. Reactor Vessel (Pressurized Weter ReeP-tnrlI

C? 0 

0

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A2.3-a Nozzles SA336, Chemically Loss of fracture Neutron irradiation embrittlement is a Yes, A2.3.1 Inlet SA508 treated toughness/ time-limited aging analysis (TLAA) to be TLAA 

A2.3.2 Outlet with borated water Neutron irradiation evaluated for the period of license 

A2.3.3 Safety injection stainless up to 3400C embrittlement renewal for all ferritic materials that have 

steel (644°F) a neutron fluence greater than 

cladding 1017 n/cm 2 (E >1 MeV) at the end of the 

neutron license renewal term. The TLAA is to 

fluence evaluate the impact of neutron 

greater than embrittlement on: (a) the RTpTs value 

1017 n/cm2 based on the requirements in 

(E >1 MeV) 10 CFR 50.61, (b) the adjusted 

reference temperature, the plant's 

pressure-temperature limits, (c) the 

Charpy upper shelf energy, and (d) the 

equivalent margins analyses performed in accordance with 10 CFR 50, Appendix 

G. The applicant may choose to 

demonstrate that the materials in the 

inlet, outlet, and safety injection nozzles 

are not controlling for the TLAA 

evaluations. A2.3-b Nozzles SA336, Chemically Loss of fracture Chapter XI.M31, "Reactor Vessel Yes, plant A2.3.1 Inlet SA508 treated toughness/ Surveillance" specific A2.3.2 Outlet with borated water Neutron irradiation 

A2.3.3 Safety injection stainless up to 3400C embrittlement 

steel (644-F) 

cladding 

neutron 

fluence 

greater than 

1017 n/cm 2 

Z (E >1 MeV) _ C 

0 m 

OD 

0
Z 

C 

m 

00 ,..9

9 0 

0

/

IV Reactor Vessel, Internals, and Reactor Coolant System 

A2. Reactor Vessel (Pressurized Water Reactor) 

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A2.3-c Nozzles SA336, Chemically Cumulative Fatigue is a time-limited aging analysis Yes, 

A2.3.1 Inlet SA508 treated fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

A2.3.2 Outlet with borated water Fatigue extended operation, and, for Class 1 

A2.3.3 Safety injection stainless up to 3400C components, environmental effects on 

steel (644°F) fatigue are to be addressed. See the 

cladding Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 

10 CFR 54.21 (c)(1)(i) and (ii), and for 

addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

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

A2.4-a Nozzle safe ends Stainless Chemically Cumulative Fatigue is a time-limited aging analysis Yes, 

A2.4.1 Inlet steel, cast treated fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

A2.4.2 Outlet austenitic borated water Fatigue extended operation, and, for Class 1 

A2.4.3 Safety injection stainless up to 3400C components, environmental effects on 

steel (644°F) fatigue are to be addressed. See the 

(NiCrFe Standard Review Plan, Section 4.3 

buttering, "Metal Fatigue," for acceptable methods 

and for meeting the requirements of 

stainless 10 CFR 54.21 (c)(1)(i) and (ii), and for 

steel or addressing environmental effects on 

NiCrFe fatigue. 

weld) 

See Chapter X.M1 of this report for 

meeting the requirements of 

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

IV Reactor Vessel, Internals, and Reactor Coolant System Aq0 *•a~~ Xl aag•l /Pr--catrTlya Watar Ma rtnrl

V 

C? 0 

(0 

z 

C 

m 

co O0

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A2.4-b Nozzle safe ends Stainless Chemically Crack initiation Chapter XI.M1, "ASME Section Xl No 

A2.4.1 Inlet steel, cast treated and growth/ Inservice Inspection, Subsections IWB, 

A2.4.2 Outlet austenitic borated water Stress corrosion IWC, and IWD," for Class 1 components 

A2.4.3 Safety injection stainless up to 3400C cracking, primary and 

steel (644°F) water stress 

(NiCrFe corrosion cracking Chapter XI.M2, "Water Chemistry," for 

buttering, PWR primary water in EPRI TR-1 05714 

and 

stainless 

steel or 

NiCrFe 

weld) 

A2.5-a Vessel shell SA302- Chemically Loss of fracture Neutron irradiation embrittlement is a Yes 

A2.5.1 Upper shell Gr B, treated toughness/ time-limited aging analysis (TLAA) to be TLAA 

A2.5.2 Intermediate and lower shell SA533- borated water Neutron irradiation evaluated for the period of license 

(including beltline welds) Gr B, up to 3400C embrittlement renewal for all ferritic materials that have 

SA336, (644°F) a neutron fluence of greater than 

SA508- 1017 n/cm 2 (E >1 MeV) at the end of the 

Cl 2 or Cl 3 neutron license renewal term. The TLAA is to 

with type fluence evaluate the impact of neutron 

308 or 309 greater than embrittlement on: (a) the RTPTS value 

cladding 1017 n/cm 2 based on the requirements in 

(E >1 MeV) 10 CFR 50.61, (b) the adjusted reference 

temperature, the plant's pressure 

temperature limits, (c) the Charpy upper 

shelf energy, and (d) the equivalent 

margins analyses performed in 

accordance with 10 CFR 50, Appendix G. 

See the Standard Review Plan, Section 

4.2 "Reactor Vessel Neutron 

Embrittlement" for acceptable methods 

for meeting the requirements of 

10 CFR 54.21 (c).
IV Reactor Vessel, Internals, and Reactor Coolant System 

A2. Reactor Vessel (Pressurized Water Reactor)

z 

C 

m 

0,

No 

0 

0?

('.

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A2.5-b Vessel shell SA508- Chemically Crack growth/ Growth of intergranular separations Yes A2.5.1 Upper shell Cl 2 treated Cyclic loading (underclad cracks) in low-alloy steel TLAA 

A2.5.2 Intermediate and lower shell forgings borated water forging heat affected zone under 

(including beltline welds) clad using up to 340"C austenitic stainless steel cladding is a 

a high- (644°F) time-limited aging analysis (TLAA) to be 

heat-input evaluated for the period of extended 

welding neutron operation for all the SA 508-Cl 2 forgings 

process fluence where the cladding was deposited with a 

greater than high heat input welding process. The 

1017 n/cm 2 methodology for evaluating an underclad 

(E >1 MeV) flaw is in accordance with the current 

well-established flaw evaluation 

procedure and criterion in the ASME 

Section Xl Code. See the Standard 

Review Plan, Section 4.7, "Other Plant

Specific Time-Limited Aging Analysis," 

for generic guidance for meeting the requirements of 10 CFR 54.21 (c). A2.5-c Vessel shell SA302- Chemically Loss of fracture Chapter XI.M31, "Reactor Vessel Yes, plant A2.5.1 Upper shell, Gr B, treated toughness/ Surveillance" specific A2.5.2 Intermediate and lower shell SA533- borated water neutron irradiation 

(including beltline welds) Gr B, up to 3400C embrittlement 

SA336, (644°F) 

SA508

Cl 2 or Cl 3 neutron 

with type fluence 

308 or 309 greater than 

cladding 1017 n/cm 2 

I (E >1 MeV) I
IV

(

Reactor Vessel, Internals, and Reactor Coolant System A2. Reactor Vessel (Pressurized Water Reactori

(

Z 

'tJ 

OD 

0 0 

z 

m

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A2.5-d Vessel shell SA302- Chemically Cumulative Fatigue is a time-limited aging analysis Yes, A2.5.1 Upper (nozzle) shell Gr B, treated fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

A2.5.2 Intermediate and lower shell SA533- borated water Fatigue extended operation, and, for Class 1 

A2.5.3 Vessel flange Gr B, up to 3400C components, environmental effects on 

A2.5.4 Bottom head SA336, (644°F) fatigue are to be addressed. See the 

SA508 Standard Review Plan, Section 4.3 

with "Metal Fatigue," for acceptable methods 

stainless- for meeting the requirements of 

steel 10 CFR 54.21 (c)(1)(i) and (ii), and for 

cladding addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 10 CFR 

54.21 (c)(1)(iii). A2.5-e Vessel shell SA336, Air, leaking Loss of material/ Chapter XI.M1 0, "Boric Acid Corrosion" No 

A2.5.3 Vessel flange (external SA508 chemically Boric acid 

surface) treated corrosion of 

borated water external surfaces 

or steam up to 

I_ 3400

C (6440F) A2.5-f Vessel shell SA336, Chemically Loss of material/ Chapter XI.M1, "ASME Section XI No 

A2.5.3 Vessel flange SA508 treated Wear Inservice Inspection, Subsections IWB, 

borated water IWC, and IWD," for Class 1 components 

or steam up to 

3400C (6440F) A2.6-a Core support pads/core guide SB'166, Chemically Crack initiation A plant-specific aging management Yes, plant lugs SB-168, treated and growth/ program is to be evaluated. The specific (alloy 600) borated water Primary water applicant is to provide a plant-specific 

up to 3400C stress corrosion AMP or participate in industry programs 

(6440F) cracking to determine appropriate AMP. A2.7-a Penetrations SB-1 66, Chemically Crack initiation A plant-specific aging management Yes, plant A2.7.1 Instrument tubes (bottom SB-167, treated and growth/ program is to be evaluated. The specific head) (alloy 600) borated water Primary water applicant is to provide a plant-specific 

up to 3400C stress corrosion AMP or participate in industry programs 

(6440F) cracking to determine appropriate AMP. I
Reactor Vessel, Internals, and Reactor Coolant System Arb ~ • li 1• 0iLeL 1r A~n|• Wafl'ar O•ak tehlp'

z IV C 

m 

0 

0C 0

P-. r1190"W1Es~4 .'. ________ 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A2.7-b Penetrations SB-166, Chemically Crack initiation Chapter XI.M1 1, "Ni-alloy Nozzles and No 

A2.7.2 Head vent pipe(top head) SB-1 67, treated and growth/ Penetrations," and 

A2.7.3 Instrument tubes (top head) (alloy 600) borated water primary water 

up to 3400C stress corrosion Chapter XI.M2, "Water Chemistry," for 

(6440F) cracking PWR primary water in EPRI TR-1 05714 

A2.8-a Pressure vessel support SA302- Air Cumulative Fatigue is a time-limited aging analysis Yes, 

A2.8.1 Skirt support Gr B, fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

SA533- Fatigue extended operation. See the Standard 

Gr B, Review Plan, Section 4.3 "Metal 

SA516- Fatigue," for acceptable methods for 

Gr7O, meeting the requirements of 

SA 36 10 CFR 54.21(c)(1). 

A2.8-b Pressure vessel support SA302- Air, leaking Loss of material/ Chapter XI.M1 0, "Boric Acid Corrosion" No 

A2.8.1 Skirt support Gr B, chemically Boric acid 

A2.8.2 Cantilever/ SA533- treated corrosion of 

column support Gr B, borated water external surfaces 

A2.8.3 Neutron shield tank, SA516

Gr70, 

I _SA 36

_0 

N)

K.
B1. REACTOR VESSEL INTERNALS (BOILING WATER REACTOR) 

B1.1 Core Shroud and Core Plate 

B13.1.1 Core Shroud (Upper, Central, Lower) 

B1.1.2 Core Plate 

B13.1.3 Core Plate Bolts 

B13.1.4 Access Hole Cover 

B13.1.5 Shroud Support Structure 

B13.1.6 LPCI Coupling 

B13.2 Top Guide 

B13.3 Core Spray Lines and Spargers 

B13.3.1 Core Spray Lines (Headers) 

B13.3.2 Spray Ring 

B1.3.3 Spray Nozzles 

B1.3.4 Thermal Sleeve 

B1.4 Jet Pump Assemblies 

B13.4.1 Thermal Sleeve 

B1.4.2 Inlet Header 

B1.4.3 Riser Brace Arm 

B1.4.4 Holddown Beams 

B1.4.5 Inlet Elbow 

B1.4.6 Mixing Assembly 

B1.4.7 Diffuser 

B1.4.8 Castings 

B1.4.9 Jet Pump Sensing Line 

B1.5 Fuel Supports and Control Rod Drive (CRD) Assemblies 

B13.5.1 Orificed Fuel Support 

B1.5.2 CRD Housing 

B13.6 Instrumentation 

B13.6.1 Intermediate Range Monitor (IRM) Dry Tubes 

B13 6.2 Low Power Range Monitor (LPRM) Dry Tubes 

B1.6.3 Source Range Monitor (SRM) Dry Tubes 

B1.6.4 Incore Neutron Flux Monitor Guide Tubes

April 2001 IV B131-1 NUREG-1801
B1. REACTOR VESSEL INTERNALS (BOILING WATER REACTOR)

Systems, Structures, and Components 

This section comprises the boiling water reactor (BWR) vessel internals and consists of the 

core shroud and core plate, the top guide, feedwater spargers, core spray lines and spargers, 

jet pump assemblies, fuel supports and control rod drive (CRD), and instrument housings, such 

as the intermediate range monitor (IRM) dry tubes, the low power range monitor (LPRM) dry 

tubes, and the source range monitor (SRM) dry tubes. Based on Regulatory Guide 1.26, 

"Quality Group Classifications and Standards for Water, Steam, and Radioactive-Waste

Containing Components of Nuclear Power Plants," all structures and components that comprise 

the reactor vessel are governed by Group A or B Quality Standards. 

The steam separator and dryer assemblies are not part of the pressure boundary and are 

removed during each outage, and they are covered by the plant maintenance program. 

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 IV B1-2 April 2001

I I
( (

V 

0 

0 

a, 

cJ

IV Reactor Vessel, Internals, and Reactor Coolant System 

BI. Reactor Vessel Internals (Boiling Water Reactor) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

31.11-a Core shroud and core plate Stainless 2880C (5500 F) Crack initiation Chapter XI.M9, "BWR Vessel Internals," No 

B1.1.1 Core shroud (upper, central, steel high-purity and growth/ for core shroud and 

lower) water Stress corrosion 

cracking, Chapter XI.M2, "Water Chemistry" for 

intergranular BWR water in BWRVIP-29 (EPRI 

stress corrosion TR-1 03515) 

cracking, 

irradiation

assisted stress 

corrosion cracking 

Bl.1-b Core shroud and core plate Stainless 2880C (5500F) Crack initiation Chapter XI.M9, "BWR Vessel Internals," No 

81.1.2 Core plate steel high-purity and growth/ for core plate and 

B1.1.3 Core plate bolts (used in early water stress corrosion 

BWRs) cracking, Chapter XI.M2, "Water Chemistry" for 

intergranular BWR water in BWRVIP-29 (EPRI 

stress corrosion TR-1 03515) 

cracking, 

irradiation

assisted stress 

corrosion cracking 

31.1-c Core shroud and core plate Stainless 2880C (5500F) Cumulative For components for which a fatigue Yes, 

813.1.2 Core plate steel high-purity fatigue damage/ analysis has been performed for the TLAA 

water Fatigue 40-year period, fatigue is a time-limited 

aging analysis (TLAA) to be evaluated 

for the period of extended operation. See 

the Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 10 CFR 

54.21 (c)(1).

z 

m 

co 0D
IV Reactor Vessel, Internals, and Reactor Coolant System 

B1. Reactor Vessel Internals (Boiling Water Reactor) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B13.1-d Core shroud and core plate Alloy 600, 2880C (5500F) Crack initiation Chapter XI.M1, "ASME Section XI No 

B1.1.4 Access hole cover alloy 182 high-purity and growth/ Inservice Inspection, Subsections IWB, 

(welded covers) welds water Stress corrosion IWC, and IWD," for Class 1 components 

cracking, and Chapter XI.M2, "Water Chemistry," 

intergranular for BWR water in BWRVIP-29 (EPRI TR

stress corrosion 103515) 

cracking, 

irradiation- Because cracking initiated in crevice 

assisted stress regions is not amenable to visual 

corrosion cracking inspection, for BWRs with a crevice in 

the access hole covers, an augmented 

inspection is to include ultrasonic testing 

(UT) or other demonstrated acceptable 

inspection of the access hole cover 

welds. 

Bl.1-e Core shroud and core plate Alloy 600 2880C (5500F) Crack initiation Chapter XI.M1, "ASME Section Xl No 

B1.1.4 Access hole cover high-purity and growth/ Inservice Inspection, Subsections IWB, 

(mechanical covers) water Stress corrosion IWC, and IWD," for Class 1 components 

cracking, and 

intergranular 

stress corrosion Chapter XI.M2, "Water Chemistry," for 

cracking, BWR water in BWRVIP-29 (EPRI 

irradiation- TR-1 03515) 

assisted stress 

corrosion cracking 

Bl.1-f Core shroud and core plate Alloy 600, 2880C (5500F) Crack initiation Chapter XI.M9, "BWR Vessel Internals," No 

B1.1.5 Shroud support structure alloy 182 high-purity and growth/ for shroud support and 

(shroud support cylinder, welds water Stress corrosion 

shroud support plate, shroud cracking, Chapter XI.M2, "Water Chemistry," for 

support legs) intergranular BWR water in BWRVIP-29 (EPRI 

stress corrosion TR-103515) 

cracking, 

irradiation

assisted stress 

I corrosion cracking 1

('.
IV

(

Reactor Vessel, Internals, and Reactor Coolant System B1. Reactor Vessel Internals (Bololina Water Reactor•

(.

0 

0 

0

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

Bi.1-g Core shroud and core plate Stainless 2880C (5500F) Crack initiation Chapter XI.M9, "BWR Vessel Internals," No B1.1.6 LPCI coupling steel high-purity and growth/ for the LPCI coupling and 

water Stress corrosion 

cracking, Chapter XI.M2, "Water Chemistry," for 

intergranular BWR water in BWRVIP-29 (EPRI 

stress corrosion TR-1 03515) 

cracking, 

irradiation

assisted stress 

corrosion cracking 

B1.2-a Top guide Stainless 2880C (5500F) Crack initiation Chapter XI.M9, "BWR Vessel Internals," No 

steel high-purity and growth/ for top guide and 

water Stress corrosion 

cracking, Chapter XI.M2, "Water Chemistry," for 

intergranular BWR water in BWRVIP-29 (EPRI 

stress corrosion TR-103515) 

cracking, 

irradiation

assisted stress 

corrosion cracking 81.2-b Top guide Stainless 2880C (5500F) Cumulative For components for which a fatigue Yes, 

steel high-purity fatigue damage/ analysis has been performed for the TLAA 

water Fatigue 40-year period, fatigue is a time-limited 

aging analysis (TLAA) to be evaluated 

for the period of extended operation. See the Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 10 CFR 

54.21 (c)(1). I

z C 

m 

co 

0
IV Reactor Vessel, Internals, and Reactor Coolant System B1. Reactor Vessel Internals (Boloilino Water Reactorl

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

Bi.3-a Core spray lines and spargers Stainless 288°C (5507F) Crack initiation Chapter XI.M9, "BWR Vessel Internals," No 

B13.3.1 Core spray lines (headers) steel high-purity and growth/ for core spray internals and 

B1.3.2 Spray rings water Stress corrosion 

B1.3.3 Spray nozzles cracking, Chapter XI.M2, "Water Chemistry," for 

B13.3.4 Thermal sleeves intergranular BWR water in BWRVIP-29 (EPRI 

stress corrosion TR-103515) 

cracking 

irradiation

assisted stress 

corrosion cracking 

Bl.3-b Core spray lines and spargers Stainless 2880C (5500F) Cumulative For components for which a fatigue Yes, 

B1.3.1 Core spray lines (headers) steel high-purity fatigue damage/ analysis has been performed for the 40- TLAA 

B13.3.2 Spray rings water Fatigue year period, fatigue is a time-limited 

B13.3.3 Spray nozzles aging analysis (TLAA) to be evaluated 

B1.3.4 Thermal sleeves for the period of extended operation. See 

the Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 10 CFR 

54.21 (c)(1). 

B13.4-a Jet pump assemblies Holddown 2880C (5500F) Crack initiation Chapter XI.M9, "BWR Vessel Internals," No 

B13.4.1 Thermal sleeve beams: high-purity and growth/ for jet pump assembly and 

B13.4.2 Inlet header Ni alloy water Stress corrosion 

B1.4.3 Riser brace arm (X-750), cracking, Chapter XI.M2, "Water Chemistry," for 

B13.4.4 Holddown beams castings: intergranular BWR water in BWRVIP-29 (EPRI 

B13.4.5 Inlet elbow cast stress corrosion TR-103515) 

B13.4.6 Mixing assembly austenitic cracking, 

813.4.7 Diffuser stainless irradiation

B1i.4.8 Castings steel assisted stress 

(CASS), corrosion cracking 

others: 

stainless 

steel

K' ( .

,-a 

..J,
(

IV Reactor Vessel, Internals, and Reactor Coolant System 

-o B1. Reactor Vessel Internals (Boilina Water Reactor)

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B1.4-b Jet pump assemblies Holddown 2880C (5500F) Cumulative For components for which a fatigue Yes, 

B1.4.1 Thermal sleeve beams: high-purity fatigue damage/ analysis has been performed for the TLAA 

B13.4.2 Inlet header Ni alloy water Fatigue 40-year period, fatigue is a time-limited 

B1.4.3 Riser brace arm (X-750), aging analysis (TLAA) to be evaluated 

B13.4.4 Holddown beams others: for the period of extended operation. See 

B13.4.5 Inlet elbow stainless the Standard Review Plan, Section 4.3 

81.4.6 Mixing assembly steel "Metal Fatigue," for acceptable methods 

B13.4.7 Diffuser for meeting the requirements of 10 CFR 

B13.4.8 Castings 54.21 (c)(1). 

B1.4-c Jet pump assemblies Cast 2880C (5500F) Loss of fracture Chapter XI.M13, 'Thermal Aging and No 

B1.4.8 Castings austenitic high-purity toughness/ Neutron Irradiation Embrittlement of Cast 

stainless water Thermal aging Austenitic Stainless Steel (CASS)" 

steel and neutron 

irradiation 

embrittlement 

B1.4-d Jet pump assemblies Stainless 2880C (5500F) Crack initiation A plant-specific aging management Yes, plant 

B13.4.9 Jet pump sensing line steel high-purity and growth/ program is to be evaluated, specific 

water cyclic loading 

B1.5-a Fuel supports and control rod Cast 28800 (5500F) Loss of fracture Chapter XI.M1 3, "Thermal Aging and No 

drive assemblies austenitic high-purity toughness/ Neutron Irradiation Embrittlement of Cast 

81.5.1 Orificed fuel support stainless water Thermal aging Austenitic Stainless Steel (CASS)" 

steel and neutron 

irradiation 

I embrittlement 

B1.5-b Fuel supports and control rod Stainless 2880C (5500F) Cumulative For components for which a fatigue Yes, 

drive assemblies steel, cast high-purity fatigue damage/ analysis has been performed for the TLAA 

B1.5.1 Orificed fuel support austenitic water Fatigue 40-year period, fatigue is a time-limited 

stainless aging analysis (TLAA) to be evaluated 

steel for the period of extended operation. See 

the Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 10 CFR 

54.21 (c)(1).

z c C: 

m 

OD 

0

,
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m 

00 

do 

cy 

0

| 1. I rlJ a%. I V qp a l il I W I- 1" I_ .25 , 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B1.5-c Fuel supports and control rod Stainless Up to 2880C, Crack initiation Chapter XI.M9, "BWR Vessel Internals," No 

drive assemblies steel (5500F) and growth/ for lower plenum and 

B13.5.2 Control rod drive housing reactor Stress corrosion 

coolant water cracking, Chapter XI.M2, "Water Chemistry," for 

intergranular BWR water in BWRVIP-29 (EPRI 

stress corrosion TR-103515) 

cracking 

B1.6-a Instrumentation Stainless 2880C (550TF) Crack initiation Chapter XI. M9, "BWR Vessel Internals," No 

B13.6.1 Intermediate range monitor steel high-purity and growth/ for lower plenum and 

(IRM) dry tubes water Stress corrosion 

B13.6.3 Source range monitor (SRM) cracking, Chapter XI.M2, "Water Chemistry," for 

dry tubes intergranular BWR water in BWRVIP-29 (EPRI 

B1.6.4 Incore neutron flux monitor stress corrosion TR-103515) 

guide tubes cracking, 

irradiation

assisted stress 

corrosion cracking 

B1.6-b Instrumentation Stainless 2880C (5500F) Cumulative For components for which a fatigue Yes, 

B13.6.1 Intermediate range monitor steel high-purity fatigue damage/ analysis has been performed for the TLAA 

dry tubes water Fatigue 40-year period, fatigue is a time-limited 

B13.6.2 Low power range monitor dry aging analysis (TLAA) to be evaluated 

tubes for the period of extended operation. See 

B13.6.3 SRM dry tubes the Standard Review Plan, Section 4.3 

B13.6.4 Incore neutron flux monitor "Metal Fatigue," for acceptable methods 

guide tubes for meeting the requirements of 10 CFR 

I _ I_ I_ 1 154.21 (c)(1).

0 

0• 

0

( ( K,
B2. REACTOR VESSEL INTERNALS (PWR) - WESTINGHOUSE 

B2.1 Upper Internals Assembly 

B2.1.1 Upper Support Plate 

B2.1.2 Upper Support Column 

B2.1.3 Upper Support Column Bolts 

B2.1.4 Upper Core Plate 

B2.1.5 Upper Core Plate Alignment Pins 

B2.1.6 Fuel Alignment Pins 

B2.1.7 Hold-Down Spring 

B2.2 RCCA Guide Tube Assemblies 

B2.2.1 RCCA Guide Tubes 

B2.2.2 RCCA Guide Tube Bolts 

B2.2.3 RCCA Guide Tube Support Pins 

B2.3 Core Barrel 

B2.3.1 Core Barrel 

B2.3.2 Core Barrel Flange 

B2.3.3 Core Barrel Outlet Nozzles 

B2.3.4 Thermal Shield 

B2.4 Baffle/Former Assembly 

B2.4.1 Baffle and Former Plates 

B2.4.2 Baffle/Former Bolts 

82.5 Lower Internal Assembly 

B2.5.1 Lower Core Plate 

B2.5.2 Fuel Alignment Pins 

B2.5.3 Lower Support Forging or Casting 

B2.5.4 Lower Support Plate Columns 

B2.5.5 Lower Support Plate Column Bolts 

B2.5.6 Radial Support Keys and Clevis Inserts 

B2.5.7 Clevis Insert Bolts 

B2.6 Instrumentation Support Structures 

B2.6.1 Flux Thimble Guide Tubes 

B2.6.2 Flux Thimbles

April 2001 NUREG-1801 IV 132-1
B2. REACTOR VESSEL INTERNALS (PWR) - WESTINGHOUSE

Systems, Structures, and Components 

This section comprises the Westinghouse pressurized water reactor (PWR) vessel internals 

and consists of the upper internals assembly, the rod control cluster assemblies (RCCA) guide 

tube assemblies, the core barrel, the baffle/former assembly, the lower internal assembly, and 

the instrumentation support structures. Based on Regulatory Guide 1.26, "Quality Group 

Classifications and Standards for Water, Steam, and Radioactive-Waste-Containing 

Components of Nuclear Power Plants," all structures and components that comprise the 

reactor vessel are governed by Group A or B Quality Standards. 

System Interfaces 

The systems that interface with the reactor vessel internals include the reactor pressure vessel 

(IV.A2).

NUREG-1801 IV B2-2 April 2001

I I
IV

(

Reactor Vessel, Internals, and Reactor Coolant System B2. Reactor Vessel Internals (P WR• - Westinahouse

(

z C> 

"10 

0 

0 

R 0, 

0

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B2.1 -a Upper internals assembly Stainless Chemically Crack initiation Chapter XI.M16, "PWR Vessel No 

B2.1.1 Upper support plate steel treated and growth/ Internals," and 

B2.1.4 Upper core plate borated water Stress corrosion 

B2.1.7 Hold-down spring up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

(644-F) irradiation- PWR primary water in EPRI TR-1 05714 

assisted stress 

corrosion cracking 

B2.1 -b Upper internals assembly Stainless Chemically Changes in A plant-specific aging management Yes, plant B2.1 .1 Upper support plate steel treated dimensions/ program is to be evaluated. The specific B2.1.4 Upper core plate borated water Void Swelling applicant is to provide a plant-specific B2.1.7 Hold-down spring up to 3400C AMP or participate in industry programs 

(644°F) to investigate aging effects and 

determine appropriate AMP. Otherwise, 

the applicant is to provide the basis for 

concluding that void swelling is not an 

issue for the component. B2.1 -c Upper internals assembly Stainless Chemically Cumulative For components for which a fatigue Yes, B2.1.1 Upper support plate steel treated fatigue damage/ analysis has been performed for the TLAA 

B2.1.4 Upper core plate borated water Fatigue 40-year period, fatigue is a time-limited 

B2.1.7 Hold-down spring up to 3400C aging analysis (TLAA) to be evaluated 

(644°F) for the period of extended operation. See 

the Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 10 CFR 

54.21 (c)(1). 

B2.1 -d Upper internals assembly Stainless Chemically Loss of preload/ Chapter XI.M1, "ASME Section Xl No 

B2.1.7 Hold-down spring steel treated Stress relaxation Inservice Inspection, Subsections IWB, 

borated water IWC, and IWD," for Class 1 components 

up to 3400C and either 

(644°F) 

Chapter XI.M14, "Loose Part 

Monitoring," or Chapter XI.M15, "Neutron 

Noise Monitoring"
IV Reactor Vessel, Internals, and Reactor Coolant System R2. Reac~tor VesselInternalsIF (WR• - Westinahouse

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B2.1-e Upper internals assembly Stainless Chemically Crack initiation Chapter XI.M16, "PWR Vessel No 

B2.1.2 Upper support column steel, treated and growth/ Internals," and 

cast borated water Stress corrosion 

austenitic up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

stainless (6440F) irradiation- PWR primary water in EPRI TR-105714 

steel assisted stress 

corrosion cracking 

B2.1 -f Upper internals assembly Stainless Chemically Changes in A plant-specific aging management Yes, plant 

B2.1.2 Upper support column steel, treated dimensions/ program is to be evaluated. The specific 

cast borated water Void swelling applicant is to provide a plant-specific 

austenitic up to 3400C AMP or participate in industry programs 

stainless (644°F) to investigate aging effects and 

steel determine appropriate AMP. Otherwise, 

the applicant is to provide the basis for 

concluding that void swelling is not an 

issue for the component. 

B2.1-g Upper internals assembly Cast Chemically Loss of fracture Chapter XI.M13, "Thermal Aging and No 

B2.1.2 Upper support column austenitic treated toughness/ Neutron Irradiation Embrittlement of Cast 

(only cast austenitic stainless stainless borated water Thermal aging Austenitic Stainless Steel (CASS)" 

steel portions) steel up to 3400C and neutron 

(6440F) irradiation 

embrittlement, 

neutron void swelling 

fluence 

greater than 

1017 n/cm 2 

(E >1 MeV) 

B2.1-h Upper internals assembly Stainless Chemically Cumulative For components for which a fatigue Yes, 

B2.1.2 Upper support column steel, treated fatigue damage/ analysis has been performed for the TLAA 

cast borated water Fatigue 40-year period, fatigue is a time-limited 

austenitic up to 3400C aging analysis (TLAA) to be evaluated 

stainless (6440F) for the period of extended operation. See 

steel the Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 10 CFR 

54.21 (c)(1).

( K
IV

(

Reactor Vessel, Internals, and Reactor Coolant System B2. Reactor Vessel Internple- ( WR1 - Wofnnoh^,,eo

(

V 

.,-• 

01

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation B2.1 -i Upper internals assembly Stainless Chemically Crack initiation Chapter XI.M16, "PWR Vessel No B2.1.3 Upper support column bolts steel, treated and growth/ Internals," and B2.1.5 Upper core plate alignment Ni alloy borated water Stress corrosion pins up to 3400C cracking, primary Chapter XI.M2, "Water Chemistry," for B2.1.6 Fuel alignment pins (644°F) water stress PWR primary water in EPRI TR-1 05714 

corrosion 

cracking, 

irradiation

assisted stress 

corrosion cracking B2.1-j Upper internals assembly Stainless Chemically Changes in A plant-specific aging management Yes, plant B2.1.3 Upper support column bolts steel, treated dimensions/ program is to be evaluated. The specific B2.1.5 Upper core plate alignment Ni alloy borated water Void swelling applicant is to provide a plant-specific pins up to 3400C AMP or participate in industry programs B2.1.6 Fuel alignment pins (644OF) to investigate aging effects and 

determine appropriate AMP. Otherwise, 

the applicant is to provide the basis for 

concluding that void swelling is not an issue for the component. B2.1 -k Upper internals assembly Stainless Chemically Loss of preload/ Chapter XI.M1, "ASME Section XI No B2.1.3 Upper support column bolts steel, treated Stress relaxation Inservice Inspection, Subsections IWB, Ni alloy borated water IWC, and IWD," for Class 1 components 

up to 3400

C and 

(644°F) 

B2.1-1 Upper Chapter XI.M14, "Loose Part Monitoring" internals assembly Stainless Chemically Loss of material/ Chapter XI.M1, "ASME Section Xl No B2.1.5 Upper core plate alignment steel, treated Wear Inservice Inspection, Subsections IWB, pins Ni alloy borated water IWC, and IWD," for Class 1 components 

up to 3400C 

(644°F)

z 

C 

m 

co 0
IV Reactor Vessel, Internals, and Reactor Coolant System R9_ ReAr~tnr Ve__~I Internal; (P'WR• - Westinohouse

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B2.1 -m Upper internals assembly Stainless Chemically Cumulative For components for which a fatigue Yes, 

B2.1.6 Fuel alignment pins steel, treated fatigue damage/ analysis has been performed for the TLAA 

Ni alloy borated water Fatigue 40-year period, fatigue is a time-limited 

up to 3400C aging analysis (TLAA) to be evaluated 

(644-F) for the period of extended operation. See 

the Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 10 CFR 

54.21(c)(1). 

B2.2-a RCCA guide tube assemblies Stainless Chemically Crack initiation Chapter XI.M16, "PWR Vessel No 

B2.2.1 ROCA guide tubes steel treated and growth/ Internals," and 

borated water Stress corrosion 

up to 340°C cracking, Chapter XI.M2, "Water Chemistry," for 

(644-F) irradiation- PWR primary water in EPRI TR-105714 

assisted stress 

corrosion cracking 

B2.2-b ROCA guide tube assemblies Stainless Chemically Changes in A plant-specific aging management Yes, 

B2.2.1 RCCA guide tubes steel treated dimensions/ program is to be evaluated. The plant 

borated water Void swelling applicant is to provide a plant-specific specific 

up to 3400C AMP or participate in industry programs 

(644°F) to investigate aging effects and 

determine appropriate AMP. Otherwise, 

the applicant is to provide the basis for 

concluding that void swelling is not an 

I_ issue for the component. 

B2.2-c ROCA guide tube assemblies Stainless Chemically Cumulative For components for which a fatigue Yes, 

B2.2.1 RCCA guide tubes steel treated fatigue damage/ analysis has been performed for the TLAA 

borated water Fatigue 40-year period, fatigue is a time-limited 

up to 3400C aging analysis (TLAA) to be evaluated 

(644°F) for the period of extended operation. See 

the Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 10 CFR 54.21 (c)(1).

( ( K
(. (

IV Reactor Vessel, Internals, and Reactor Coolant System B2. Reactor Vessel Internals PWRY - Westinghouse

0 

00 

,4 

Z 

a 

m 

0 

0_

Structure and/or Aging Effect? Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B2.2-d RCCA guide tube assemblies Stainless Chermiically Crack initiation Chapter XI.M16, "PWR Vessel No 

B2.2.2 RCCA guide tube bolts steel, treated and growth/ Internals," and 

B2.2.3 RCCA guide tube support Ni alloy borated water Stress corrosion 

pins up to 3400C cracking, primary Chapter XI.M2, "Water Chemistry," for 

(644°F) water stress PWR primary water in EPRI TR-1 05714 

corrosion 

cracking, 

irradiation

assisted stress 

corrosion cracking B2.2-e RCCA guide tube assemblies Stainless Chemically Changes in A plant-specific aging management Yes, plant B2.2.2 RCCA guide tube bolts, steel, treated dimensions/ program is to be evaluated. The specific B2.2.3 RCCA guide tube support Ni alloy borated water Void swelling applicant is to provide a plant-specific pins up to 3400C AMP or participate in industry programs 

(644°F) to investigate aging effects and 

determine appropriate AMP. Otherwise, the applicant is to provide the basis for 

concluding that void swelling is not an 

issue for the component. B2.2-f RCCA guide tube assemblies Stainless Chemically Cumulative For components for which a fatigue Yes, B2.2.2 RCCA guide tube bolts steel, treated fatigue damage/ analysis has been performed for the TLAA 

B2.2.3 RCCA guide tube support Ni alloy borated water Fatigue 40-year period, fatigue is a time-limited 

pins up to 3400C aging analysis (TLAA) to be evaluated 

(644°F) for the period of extended operation. See 

the Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 10 CFR 

54.21(c)(1). B2.3-a Core barrel Stainless Chemically Crack initiation Chapter XI.M1 6, "PWR Vessel No 

B2.3.1 Core barrel (CB) steel treated and growth/ Internals," and 

B2.3.2 CB flange (upper) borated water Stress corrosion 

82.3.3 CB outlet nozzles up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

B2.3.4 Thermal shield (644°F) irradiation- PWR primary water in EPRI TR-1 05714 

assisted stress 

corrosion cracking 1
IV Reactor Vessel, Internals, and Reactor Coolant System 82. Reactor Vessel Internals (IPWR• - Westinahouse

z 

C 

33 m 

0 

0 0D

(

-... ... . .... . . . .. .......... - '- ... .. .. . .. - . 

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B2.3-b Core barrel Stainless Chemically Changes in A plant-specific aging management Yes,'plant B2.3.1 Core barrel (CB) steel treated dimensions/ program is to be evaluated. The specific B2.3.2 CB flange (upper) borated water Void swelling applicant is to provide a plant-specific 

B2.3.3 CB outlet nozzles up to 3400C AMP or participate in industry programs B2.3.4 Thermal shield (644°F) to investigate aging effects and 

determine appropriate AMP. Otherwise, 

the applicant is to provide the basis for 

concluding that void swelling is not an 

issue for the component. B2.3-c Core barrel Stainless Chemically Loss of fracture Chapter XI.M16, "PWR Vessel Internals" No 

B2.3.1 Core barrel (CB) steel treated toughness/ 

B2.3.2 CB flange (upper) borated water Neutron irradiation 

B2.3.3 CB outlet nozzles up to 3400C embrittlement, 

B2.3.4 Thermal shield (6440F) void selling 

neutron 

fluence 

greater than 

1017 n/cm2 

(E>1 MeV) 

B2.3-d Core barrel Stainless Chemically Cumulative For components for which a fatigue Yes, 

82.3.1 Core barrel (CB) steel treated fatigue damage/ analysis has been performed for the TLAA 

B2.3.2 CB flange (upper) borated water Fatigue 40-year period, fatigue is a time-limited 

B2.3.3 CB outlet nozzles up to 3400C aging analysis (TLAA) to be evaluated 

B2.3.4 Thermal shield (644°F) for the period of extended operation. See 

the Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 10 CFR 

54.21(c)(1). 

B2.4-a Baffle/former assembly Stainless Chemically Crack initiation Chapter XI.M1 6, "PWR Vessel No 

B2.4.1 Baffle and former plates steel treated and growth/ Internals," and 

borated water Stress corrosion 

up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

(644°F) irradiation- PWR primary water in EPRI TR-1 05714 

assisted stress 

I corrosion cracking 1

0 

0?
( ( (

-o 

Co

IV Reactor Vessel, Internals, and Reactor Coolant System 3B2. Reactor Vessel Internals (PWR) - Westinghouse 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation B2.4-b Baffle/former assembly Stainless Chemically Changes in A plant-specific aging management Yes, plant B2.4.1 Baffle and former plates steel treated dimensions/ program is to be evaluated. The specific 

borated water Void swelling applicant is to provide a plant-specific up to 3400C AMP or participate in industry programs (644°F) to investigate aging effects and 

determine appropriate AMP. Otherwise, the applicant is to provide the basis for 

concluding that void swelling is not an 

issue for the component or is to provide 

an AMP. The applicant is to address the 

B2.4-c Baffle/former loss of ductility associated with swelling. assembly Stainless Chemically Crack initiation A plant-specific aging management Yes, plant B2.4.2 Baffle/former bolts steel treated and growth/ program is to be evaluated, specific (type 347 borated water Stress corrosion 

and up to 3400C cracking, Historically, the VT-3 visual examinations cold- (6440F) and irradiation- have not identified baffle/former bolt worked high fluence assisted stress cracking because cracking occurs at the type 316) (>10 dpa or corrosion cracking juncture of the bolt head and shank, 

7 x 10;1 n/cm 2 which is not accessible for visual 

E >1 MeV) inspection. However, recent UT 

examinations of the baffle/former bolts 

have identified cracking in several plants. The industry is currently addressing the 

issue of baffle bolt cracking in the PWR 

Materials Reliability Project, Issues Task 

Group (ITG) activities to determine, 

develop, and implement the necessary 

steps and plans to manage the 

applicable aging effects on a plant I specific basis.

z 

C 

m 

0
IV Reactor Vessel, Internals, and Reactor Coolant System 

B2. Reactor Vessel Internals (PWR) - Westinghouse 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B2.4-d Baffle/former assembly Stainless Chemically Changes in A plant-specific aging management Yes, plant 

B2.4.2 Baffle/former bolts steel treated dimensions/ program is to be evaluated. The specific 

(type 347 borated water Void swelling applicant is to provide a plant-specific 

and up to 3400C AMP or participate in industry programs 

cold- (6440F) and to investigate aging effects and 

worked high fluence determine appropriate AMP. Otherwise, 

type 316) the applicant is to provide the basis for 

concluding that void swelling is not an 

issue for the component.. 

B2.4-e Baffle/former assembly Stainless Chemically Loss of fracture Chapter XI.M16, "PWR Vessel Interrials" No 

B2.4.1 Baffle and former plates steel treated toughness/ 

borated water Neutron irradiation 

up to 3400C embrittlement, 

void swelling 

fluence 

>1017 n/cm2 

(E >1 MeV) 

B2.4-f Baffle/former assembly Stainless Treated Loss of fracture A plant-specific aging management Yes, plant 

B2.4.2 Baffle/former bolts steel borated water toughness/ program is to be evaluated, specific 

(type 347 up to 3400C Neutron irradiation 

and embrittlement 

cold- fluence 

worked >1017 n/cm2 

type 316) (E >1 MeV) 

B2.4-g Baffle/former assembly Stainless Chemically Cumulative For components for which a fatigue Yes, 

B2.4.1 Baffle and former plates steel, treated fatigue damage/ analysis has been performed for the TLAA 

B2.4.2 Baffle/former bolts Ni alloy borated water Fatigue 40-year period, fatigue is a time-limited 

(bolts) up to 3400C aging analysis (TLAA) to be evaluated 

(644°F) for the period of extended operation. See 

the Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 10 CFR 

54.21(c)(1). I _I

(
(

IV Reactor Vessel, Internals, and Reactor Coolant System B2. Reactor Vessel Internals (P'WR• - Westinahouse

(

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B2.4-h Baffle/former assembly Stainless Chemically Loss of preload/ A plant-specific aging management Yes, plant 

B2.4.2 Baffle/former bolts steel, treated Stress relaxation program is to be evaluated. Visual specific 

Ni alloy borated water inspection (VT-3) is to be augmented to 

up to 3400C detect relevant conditions of stress 

(6440F) relaxation because only the heads of the 

baffle/former bolts are visible, and a 

plant-specific aging management 

program is thus required. 

B2.5-a Lower internal assembly Stainless Chemically Crack initiation Chapter XI.M16, "PWR Vessel No 

B2.5.1 Lower core plate steel treated and growth/ Internals," and 

B2.5.6 Radial keys and clevis inserts borated water Stress corrosion 

up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

(644°F) irradiation- PWR primary water in EPRI TR-1 05714 

assisted stress 

corrosion cracking 

B2.5-b Lower internal assembly Stainless Chemically Changes in A plant-specific aging management Yes, plant 

B2.5.1 Lower core plate steel treated dimensions/ program is to be evaluated. The specific 

B2.5.6 Radial keys and clevis inserts borated water Void swelling applicant is to provide a plant-specific 

up to 3400C AMP or participate in industry programs 

(644°F) to investigate aging effects and 

determine appropriate AMP. Otherwise, 

the applicant is to provide the basis for 

concluding that void swelling is not an 

issue for the component. 

B2.5-c Lower internal assembly Stainless Treated Loss of fracture Chapter XI.M16, "PWR Vessel Internals" No 

B2.5.1 Lower core plate steel borated water toughness/ 

up to 3400C Neutron irradiation 

embrittlement, 

fluence void swelling 

>1017 n/cm2 

(E >1 MeV)
IV Reactor Vessel, Internals, and Reactor Coolant System B2. Reactor Vessel Internals (PWR) - Westinahouse

z 

C 

m 

co 

0 

I\ 

V

(

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation B2.5-d Lower internal assembly Stainless Chemically' Cumulative For components for which a fatigue Yes, B2.5.1 Lower core plate steel treated fatigue damage/ analysis has been performed for the TLAA B2.5.4 Lower support plate columns borated water Fatigue 40-year period, fatigue is a time-limited 

up to 3400C aging analysis (TLAA) to be evaluated 

(644°F) for the period of extended operation. See 

the Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 10 CFR 54.21 (c)(1). 

B2.5-e Lower internal assembly Stainless Chemically Crack initiation Chapter XI.M1 6, "PWR Vessel No B2.5.2 Fuel alignment pins steel, treated and growth/ Internals," and 

B2.5.5 Lower support plate column Ni alloy borated water Stress corrosion 

bolts up to 340'C cracking, primary Chapter XI.M2, "Water Chemistry" for B2.5.7 Clevis insert bolts (644°F) water stress PWR primary water in EPRI TR-1 05714 

corrosion 

cracking, 

irradiation

assisted stress 

corrosion cracking 82.5-f Lower internal assembly Stainless Chemically Changes in A plant-specific aging management Yes, plant B2.5.2 Fuel alignment pins steel, treated dimensions/ program is to be evaluated. The specific B2.5.5 Lower support plate column Ni alloy borated water Void swelling applicant is to provide a plant-specific bolts up to 3400C AMP or participate in industry programs B2.5.7 Clevis insert bolts (644OF) to investigate aging effects and 

determine appropriate AMP. Otherwise, the applicant is to provide the basis for 

concluding that void swelling is not an issue for the component. B2.5-g Lower internal assembly Stainless Treated Loss of fracture Chapter XI.M16, "PWR Vessel Internals" No B2.5.2 Fuel alignment pins steel, borated water toughness/ 82.5.5 Lower support plate column Ni alloy up to 3400C Neutron irradiation 

bolts embrittlement, 82.5.7 Clevis insert bolts fluence void swelling 

>1017 n/cm 2 

(E >1 MeV)_
(

IV Reactor Vessel, Internals, and Reactor Coolant System B2. Reactor Vessel Internais (FPWR} - Westinahouse

(

9 

03 

z 

C 

m 

00 

0>

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B2.5-h Lower internal assembly Stainless Ch5emically Loss of preload/ Chapter XI.M1, "ASME Section Xl No 

B2.5.5 Lower support plate column steel, treated Stress relaxation Inservice Inspection, Subsections IWB, bolts Ni alloy borated water IWC, and IWD," for Class 1 components 

up to 3400C and Chapter XI.M14, "Loose Part 

(6440F) Monitoring" B2.5-i Lower internal assembly Stainless Chemically Loss of preload/ Chapter XI.M1, "ASME Section Xl No 

B2.5.7 Clevis insert bolts steel, treated Stress relaxation Inservice Inspection, Subsections IWB, 

Ni alloy borated water IWC, and IWD," for Class 1 components 

up to 3400

C and either Chapter XI.M14, "Loose Part 

(6440F) Monitoring," or Chapter XI.M1 5, "Neutron 

Noise Monitoring" B2.5-j Lower internal assembly Stainless Chemically Cumulative For components for which a fatigue Yes, B2.5.2 Fuel alignment pins steel, treated fatigue damage/ analysis has been performed for the TLAA 

B2.5.5 Lower support plate column Ni alloy borated water Fatigue 40-year period, fatigue is a time-limited 

bolts up to 3400C aging analysis (TLAA) to be evaluated 

(6440F) for the period of extended operation. See 

the Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 10 CFR 

54.21 (c)(1). B2.5-k Lower internal assembly Stainless Chemically Crack initiation Chapter XI.M16, "PWR Vessel No 

B2.5.3 Lower support forging or steel, treated and growth/ Internals," and 

casting cast borated water Stress corrosion 

B2.5.4 Lower support plate columns austenitic up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

stainless (6440F) irradiation- PWR primary water in EPRI TR-1 05714 

steel assisted stress 

corrosion cracking B2.5-1 Lower internal assembly Stainless Chemically Changes in A plant-specific aging management Yes, plant B2.5.3 Lower support forging or steel, treated dimensions/ program is to be evaluated. The specific casting cast borated water Void swelling applicant is to provide a plant-specific B2.5.4 Lower support plate columns austenitic up to 3400C AMP or participate in industry programs 

stainless (644°F) to investigate aging effects and 

steel determine appropriate AMP. Otherwise, 

the applicant is to provide the basis for 

concluding that void swelling is not an 

Issue for the component. I
z 

C 

m 

0 

co 

0

0 

0

(

IV Reactor Vessel, Internals, and Reactor Coolant System 

B2. Reactor Vessel Internals (PWR) - Westinghouse 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B2.5-m Lower internal assembly Cast Chemically Loss of fracture Chapter XI.M1 3, "Thermal Aging and No 

B2.5.3 Lower support forging or austenitic treated toughness/ Neutron Irradiation Embrittlement of Cast 

casting stainless borated water Thermal aging Austenitic Stainless Steel (CASS)" B2.5.4 Lower support plate columns steel up to 3400C and neutron 

(644°F) irradiation 

embrittlement, 

fluence void swelling 

>1017 n/cm2 

(E >1 MeV) B2.5-n Lower internal assembly Stainless Chemically Loss of fracture Chapter XI.M16, "PWR Vessel Internals" No 

B2.5.3 Lower support forging or steel treated toughness/ 

casting borated water Neutron irradiation 

B2.5.4 Lower support plate columns up to 3400C embrittlement, 

(644°F) void swelling 

fluence 

>1017 n/cm2 

(E >1 MeV) 

B2.5-o Lower internal assembly Stainless Chemically Loss of material/ Chapter XI.M1, "ASME Section Xl No 

B2.5.6 Radial keys and clevis Inserts steel treated Wear Inservice Inspection, Subsections IWB, 

borated water IWC, and IWD," for Class 1 components 

up to 3400C 

(6440F) 

B2.5-p Lower internal assembly Stainless Chemically Cumulative For components for which a fatigue Yes, B2.5.6 Radial keys and clevis inserts steel treated fatigue damage/ analysis has been performed for the TLAA 

B2.5.7 Clevis insert bolts borated water Fatigue 40-year period, fatigue is a time-limited 

up to 3400C aging analysis (TLAA) to be evaluated 

(6440F) for the period of extended operation. See 

the Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 10 CFR 

54.21(c)(1). I
I 

IV Reactor Vessel, Internals, and Reactor Coolant System B2. Reactor Vessel Internals (P'WR) - Westinohouse

Ctl 

03

(

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation B2.6-a Instrumentation support Stainless Chemically Crack initiation Chapter XI.M16, "PWR Vessel No 

structures steel treated and growth/ Internals," and 

B2.6.1 Flux thimble guide tubes borated water Stress corrosion 

up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

(6440F) irradiation- PWR primary water in EPRI TR-1 05714 

assisted stress 

corrosion cracking B2.6-b Instrumentation support Stainless Chemically Changes in A plant-specific aging management Yes, plant structures steel treated dimensions/ program is to be evaluated. The specific B2.6.1 Flux thimble guide tubes borated water Void swelling applicant is to provide a plant-specific 

up to 3400C AMP or participate in industry programs 

(644°F) to investigate aging effects and 

determine appropriate AMP. Otherwise, 

the applicant is to provide the basis for 

concluding that void swelling is not an 

issue for the component.

z 

C 

m 

9
IV Reactor Vessel, Internals, and Reactor Coolant System R2.. Reactotr V,•s•,l Internals tP)WR• - Westinohouse

z C 

m 

Go 

0)

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B2.6-c Instrumentation support Stainless Chemically Loss of material/ Chapter XI.M1, "ASME Section XI No 

structures steel treated Wear Inservice Inspection, Subsections IWB, 

B2.6.2 Flux thimble borated water IWC, and IWD," for Class 1 components 

up to 340°C and 

(6440F) 

recommendations of NRC I&E Bulletin 

88-09 "Thimble Tube Thinning in 

Westinghouse Reactors," described 

bellow: 

In response to I&E Bulletin 88-09, an 

inspection program, with technical 

justification, is to be established and is to 

include (a) an appropriate thimble tube 

wear acceptance criterion, e.g., percent 

through-wall loss, and includes 

allowances for inspection methodology 

and wear scar geometry uncertainty, 

(b) an appropriate inspection frequency, 

e.g., every refueling outage, and (c) 

inspection methodology such as eddy 

current technique that is capable of 

adequately detecting wear of the thimble 

tubes. In addition, corrective actions 

include isolation or replacement if a 

thimble tube fails to meet the above 

acceptance criteria. Inspection schedule 

is in accordance with the guidelines of 

I&E Bulletin 88-09.

-o 

0 

C0
B3. REACTOR VESSEL INTERNALS (PWR) - COMBUSTION ENGINEERING 

B3.1 Upper Internals Assembly 

B3.1.1 Upper Guide Structure Support Plate 

B3.1.2 Fuel Alignment Plate 

B3.1.3 Fuel Alignment Plate Guide Lugs and Guide Lug Inserts 

B3.1.4 Hold-Down Ring 

B3.2 Control Element Assembly (CEA) Shroud Assemblies 

B3.2.1 CEA Shrouds 

B3.2.2 CEA Shrouds Bolts 

B3.2.3 CEA Shrouds Extension Shaft Guides 

B3.3 Core Support Barrel 

B3.3.1 Core Support Barrel 

B3.3.2 Core Support Barrel Upper Flange 

B3.3.3 Core Support Barrel Alignment Keys 

B3.4 Core Shroud Assembly 

B3.4.1 Core Shroud Assembly 

B3.4.2 Core Shroud Assembly Bolts 

B3.4.3 Core Shroud Tie Rods 

B3.5 Lower Internal Assembly 

B3.5.1 Core Support Plate 

B3.5.2 Fuel Alignment Pins 

B3.5.3 Lower Support Structure Beam Assemblies 

B3.5.4 Core Support Column 

B3.5.5 Core Support Column Bolts 

B3.5.6 Core Support Barrel Snubber Assemblies

April 2001 IV 133-1 NUREG-1801
B3. REACTOR VESSEL INTERNALS (PWR) - COMBUSTION ENGINEERING 

Systems, Structures, and Components 

This section comprises the Combustion Engineering pressurized water reactor (PWR) vessel 

internals and consists of the upper internals assembly, the CEA shroud assemblies, the core 

support barrel, the core shroud assembly, and the lower internal assembly. Based on 

Regulatory Guide 1.26, "Quality Group Classifications and Standards for Water, Steam, and 

Radioactive-Waste-Containing Components of Nuclear Power Plants," all structures and 

components that comprise the reactor vessel are governed by Group A or B Quality Standards. 

System Interfaces 

The systems that interface with the reactor vessel internals include the reactor pressure vessel 

(IV.A2).

NUREG-1801 IV 13-2 April 2001

I I
( K (

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IV Reactor Vessel, Internals, and Reactor Coolant System 

B3. Reactor Vessel Internals ( WR) - Combustion Engineering__ 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B3.1 -a Upper Internals Assembly Stainless Chemically Crack initiation Chapter XI.M16 "PWR Vessel Internals," No 

B3.1.1 Upper guide structure support steel treated and growth/ and 

plate borated water Stress corrosion 

B3.1.2 Fuel alignment plate up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

B3.1.3 Fuel alignment plate guide (644°F) irradiation- PWR primary water in EPRI TR-105714 

lugs and guide lug inserts assisted stress 

corrosion cracking B3.1 -b Upper Internals Assembly Stainless Chemically Changes in A plant-specific aging management Yes, plant B3.1.1 Upper guide structure support steel treated dimensions/ program is to be evaluated. The specific plate borated water Void swelling applicant is to provide a plant-specific B3.1.2 Fuel alignment plate up to 3400C AMP or participate in industry programs B3.1.3 Fuel alignment plate guide (644°F) to investigate aging effects and 

lugs and guide lug inserts determine appropriate AMP. Otherwise, 

the applicant is to provide the basis for 

concluding that void swelling is not an 

issue for the component. B3.1-c Upper Internals Assembly Stainless Chemically Loss of material/ Chapter XI.M1, "ASME Section XI No 

B3.1.2 Fuel alignment plate steel treated Wear Inservice Inspection, Subsections IWB, 

B3.1.3 Fuel alignment plate guide borated water IWC, and IWD," for Class 1 components 

lugs and their lugs up to 3400C 

B3.1.4 Hold-down ring (644°F) 

B3.2-a CEA Shroud Assemblies Stainless Chemically Crack initiation Chapter XI.M16, "PWR Vessel No 

B3.2.1 CEA shroud steel treated and growth/ Internals," and 

cast borated water Stress corrosion 

austenitic up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

stainless (644°F) irradiation- PWR primary water in EPRI TR-105714 

steel assisted stress 

I corrosion cracking 1

z 

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IV Reactor Vessel, Internals, and Reactor Coolant System 

B3. Reactor Vessel Internals (PWRI - Combustion Engine rina

z C 

m 

0 

-o 

03

( (.

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B3.2-b CEA Shroud Assemblies Stainless Chemically Crack initiation Chapter XI.M16, "PWR Vessel No 

B3.2.2 CEA shrouds bolts steel, treated and growth/ Internals," and 

Ni alloy borated water Stress corrosion 

up to 3400C cracking, primary Chapter XI.M2, "Water Chemistry," for 

(644°F) water stress PWR primary water in EPRI TR-105714 

corrosion 

cracking, 

irradiation

assisted stress 

corrosion cracking 

B3.2-c CEA shroud assemblies Stainless Chemically Changes in A plant-specific aging management Yes, plant 

B3.2.1 CEA shroud steel, treated dimensions/ program is to be evaluated. The specific 

B3.2.2 CEA shrouds bolts cast borated water Void swelling applicant is to provide a plant-specific 

austenitic up to 3400C AMP or participate in industry programs 

stainless (644-F) to investigate aging effects and 

steel, determine appropriate AMP. Otherwise, 

Ni alloy the applicant is to provide the basis for 

concluding that void swelling is not an 

issue for the component. 

B3.2-d CEA shroud assemblies Stainless Chemically Loss of material/ Chapter XI.M1, "ASME Section XI No 

B3.2.3 CEA shroud extension shaft steel treated Wear Inservice Inspection, Subsections IWB, 

guides borated water IWC, and IWD," for Class 1 components 

up to 3400C 

(6440F) 

B3.2-e CEA shroud assemblies Cast Chemically Loss of fracture Chapter XI.M13, "Thermal Aging and No 

B3.2.1 CEA shroud austenitic treated toughness/ Neutron Irradiation Embrittlement of Cast 

stainless borated water Thermal aging Austenitic Stainless Steel (CASS)" 

steel up to 3400C and neutron 

(644°F) irradiation 

neutron embrittlement, 

fluence of void swelling 

greater than 

1017 n/cm 2 

(E>1 MeV)

/
(

IV

(

Reactor Vessel, Internals, and Reactor Coolant System R.'4 RerPtnr Vpq_'eI Int~rnnlk (IWR• - Cnmhu~tinn IFnnin~nrina

(

z 

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B3.2-f CEA shroud assemblies Stainless Chemically/ Cumulative For components for which a fatigue Yes, 

B3.2.1 CEA shroud steel, treated fatigue damage/ analysis has been performed for the TLAA 

B3.2.2 CEA shrouds bolts cast borated water Fatigue 40-year period, fatigue is a time-limited 

austenitic up to 3400C aging analysis (TLAA) to be performed 

stainless (644-F) for the period of extended operation, 

steel, and, for Class 1 components, 

Ni alloy environmental effects on fatigue are to 

be addressed. See the Standard Review 

Plan, Section 4.3 "Metal Fatigue," for 

acceptable methods for meeting the . 

requirements of 10 CFR 54.21(c). 

B3.2-g CEA shroud assemblies Stainless Chemically Loss of preload/ Chapter XI.M1, "ASME Section Xl No 

B3.2.2 CEA shrouds bolts steel, treated Stress relaxation Inservice Inspection, Subsections IWB, 

Ni alloy borated water IWC, and IWD," for Class 1 components 

up to 3400C and 

(644°F) 

Chapter XI.M1 4, "Loose Part Monitoring" 

B3.3-a Core support barrel Stainless Chemically Crack initiation Chapter XI.M1 6, "PWR Vessel No 

B3.3.1 Core support barrel steel treated and growth/ Internals," and 

B3.3.2 Core support barrel upper borated water Stress corrosion 

flange up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

(6440 F) irradiation- PWR primary water in EPRI TR-1 05714 

assisted stress 

corrosion cracking ..... 

B3.3-b Core support barrel Stainless Chemically Changes in A plant-specific aging management Yes, plant 

B3.3.1 Core support barrel steel treated dimensions/ program is to be evaluated. The specific 

B3.3.2 Core support barrel upper borated water Void swelling applicant is to provide a plant-specific 

flange up to 3400C AMP or participate in industry programs 

(644°F) to investigate aging effects and 

determine appropriate AMP. Otherwise, 

the applicant is to provide the basis for 

concluding that void swelling is not an 

issue for the component.
IV Reactor Vessel, Internals, and Reactor Coolant System 

B3. Reactor Vessel Internals (PWRI - Combustion Enaine rina

z 

C 71 

m 

Go 

00 

0)

0 0>

K

Structure and/or Aging Effect! Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B3.3-a Core support barrel stainless Chemically' Loss of fracture Chapter XI.M16, "PWR Vessel Internals" No 

B3.3.1 Core support barrel steel Treated toughness/ 

B3.3.2 Core support barrel upper borated water Neutron irradiation 

flange up to 3400C embrittlement, 

(644°F) void swelling 

neutron 

fluence 

>1017 n/cm 2 

_____ _______ ~~~(E >1 MeV) _ _ _ _ _ ___ _ _ _ 

B3.3-b Core support barrel Stainless Chemically Loss of material/ Chapter XI.M1, "ASME Section Xl No 

B3.3.2 Core support barrel upper steel treated Wear Inservice Inspection, Subsections IWB, 

flange borated water IWC, and IWD," for Class 1 components 

B3.3.3 Core support barrel alignment up to 3400C 

I keys (6440F) 

B3.4-a Core shroud assembly Stainless Chemically Crack initiation Chapter XI.M1 6, "PWR Vessel No 

B3.4.1 Core shroud assembly steel, treated and growth/ Internals," and 

B3.4.3 Core shroud tie rods (core cast borated water Stress corrosion 

support plate attached by austenitic up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

welds in later plants) stainless (644°F) irradiation- PWR primary water in EPRI TR-1 05714 

steel assisted stress 

corrosion cracking 

B3.4-b Core shroud assembly Stainless Chemically Changes in A plant-specific aging management Yes, plant 

B3.4.1 Core shroud assembly steel, treated dimensions/ program is to be evaluated. The specific 

B3.4.3 Core shroud tie rods (core cast borated water Void swelling applicant is to provide a plant-specific 

support plate attached by austenitic up to 3400C AMP or participate in industry programs 

welds in later plants) stainless (644-F) to investigate aging effects and 

steel, determine appropriate AMP. Otherwise, 

Ni alloy the applicant is to provide the basis for 

concluding that void swelling is not an 

issue for the component.
IV

R 

Reactor Vessel, Internals, and Reactor Coolant System 

B3. Reactor Vessel Internals (P'WR• - Combu-•tinn F~ninlnAxinn

(

9 

03 1P 0 

w3

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation B3.4-c Core shroud assembly Stainless Chemically Loss of fracture Chapter XI.M16, "PWR Vessel Internals" No B3.4.1 Core shroud assembly steel treated toughness/ B3.4.3 Core shroud tie rods (core borated water Neutron irradiation 

support plate attached by up to 3400C embrittlement, welds in later plants) void swelling 

fluence 

>1017 n/cm2 

I (E >1 MeV) B3.4-d Core shroud assembly Stainless Chemically Cumulative For components for which a fatigue Yes, B3.4.1 Core shroud assembly steel, treated fatigue damage/ analysis has been performed for the TLAA B3.4.2 Core shroud assembly bolts Ni alloy borated water Fatigue 40-year period, fatigue is a time-limited B3.4.3 Core shroud tie rods (bolts) up to 3400C aging analysis (TLAA) to be performed 

(6440F) for the period of extended operation, and, for Class 1 components, 

environmental effects on fatigue are to be addressed. See the Standard Review 

Plan, Section 4.3 "Metal Fatigue," for 

acceptable methods for meeting the 

requirements of 10 CFR 54.21(c). B3.4-e Core shroud assembly Stainless Chemically Crack initiation Chapter XI.M16, "PWR Vessel No B3.4.2 Core shroud assembly bolts steel, treated and growth/ Internals," and 

(later plants are welded) Ni alloy borated water Stress corrosion 

up to 3400C cracking, primary Chapter XI.M2, "Water Chemistry," for 

(644°F) water stress PWR primary water in EPRI TR-1 05714 

corrosion 

cracking, 

irradiation

assisted stress 

I corrosion cracking 1

z C 

m 

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z 

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m 

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00

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0

K

IV Reactor Vessel, Internals, and Reactor Coolant System 

B3. Reactor Vessel Internals (PWR) - Combustion Engine ring 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B3.4-f Core shroud assembly Stainless Chemically Changes in A plant-specific aging management Yes, plant B3.4.2 Core shroud assembly bolts steel, treated dimensions/ program is to be evaluated. The specific 

(later plants are welded) Ni alloy borated water Void swelling applicant is to provide a plant-specific 

up to 3400C AMP or participate in industry programs 

(644°F) to investigate aging effects and 

determine appropriate AMP. Otherwise, 

the applicant is to provide the basis for 

.concluding that void swelling is not an 

issue for the component. B3.4-g Core shroud assembly Stainless Chemically Loss of fracture Chapter XI.M16, "PWR Vessel Internals" No 

B3.4.2 Core shroud assembly bolts steel, treated toughness/ 

(later plants are welded) Ni alloy borated water Neutron irradiation 

up to 3400C embrittlement, 

void swelling 

fluence 

>1017 n/cm2 

(E >1 MeV) 

B3.4-h Core shroud assembly Stainless Chemically Loss of preload/ Chapter XI.M1, "ASME Section Xi No 

B3.4.2 Core shroud assembly bolts steel, treated Stress relaxation Inservice Inspection, Subsections IWB, 

B3.4.3 Core shroud tie rods Ni alloy borated water IWC, and IWD," for Class 1 components 

up to 340°C and 

(644°F) 

Chapter XI.M14, "Loose Part Monitoring" B3.5-a Lower internal assembly Stainless Chemically Crack'initiation Chapter XI.M16, "PWR Vessel No 

B3.5.1 Core support plate steel treated and growth/ Internals," and 

B3.5.3 Lower support structure beam borated water Stress corrosion 

assemblies up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

B3.5.4 Core support column (644°F) irradiation- PWR primary water in EPRI TR-1 05714 

B3.5.6 Core support barrel snubber assisted stress 

I assemblies I corrosion cracking I I
(

IV Reactor Vessel, Internals, and Reactor Coolant System BS. Reactor Vessel Internals 1P WR• - Combustion Enalnee rina

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B3.5-b Lower internal Assembly Stainless Chemically Crack Initiation Chapter XI.M16, "PWR Vessel No 

B3.5.2 Fuel alignment pins steel, treated and growth/ Internals," and 

B3.5.5 Core support column bolts Ni alloy borated water Stress corrosion 

up to 3400C cracking, primary Chapter XI.M2, "Water Chemistry," for 

(6440F) water stress PWR primary water in EPRI TR-1 05714 

corrosion 

cracking, 

irradiation

assisted stress 

corrosion cracking 

B3.5-c Lower internal assembly Stainless Chemically Changes in A plant-specific aging management Yes, plant 

B3.5.1 Core support plate steel, treated dimensions/ program is to be evaluated. The specific 

B3.5.2 Fuel alignment pins Ni alloy borated water Void swelling applicant is to provide a plant-specific 

B3.5.3 Lower support structure beam (pins/ up to 3400C AMP or participate in industry programs 

assemblies bolts), cast (6440F) to investigate aging effects and 

B3.5.4 Core support column austenitic determine appropriate AMP. Otherwise, 

B3.5.5 Core support column bolts stainless the applicant is to provide the basis for 

B3.5.6 Core support barrel snubber steel concluding that void swelling is not an 

assemblies (support issue for the component. column) 

B3.5-d Lower internal assembly Stain'less Chemically Loss of fracture Chapter XI.M16, "PWR Vessel Internals" No 

B3.5.1 Core support plate steel, treated toughness/ 

B3.5.2 Fuel alignment pins Ni alloy borated water Neutron irradiation 

B3.5.3 Lower support structure beam (pins/bolts) up to 3400C embrittlement, 

assemblies (644°F) void swelling 

B3.5.5 Core support column bolts 

B3.5.6 Core support barrel snubber neutron 

assemblies fluence 

>1017 n/cm2 

(E >1 MeV) 

B3.5-e Lower internal assembly Stainless Chemically Loss of material/ Chapter XI.M1, "ASME Section Xl No 

B3.5.2 Fuel alignment pins steel, treated Wear Inservice Inspection, Subsections IWB, 

B3.5.6 Core support barrel snubber Ni alloy borated water IWC, and IWD," for Class 1 components 

assemblies (pins) up to 340TC 

I_____ 1(644°F) I I
IV Reactor Vessel, Internals, and Reactor Coolant System R2_ Rc'RP.rtnr Vcm~l IntmrnnIk (P WR• - Cnomhus~tion Enalnae=rlna

z 

C 

03 

w 

CA 

0

( K

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B3.5-f Lower internal assembly Cast Chemically Loss of fracture Chapter XI.M1 3, "Thermal Aging and No 

B3.5.4 Core support column austenitic treated toughness/ Neutron Irradiation Embrittlement of Cast 

stainless borated water Thermal aging Austenitic Stainless Steel (CASS)" 

steel up to 340°C and neutron 

(644°F) irradiation 

embrittlement, 

void swelling 

B3.5-g Lower internal assembly Stainless Chemically Cumulative For components for which a fatigue Yes, 

B3.5.1 Core support plate steel, treated fatigue damage/ analysis has been performed for the TLAA 

B3.5.2 Fuel alignment pins Ni alloy borated water Fatigue 40-year period, fatigue is a time-limited 

B3.5.3 Lower support structure beam (pins/ up to 3400C aging analysis (TLAA) to be performed 

assemblies bolts), cast (6440F) for the period of extended operation, 

B3.5.4 Core support column austenitic and, for Class 1 components, 

B3.5.5 Core support column bolts stainless environmental effects on fatigue are to 

B3.5.6 Core support barrel snubber steel be addressed. See the Standard Review 

assemblies (support Plan, Section 4.3 "Metal Fatigue," for 

column) acceptable methods for meeting the 

requirements of 10 CFR 54.21(c).

0> 

0
B4 REACTOR VESSEL INTERNALS (PWR) - BABCOCK AND WILCOX 

B4.1 Plenum Cover and Plenum Cylinder 

B4.1.1 Plenum Cover Assembly 

B4.1.2 Plenum Cylinder 

B4.1.3 Reinforcing Plates 

B4.1.4 Top Flange-to-Cover Bolts 

B4.1.5 Bottom Flange-to-Upper Grid Screws 

B4.2 Upper Grid Assembly 

B4.2.1 Upper Grid Rib Section 

B4.2.2 Upper Grid Ring Forging 

B4.2.3 Fuel Assembly Support Pads 

B4.2.4 Plenum Rib Pads 

B4.2.5 Rib-to-Ring Screws 

B4.3 Control Rod Guide Tube (CRGT) Assembly 

B4.3.1 CRGT Pipe and Flange 

B4.3.2 CRGT Spacer Casting 

B4.3.3 CRGT Spacer Screws 

B4.3.4 Flange-to-Upper Grid Screws 

B4.3.5 CRGT Rod Guide Tubes 

B4.3.6 CRGT Rod Guide Sectors 

B4.4 Core Support Shield Assembly 

B4.4.1 Core Support Shield Cylinder (Top and Bottom Flange) 

B4.4.2 Core Support Shield-to-Core Barrel Bolts 

B4.4.3 Outlet and Vent Valve Nozzles 

B4.4.4 Vent Valve Body and Retaining Ring 

B4.4.5 Vent Valve Assembly Locking Device 

B4.5 Core Barrel Assembly 

B4.5.1 Core Barrel Cylinder (Top and Bottom Flange) 

B4.5.2 Lower Internals Assembly-to-Core Barrel Bolts 

B4.5.3 Core Barrel-to-Thermal Shield Bolts 

B4.5.4 Baffle Plates and Formers 

B4.5.5 Baffle/Former Bolts and Screws 

B4.6 Lower Grid (LG) Assembly 

B4.6.1 Lower Grid Rib Section 

B4.6.2 Fuel Assembly Support Pads 

B4.6.3 Lower Grid Rib-to-Shell Forging Screws 

B4.6.4 Lower Grid Flow Distributor Plate 

B4.6.5 Orifice Plugs 

B4.6.6 Lower Grid and Shell Forgings

April 2001 IV 134-1 NUREG-1801
B4.6.7 Lower Internals Assembly-to-Thermal Shield Bolts 

B4.6.8 Guide Blocks and Bolts 

B4.6.9 Shock Pads and Bolts 

B4.6.1 0 Support Post Pipes 

B4.6.11 Incore Guide Tube Spider Castings 

B4.7 Flow Distributor Assembly 

B4.7.1 Flow Distributor Head and Flange 

B4.7.2 Shell Forging-to-Flow Distributor Bolts 

B4.7.3 Incore Guide Support Plate 

B4.7.4 Clamping Ring 

B4.8 Thermal Shield

NUREG-1801 IV 134-2 April 2001
B4. REACTOR VESSEL INTERNALS (PWR) - BABCOCK AND WILCOX 

Systems, Structures, and Components 

This section comprises 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 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. 

System Interfaces 

The systems that interface with the reactor vessel internals include the reactor pressure vessel 

(IV.A2).

April 2001 IV B4-3 NUREG-1 801
z 

C 

m 

O 

co 

0 

1 

<~. 

0J 

0

( K.

IV Reactor Vessel, Internals, and Reactor Coolant System B4. Reactor Vessel Internals (PWR) - Babcock and Wilcox 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.1-a Plenum cover and plenum Type 304 Chemically Crack initiation Chapter XI.M16, "PWR Vessel No cylinder stainless treated and growth/ Internals," and 

B4.1.1 Plenum cover assembly steel, borated water Stress corrosion 

B4.1.2 Plenum cylinder plenum up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for B4.1.3 Reinforcing plates cylinder: (644°F) irradiation- PWR primary water in EPRI TR-105714 

type 304 assisted stress 

forging corrosion cracking B 4.1-b Plenum cover and plenum Gr. B-8 Chemically Crack initiation Chapter XI.M16, "PWR Vessel No 

cylinder stainless treated and growth/ Internals," and 

B4.1.4 Top flange-to-cover bolts steel borated water Stress corrosion 

B4.1.5 Bottom flange-to-upper grid up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

screws (644°F) irradiation- PWR primary water in EPRI TR-1 05714 

assisted stress 

corrosion cracking B4.1-c Plenum cover and plenum Type 304 Chemically Changes in A plant-specific aging management Yes, plant cylinder stainless treated dimensions/ program is to be evaluated. The specific B4.1.1 Plenum cover assembly steel, borated water Void swelling applicant is to provide a plant-specific B4.1.2 Plenum cylinder bolts: up to 3400C AMP or participate in industry programs B4.1.3 Reinforcing plates Gr. B-8 (644-F) to investigate aging effects and B4.1.4 Top flange-to-cover bolts stainless determine appropriate AMP. Otherwise, B4.1.5 Bottom flange-to-upper grid steel the applicant is to provide the basis for 

screws concluding that void swelling is not an 

issue for the component. B4.1 -d Plenum cover and plenum Type 304 Chemically Cumulative For components for which a fatigue Yes, cylinder stainless treated fatigue damage/ analysis has been performed for the TLAA B4.1.1 Plenum cover assembly steel, borated water Fatigue 40-year period, fatigue is a time-limited B4.1.2 Plenum cylinder plenum up to 3400C aging analysis (TLAA) to be performed B4.1.3 Reinforcing plates cylinder: (644°F) for the period of extended operation, B4.1.4 Top flange-to-cover bolts type 304 and, for Class 1 components, B4.1.5 Bottom flange-to-upper grid forging environmental effects on fatigue are to 

screws be addressed. See the Standard Review 

Plan, Section 4.3 "Metal Fatigue," for 

acceptable methods for meeting the 

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

IV Reactor Vessel, Internals, and Reactor Coolant System 

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

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.2-a Upper grid assembly Type 304 Chemically Crack' initiation Chapter XI.M16, "PWR Vessel No 

84.2.1 Upper grid rib section stainless treated and growth/ Internals," and 

B4.2.2 Upper grid ring forging steel borated water Stress corrosion 

B4.2.3 Fuel assembly support pads up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

B4.2.4 Plenum rib pads (644°F) irradiation- PWR primary water in EPRI TR-1 05714 

assisted stress 

corrosion cracking 

B4.2-b Upper grid assembly Gr. B-8 Chemically Crack initiation Chapter XI.M1 6, "PWR Vessel No 

B4.2.5 Rib- to-ring screws stainless treated and growth/ Internals," and 

steel borated water Stress corrosion 

up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

(644°F) irradiation- PWR primary water in EPRI TR-105714 

assisted stress 

corrosion cracking 

84.2-c Upper grid assembly Type 304 Chemically Changes in A plant-specific aging management Yes, plant 

B4.2.1 Upper grid rib section stainless treated dimensions/ program is to be evaluated. The specific 

84.2.2 Upper grid ring forging steel, borated water Void swelling applicant is to provide a plant-specific 

B4.2.3 Fuel assembly support pads screws: up to 3400C AMP or participate in industry programs 

84.2.4 Plenum rib pads Gr. B-8 (644°F) to investigate aging effects and 

84.2.5 Rib-to-ring screws stainless determine appropriate AMP. Otherwise, 

steel the applicant is to provide the basis for 

concluding that void swelling is not an 

issue for the component. 

B4.2-d Upper grid assembly Type 304 Chemically Cumulative For components for which a fatigue Yes, 

B4.2.1 Upper grid rib section stainless treated fatigue damage/ analysis has been performed for the TLAA 

84.2.2 Upper grid ring forging steel borated water Fatigue 40-year period, fatigue is a time-limited 

84.2.3 Fuel assembly support pads up to 3400C aging analysis (TLAA) to be performed 

84.2.4 Plenum rib pads (644°F) for the period of extended operation, 

84.2.5 Rib-to-ring screws and, for Class 1 components, 

environmental effects on fatigue are to 

be addressed. See the Standard Review 

Plan, Section 4.3 "Metal Fatigue," for 

acceptable methods for meeting the 

requirements of 10 CFR 54.21 (c).
IV Reactor Vessel, Internals, and Reactor Coolant System B4. Reactor Vessel Internals (IPWR• - Babcock and Wilcox

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Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.2-e Upper grid assembly Type 304 Chemicafly Loss of fracture Chapter XI.M16, "PWR Vessel Internals" No 

B4.2.1 Upper grid rib section stainless treated toughness/ B4.2.2 Upper grid ring forging steel, borated water Neutron irradiation 

B4.2.3 Fuel assembly support pads screws: up to 3400C embrittlement, 

B4.2.4 Plenum rib pads Gr. B-8 (644°F) void swelling 

B4.2.5 Rib-to-ring screws stainless 

steel 

B4.2-f Upper grid assembly Type 304 Chemically Loss of material/ Chapter XI.M1, "ASME Section Xl No 

B4.2.3 Fuel assembly support pads stainless treated Wear Inservice Inspection, Subsections IWB, B4.2.4 Plenum rib pads steel borated water IWC, and IWD," for Class 1 components 

up to 3400C 

(6440F) B4.3-a Control rod guide tube (CRGT) Pipe and Chemically Crack initiation Chapter Xl. M 16, "PWR Vessel No 

assembly flange: treated and growth/ Internals," and 

84.3.1 CRGT pipe and flange type 304 borated water Stress corrosion 

B4.3.2 CRGT spacer casting stainless up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

B4.3.5 CRGT rod guide tubes steel, (6440F) irradiation- PWR primary water in EPRI TR-1 05714 

B4.3.6 CRGT rod guide sectors spacer assisted stress 

casting: corrosion cracking 

CF-3M, 

guide 

tubes and 

sectors: 

type 304L 

84.3-b Control rod guide tube (CRGT) Gr. B-8 Chemically Crack initiation Chapter XI.M1 6, "PWR Vessel No 

assembly stainless treated and growth/ Internals," and 

84.3.3 CRGT spacer screws steel borated water Stress corrosion 

84.3.4 Flange-to-upper grid screws up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

(6440F) irradiation- PWR primary water in EPRI TR-1 05714 

assisted stress 

I corrosion cracking I
( ( (

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0

IV Reactor Vessel, Internals, and Reactor Coolant System B4. Reactor Vessel Internals (PWR) - Babcock and Wilcox 

Structure and/or Aging Effect! Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.3-c Control rod guide tube (CRGT) Pipe and Chemically Changes in A plant-specific aging management Yes, plant assembly flange: treated dimensions/ program is to be evaluated. The specific B4.3.1 CRGT pipe and flange type 304 borated water Void swelling applicant is to provide a plant-specific B4.3.2 CRGT spacer casting stainless up to 3400C AMP or participate in industry programs 84.3.3 CRGT spacer screws steel; (644°F) to investigate aging effects and B4.3.4 Flange-to-upper grid screws spacer determine appropriate AMP. Otherwise, B4.3.5 CRGT rod guide tubes casting: the applicant is to provide the basis for B4.3.6 CRGT rod guide sectors CF-3M; concluding that void swelling is not an 

guide issue for the component. 

tubes and 

sectors: 

type 304L; 

screws: 

Gr. B-8 

stainless 

steel 

14.3-d Control rod guide tube (CRGT) Cast Chemically Loss of fracture Chapter XI.M13, "Thermal Aging and No assembly austenitic treated toughness/ Neutron Irradiation Embrittlement of Cast 84.3.2 CRGT spacer casting stainless borated water Thermal aging Austenitic Stainless Steel (CASS)" 

steel up to 3400C and neutron 

CF-3M (644°F) irradiation 

embrittlement, 

neutron void swelling 

fluence 

>1017 n/cm2 

(E >1 MeV) 

B4.3-e Control rod guide tube (CRGT) Gr. B-8 Chemically Loss of preload/ Chapter XI.M1, "ASME Section Xl No 

assembly stainless treated Stress relaxation Inservice Inspection, Subsections IWB, B4.3.4 Flange-to-upper grid screws steel borated water IWC, and IWD," for Class 1 components 

up to 3400C and 

(644-F) 

Chapter XI.M14, "Loose Part Monitoring" z 

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Co 00
Z 

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IV Reactor Vessel, Internals, and Reactor Coolant System 

B4. Reactor Vessel Internals (FWR) - Babcock and Wilcox 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.3-f Control rod guide tube (CRGT) Pipe and Chemically Cumulative For components for which a fatigue Yes, 

assembly flange: treated fatigue damage/ analysis has been performed for the TLAA 

B4.3.1 CRGT pipe and flange type 304 borated water Fatigue 40-year period, fatigue is a time-limited 

B4.3.2 CRGT spacer casting stainless up to 3400C aging analysis (TLAA) to be performed 

B4.3.3 CRGT spacer screws steel; (644°F) for the period of extended operation, 

B4.3.4 Flange-to-upper grid screws spacer and, for Class 1 components, 

84.3.5 CRGT rod guide tubes casting: environmental effects on fatigue are to 

B4.3.6 CRGT rod guide sectors CF-3M; be addressed. See the Standard Review 

guide Plan, Section 4.3 "Metal Fatigue," for 

tubes and acceptable methods for meeting the 

sectors: requirements of 10 CFR 54.21 (c). 

type 304L; 

screws: 

Gr. B-8 

stainless 

steel 

B4.4-a Core support shield assembly Shield Chemically Crack initiation Chapter XI.M1 6, "PWR Vessel No 

84.4.1 Core support shield cylinder cylinder: treated and growth/ Internals," and 

(top and bottom flange) Type 304; borated water Stress corrosion 

84.4.3 Outlet and vent valve (VV) nozzles: up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

nozzles stainless (644°F) irradiation- PWR primary water in EPRI TR-1 05714 

B4.4.4 VV body and retaining ring steel assisted stress 

forging, corrosion cracking 

CF-8; 

VV body: 

CF-8; 

VV ring: 

type 15

5PH 1forging I
IV Reactor Vessel, Internals, and Reactor Coolant System B4. Reactor Vessel Internals (FPWR) - Babcock and Wilcox N> 

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4,4-b Core support shield assembly Bolts: Chemically Crack initiation Chapter XI.M16, "PWR Vessel No 

B4.4.2 Core support shield-to-core Gr. 660 treated and growth/ Internals," and 

barrel bolts (A-286), borated water Stress corrosion 

B4.4.5 VV assembly locking device Gr. 688 up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

(X-750); (6440F) irradiation- PWR primary water in EPRI TR-105714 

VV locking assisted stress 

device: corrosion cracking 

Gr. B-8 or 

B-8M 

B4.4-c Core support shield assembly Shield Chemically Changes in A plant-specific aging management Yes, plant B4.4.1 Core support shield cylinder cylinder: treated dimensions/ program is to be evaluated. The specific (top and bottom flange) type 304; borated water Void swelling applicant is to provide a plant-specific B4.4.2 Core support shield-to-core bolts: up to 3400

C AMP or participate in industry programs barrel bolts A-286, (644-F) to investigate aging effects and B4.4.4 VV retaining ring X-750; determine appropriate AMP. Otherwise, B4.4.5 VV assembly locking device VV ring: the applicant is to provide the basis for 

type concluding that void swelling is not an 

15-5PH issue for the component. 

forging; 

locking 

device: 

Gr. B-8 or 

B-8M

z 

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IV Reactor Vessel, Internals, and Reactor Coolant System B4. Reactor Vessel Internals (PWR) - Babcock and Wilcox 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.4-d Core support shield assembly Shield Chemically Loss of fracture Chapter XL.M16, "PWR Vessel Internals" No 

B4.4.1 Core support shield cylinder cylinder: treated toughness/ 

(top and bottom flange) type 304; borated water Neutron irradiation 

B4.4.2 Core support shield-to-core bolts: up to 3400C embrittlement, 

barrel bolts A-286, (644°F) void swelling 

B4.4.3 Outlet and vent valve (VV) X-750; 

nozzles nozzles: neutron 

B4.4.5 VV assembly locking device stainless fluence 

steel >1017 n/cm 2 

forging; (E >1 MeV) 

VV ring: 

type 

15-5PH 

forging; 

locking 

device: 

Gr. B-8 or 

3B-8M
IV

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Reactor Vessel, Internals, and Reactor Coolant System 

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Structure and/or Aging Effect/ Further 

item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.4-e Core support shield assembly Shield Chemically Cumulative For components for which a fatigue Yes, 

B4.4.1 Core support shield cylinder cylinder: treated fatigue damage/ analysis has been performed for the TLAA 

(top and bottom flange) type 304; borated water Fatigue 40-year period, fatigue is a time-limited 

B4.4.2 Core support shield-to-core bolts: up to 3400C aging analysis (TLAA) to be performed 

barrel bolts A-286, (6440F) for the period of extended operation, 

B4.4.3 Outlet and vent valve (VV) X-750; and, for Class 1 components, 

nozzles nozzles: environmental effects on fatigue are to 

B4.4.4 VV body and retaining ring stainless be addressed. See the Standard Review 

steel Plan, Section 4.3 "Metal Fatigue," for 

forging, acceptable methods for meeting the 

CF-8; requirements of 10 CFR 54.21 (c). 

VV body: 

CF-8; 

VV ring: 

type 

15-5PH 

forging; 

locking 

device: 

Gr. B-8 or 

B-8M 

B4.4-f Core support shield assembly Top flange: Chemically Loss of material/ Chapter XI.M1, "ASME Section XI No 

B4.4.1 Core support shield cylinder type 304, treated Wear Inservice Inspection, Subsections IWB, 

(top flange) VV locking borated water IWC, and IWD," for Class 1 components 

B4.4.5 VV assembly locking device device: up to 3400C 

Gr. B-8 or (6440F) 

B-8M 

B4.4-g Core support shield assembly Cast Chemically Loss of fracture Chapter XI.M1 3, "Thermal Aging and No 

B4.4.3 Outlet and vent valve nozzles austenitic treated toughness/ Neutron Irradiation Embrittlement of Cast 

B4.4.4 VV body and retaining ring stainless borated water Thermal aging Austenitic Stainless Steel (CASS)" 

steel up to 3400C and neutron 

CF-8 irradiation 

fluence embrittlement, 

>10 17 n/cm2 void swelling 

I (E >1 MeV) _

Z 

C 

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IV Reactor Vessel, Internals, and Reactor Coolant System B4. Reactor Vessel Internals (! WR• - Babcock and Wilcox

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.4-h Core support shield assembly Gr. 660 Chemically Loss of preload/ Chapter XI.M1, "ASME Section Xl No 

B4.4.2 Core support shield-to-core (A-286), treated Stress relaxation Inservice Inspection, Subsections IWB, barrel bolts Gr. 688 borated water IWC, and IWD," for Class 1 components 

(X-750) up to 3400C and 

(644°F) _Chapter XI.M14, "Loose Part Monitoring" 

B4.5-a Core barrel assembly CB Chemically Crack initiation Chapter XI.M1 6, "PWR Vessel No 

B4.5.1 Core barrel cylinder (top and cylinder: treated and growth/ Internals," and 

bottom flange) type 304 borated water Stress corrosion 

B4.5.4 Baffle plates and formers forging, up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

baffle (644°F) irradiation- PWR primary water in EPRI TR-105714 

plates and assisted stress 

formers: corrosion cracking 

type 304 

stainless 

steel 

B4.5-b Core barrel assembly A-286, Chemically Crack initiation Chapter XI.M16, "PWR Vessel No 

B4.5.2 Lower internals assembly-to- X-750 treated and growth/ Internals," and 

core barrel bolts borated water Stress corrosion 

B4.5.3 Core barrel-to-thermal shield up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

bolts (644°F) irradiation- PWR primary water in EPRI TR-1 05714 

assisted stress 

corrosion cracking B4.5-c Core barrel assembly CB Chemically Changes in A plant-specific aging management Yes, plant B4.5.1 Core barrel cylinder (top and cylinder: treated dimensions/ program is to be evaluated. The specific bottom flange) type 304 borated water Void swelling applicant is to provide a plant-specific B4.5.2 Lower internals assembly-to- forging; up to 3400C AMP or participate in industry programs 

core barrel bolts CB bolts: (644°F) to investigate aging effects and 

B4.5.3 Core barrel-to-thermal shield A-286, determine appropriate AMP. Otherwise, 

bolts X-750; the applicant is to provide the basis for 

B4.5.4 Baffle plates and formers baffle concluding that void swelling is not an 

plates and issue for the component. 

formers: 

type 304 

stainless 

steel
IV Reactor Vessel, Internals, and Reactor Coolant System B4. Reactor Vessel Internals (I WR• - Babcock and Wilcox

Ko 

0 

¢0 

9

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.5-d Core barrel assembly CB Chemically Loss of fracture Chapter XI.M16, "PWR Vessel Internals" No 

B4.5.1 Core barrel cylinder (top and cylinder: treated toughness/ 

bottom flange) type 304 borated water Neutron irradiation 

B4.5.2 Lower internals assembly-to- forging; up to 3400C embrittlement, 

core barrel bolts CB bolts: (644°F) void swelling B4.5.3 Core barrel-to-thermal shield A-286, neutron 

bolts X-750; fluence of 

B4.5.4 Baffle plates and formers baffle greater than 

plates and 1017 n/cm 2 

formers: (E>1 MeV) 

type 304 

stainless 

steel 

B4.5-e Core barrel assembly A-286, Chemically Loss of preload/ Chapter XI.M1, "ASME Section Xl No 

B4.5.2 Lower internals assembly-to- X-750 treated Stress relaxation Inservice Inspection, Subsections IWB, 

core barrel bolts borated water IWC, and IWD," for Class 1 components B4.5.3 Core barrel-to-thermal shield up to 3400C and 

bolts (644°F) 

I_ I_ I_ I_ Chapter XI.M14, "Loose Part Monitoring" I

z 

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m G) i 

Co 

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OJ

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.5-f Core barrel assembly CB Chemically Cumulative For components for which a fatigue Yes, B4.5.1 Core barrel cylinder (top and cylinder: treated fatigue damage/ analysis has been performed for the TLAA 

bottom flange) type 304 borated water Fatigue 40-year period, fatigue is a time-limited 

B4.5.2 Lower internals assembly-to- forging; up to 3400C aging analysis (TLAA) to be performed 

core barrel bolts CB bolts: (644°F) for the period of extended operation, B4.5.3 Core barrel-to-thermal shield A-286, and, for Class 1 components, bolts X-750; environmental effects on fatigue are to 

B4.5.4 Baffle plates and formers baffle be addressed. See the Standard Review 

B4.5.5 Baffle/former bolts and plates and Plan, Section 4.3 "Metal Fatigue," for 

screws formers: acceptable methods for meeting the 

type 304 requirements of 10 CFR 54.21 (c). 

stainless 

steel; 

baffle/ 

former 

bolts and 

screws: 

Gr. B-8 

stainless 

steel

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0 

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IV Reactor Vessel, Internals, and Reactor Coolant System 

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

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.5-g Core barrel assembly Gr. B-8 Chemically Crack initiation A plant-specific aging management Yes, plant B4.5.5 Baffle/former bolts and stainless treated and growth/ program is to be evaluated. Historically specific 

screws steel borated water Stress corrosion the VT-3 visual examinations have not 

up to 3400C cracking, identified baffle/former bolt cracking (644°F) irradiation- because cracking occurs at the juncture 

assisted stress of the bolt head and shank, which is not 

corrosion cracking accessible for visual inspection. 

However, recent UT examinations of the 

baffle/former bolts have identified 

cracking in several plants. The industry 

is currently addressing the issue of baffle 

bolt cracking in the PWR Materials 

Reliability Project, Issues Task Group (ITG) activities to determine, develop, 

and implement the necessary steps and 

plans to manage the applicable aging effects on a plant-specific basis. 

B4.5-h Core barrel assembly Gr. B-8 Chemically Changes in A plant-specific aging management Yes, plant B4.5.5 Baffle/former bolts and stainless treated dimensions/ program is to be evaluated. The specific 

screws steel borated water Void swelling applicant is to provide a plant-specific 

up to 3400C AMP or participate in industry programs 

(644°F) to investigate aging effects and 

determine appropriate AMP. Otherwise, 

the applicant is to provide the basis for 

concluding that void swelling is not an 

issue for the component. B4.5-i Core barrel assembly Gr. B-8 Chemically Loss of fracture A plant-specific aging management Yes, plant B4.5.5 Baffle/former bolts and stainless treated toughness/ program is to be evaluated, specific 

screws steel borated water Neutron irradiation 

up to 3400C embrittlement, 

void swelling 

fluence 

>1017 n/cm 2 

(E >1 MeV)
z 

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IV Reactor Vessel, Internals, and Reactor Coolant System 

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

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.5-j Core barrel assembly Gr. B-8 Chemically Loss of preload/ A plant-specific aging management Yes, plant B4.5.5 Baffle/former bolts and stainless treated Stress relaxation program is to be evaluated, specific 

screws steel borated water 

up to 3400C Visual inspection (VT-3) is to be 

(644°F) augmented to detect relevant conditions 

of stress relaxation because only the 

heads of the baffle/former bolts are 

visible, and a plant-specific aging 

management program is thus required. B4.6-a Lower grid assembly Type 304 Chemically Crack initiation Chapter XI.M1 6, "PWR Vessel No 

B4.6.1 Lower grid rib section stainless treated and growth/ Internals," and 

B4.6.2 Fuel assembly support pads steel, borated water Stress corrosion 

B4.6.4 Lower grid flow dist. plate cast up to 340°C cracking, Chapter XI.M2, "Water Chemistry," for 

B4.6.5 Orifice plugs austenitic (6440F) irradiation- PWR primary water in EPRI TR-105714 

B4.6.6 Lower grid and shell forgings stainless assisted stress 

B4.6.8 Guide blocks steel corrosion cracking 

B4.6.9 Shock pads (CASS) 

B4.6.10 Support post pipes 

B4.6.11 Incore guide tube spider 

castings 

B4.6-b Lower grid assembly Lower Chemically Crack initiation Chapter XI.M1 6, "PWR Vessel No 

B4.6.3 Lower grid rib-to-shell forging internal treated and growth/ Internals," and 

screws assembly- borated water Stress corrosion 

84.6.7 Lower internals assembly-to- to-thermal up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

thermal shield bolts shield (644°F) irradiation- PWR primary water in EPRI TR-1 05714 

B4.6.8 Guide blocks and bolts bolts: A- assisted stress 

B4.6.9 Shock pads and bolts 286, corrosion cracking 

X-750; 

Other bolts 

and 

screws: 

Gr. B-8 

stainless 

steel
IV Reactor Vessel, Internals, and Reactor Coolant System B4. Reactor Vessel Internals (PWR) - Babcock and Wilcox

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0O 

0

(

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.6-c Lower grid assembly Lower Chemically Changes in A plant-specific aging management Yes, plant B4.6.1 Lower grid rib section internals treated dimensions/ program is to be evaluated, specific B4.6.2 Fuel assembly support pads assembly- borated water Void swelling B4.6.3 Lower grid rib-to-shell forging to-thermal up to 3400C The applicant is to provide a plant

screws shield (6440F) specific AMP or participate in industry 84.6.4 Lower grid flow dist. plate bolts: programs to investigate aging effects 

B4.6.5 Orifice plugs A-286, and determine appropriate AMP. 

84.6.6 Lower grid and shell forgings X-750; Otherwise, the applicant is to provide the B4.6.7 Lower internals assembly-to- other bolts basis for concluding that void swelling is 

thermal shield bolts and not an issue for the component. B4.6.8 Guide blocks and bolts screws: 

B4.6.9 Shock pads and bolts Gr. B-8 

B4.6.10 Support post pipes stainless 

B4.6.11 Incore guide tube spider steel; 

castings spider 

castings: 

cast 

austenitic 

stainless 

steel

z C 

m 

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Reactor Vessel, Internals, and Reactor Coolant System B4. Reactor Vaaaol Internnls (P WRI - Bnbcoek and Wilcox

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m 

co 

0

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.6-d Lower grid assembly Type 304 Chemically Loss of fracture Chapter XI.M16, "PWR Vessel Internals" No 

B4.6.1 Lower grid rib section stainless treated toughness/ 

B4.6.2 Fuel assembly support pads steel, borated water Neutron irradiation 

B4.6.3 Lower grid rib-to-shell forging lower up to 3400C embrittlement, 

screws internals (644-F) void swelling 

B4.6.4 Lower grid flow dist. plate assembly

B4.6.5 Orifice plugs to-thermal neutron 

B4.6.6 Lower grid and shell forgings shield fluence 

B4.6.7 Lower internals assembly-to- bolts: >1017 n/cm2 

thermal shield bolts A-286, (E >1 MeV) 

B4.6.8 Guide blocks and bolts X-750; 

B4.6.9 Shock pads and bolts other bolts 

B4.6.10 Support post pipes and 

screws: 

Gr. B-8 

stainless 

steel 

B4.6-e Lower grid assembly Cast Chemically Loss of fracture Chapter XI.M13, "Thermal Aging and No 

B4.6.11 Incore guide tube spider austenitic treated toughness/ Neutron Irradiation Embrittlement of Cast 

castings stainless borated water Thermal aging Austenitic Stainless Steel (CASS)" 

steel up to 3400C and neutron 

(CASS) (644°F) irradiation 

embrittlement, 

void swelling I

C 

0o 

0

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IV Reactor Vessel, Internals, and Reactor Coolant System 

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

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0 

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.6-f Lower grid assembly Type 304 Chemically Cumulative For components for which a fatigue Yes, 

B4.6.1 Lower grid rib section stainless treated fatigue damage/ analysis has been performed for the TLAA 

B4.6.2 Fuel assembly support pads steel; borated water Fatigue 40-year period, fatigue is a time-limited 

B4.6.3 Lower grid rib-to-shell forging lower up to 3400C aging analysis (TLAA) to be performed 

screws internals (644°F) for the period of extended operation, 

B4.6.4 Lower grid flow dist. plate assembly- and, for Class 1 components, 

B4.6.5 Orifice plugs to-thermal environmental effects on fatigue are to 

B4.6.6 Lower grid and shell forgings shield be addressed. See the Standard Review 

B4.6.7 Lower internals assembly-to- bolts: Plan, Section 4.3 "Metal Fatigue," for 

thermal shield bolts A-286, acceptable methods for meeting the 

B4.6.8 Guide blocks and bolts X-750; requirements of 10 CFR 54.21 (c). 

B4.6.9 Shock pads and bolts other bolts 

B4.6.10 Support post pipes and 

B4.6.11 Incore guide tube spider screws: 

castings Gr. B-8 

stainless 

steel; 

spider 

castings: 

CASS 

B4.6-g Lower grid assembly Shell Chemically Loss of preload/ Chapter XI.M1, "ASME Section XI No 

B4.6.3 Lower grid rib-to-shell forging forging treated Stress relaxation Inservice Inspection, Subsections IWB, 

screws screws: borated water IWC, and IWD," for Class 1 components 

B4.6.7 Lower internals assembly-to- Gr. B-8 up to 3400C and 

thermal shield bolts stainless (644°F) 

steel; Chapter XI.M14, "Loose Part Monitoring" 

thermal 

shield 

bolts: 

A-286, 

X-750 

B4.6-h Lower grid assembly Type 304 Chemically Loss of material/ Chapter XI.M1, "ASME Section XI No 

B4.6.2 Fuel assembly support pads stainless treated Wear Inservice Inspection, Subsections IWB, 

B4.6.8 Guide blocks steel borated water IWC, and IWD," for Class 1 components 

up to 3400C 

(644°F)
IV Reactor Vessel, Internals, and Reactor Coolant System 

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

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.7-a Flow distributor assembly Type 304 Chemically Crack initiation Chapter XI.M1 6, "PWR Vessel No 

B4.7.1 Flow distributor head and stainless treated and growth/ Internals," and 

flange steel borated water Stress corrosion 

B4.7.3 Incore guide support plate up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

B4.7.4 Clamping ring (644°F) irradiation- PWR primary water in EPRI TR-1 05714 

assisted stress 

corrosion cracking 

B4.7-b Flow distributor assembly A-286, Chemically Crack initiation Chapter XI.M1 6, "PWR Vessel No 

B4.7.2 Shell forging-to-flow X-750 treated and growth/ Internals," and 

distributor bolts borated water Stress corrosion 

up to 3400C cracking, Chapter XI.M2, "Water Chemistry," for 

(644°F) irradiation- PWR primary water in EPRI TR-1 05714 

assisted stress 

corrosion cracking 

B4.7-c Flow distributor assembly Type 304 Chemically Changes in A plant-specific aging management Yes, plant 

B4.7.1 Flow distributor head and stainless treated dimensions/ program is to be evaluated. The specific 

flange steel; bolts: borated water Void swelling applicant is to provide a plant-specific 

B4.7.2 Shell forging-to-flow A-286, up to 3400C AMP or participate in industry programs 

distributor bolts X-750 (644°F) to investigate aging effects and 

B4.7.3 Incore guide support plate determine appropriate AMP. Otherwise, 

B4.7.4 Clamping ring the applicant is to provide the basis for 

concluding that void swelling is not an 

issue for the component. 

B4.7-d Flow distributor assembly Type 304 Chemically Loss of fracture Chapter XI.M116, "PWR Vessel Internals" No 

B4.7.1 Flow distributor head and stainless treated toughness/ 

flange steel; borated water Neutron irradiation 

B4.7.2 Shell forging-to-flow bolts: up to 3400C embrittlement, 

distributor bolts A-286, (644°F) void swelling 

B4.7.3 Incore guide support plate X-750 

B4.7.4 Clamping ring neutron 

fluence 

>1017 n/cm 2 

I_ (E >1 MeV)
(

IV Reactor Vessel, Internals, and Reactor Coolant System B4. Reactor Vessel Internals (P WR• - Babcock and Wilcox

> 

00 

-J.

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B4.7-e Flow distributor assembly A-286, Chemically Loss of preload/ Chapter Xi.M1, "ASME Section XI No 

B4.7.2 Shell forging to flow distributor X-750 treated Stress relaxation Inservice Inspection, Subsections IWB, 

bolts borated water IWC, and IWD," for Class 1 components 

up to 3400C and 

(644°F) 

I _Chapter XI.M14, "Loose Part Monitoring" B4.8-a Thermal shield Stainless Chemically Crack initiation Chapter XI.M16, "PWR Vessel No 

steel treated and growth/ Internals," and Chapter XI.M2, "Water 

borated water Stress corrosion Chemistry," for PWR primary water in 

up to 3400C cracking, EPRI TR-1 05714 

(644°F) irradiation

assisted stress 

corrosion cracking 

B4.8-b Thermal shield Stainless Chemically Changes in A plant-specific aging management Yes, plant 

steel treated dimensions/ program is to be evaluated. The specific 

borated water Void swelling applicant is to provide a plant-specific 

up to 3400C AMP or participate in industry programs 

(644°F) to investigate aging effects and 

determine appropriate AMP. Otherwise, 

the applicant is to provide the basis for 

concluding that void swelling is not an 

issue for the component. B4.8-c Thermal shield Stainless Chemically Loss of fracture Chapter XI.M16, "PWR Vessel Internals" No 

steel treated toughness/ 

borated water Neutron irradiation 

up to 3400C embrittlement, 

void swelling 

fluence 

>1017 n/cm2 

(E >1 MeV)

z 

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(
Cl. REACTOR COOLANT PRESSURE BOUNDARY (BOILING WATER REACTOR) 

C1.1 Piping and Fittings 

C1.1.1 Main Steam 

C1.1.2 Feedwater 

C1.1.3 High Pressure Coolant Injection (HPCI) System 

C1.1.4 Reactor Core Isolation Cooling (RCIC) System 

C1.1.5 Recirculation 

C1.1.6 Residual Heat Removal (RHR) System 

C1.1.7 Low Pressure Coolant Injection (LPCI) System C1.1.8 Low Pressure Core Spray (LPCS) System 

C1.1.9 High Pressure Core Spray (HPCS) System 

C1.1.10 Lines to Isolation Condenser 

C1.1.11 Lines to Reactor Water Cleanup (RWC) and Standby Liquid Control 

(SLC) Systems 

C1.1.12 Steam Line to HPCI and RCIC Pump Turbine 

C1.1.13 Small Bore Piping Less than NPS 4 

C1.2 Recirculation Pump 

C1.2.1 Casing 

C1.2.2 Cover 

C1.2.3 Seal Flange 

C1.2.4 Closure Bolting 

C1.3 Valves 

C1.3.1 Body 

C1.3.2 Bonnet 

C1.3.3 Seal Flange 

C1.3.4 Closure Bolting 

C1.4 Isolation Condenser 

C1.4.1 Tubing 

C1.4.2 Tubesheet 

C1.4.3 Channel Head 

C1.4.4 Shell

April 2001 NUREG-1801 IV C1-1
C1. REACTOR COOLANT PRESSURE BOUNDARY (BOILING WATER REACTOR) 

Systems, Structures, and Components 

This section comprises 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 system (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. 

Therefore, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

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 IV C1-2 April 2001

I I
IV Reactor Vessel, Internals, and Reactor Coolant System (.I_ Re.nr~tnr CoolAnt Pressure Boundary (Boililna Water Reactor•I

(

V 

0 

eo 

z 

m M 

0 

0

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C1.1-a Piping and fittings Carbon 2880C (550°F) Wall thinning/ Chapter XI.M17, "Flow-Accelerated No 

C1.1.1 Main steam steel steam Flow-accelerated Corrosion" 

C1.1.12 Steam line to HPCI and SA106- corrosion 

RCIC pump turbine Gr B, 

SA333

Gr6, 

SA1 55-Gr 

KCF70 

C1.1-b Piping and fittings Carbon 2880C (5500F) Cumulative Fatigue is a time-limited aging analysis Yes, 

C1.1.1 Main steam steel steam fatigue damage/ (TLAA) to be performed for the period TLAA 

SA1 06- Fatigue of extended operation, and, for Class 1 

Gr B, components, environmental effects on 

SA333- fatigue are to be addressed. See the 

Gr 6, Standard Review Plan, Section 4.3 

SA1 55-Gr "Metal Fatigue," for acceptable 

KCF70 methods for meeting the requirements 

of 10 CFR 54.21 (c)(1)(i) and (ii), and 

for addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

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

C1.1-c Piping and fittings Carbon Up to 2250C, Wall thinning/ Chapter XI.M1 7, "Flow-Accelerated No 

C1.1.2 Feedwater steel (437°F) Flow-accelerated Corrosion" 

SA1 06- reactor corrosion 

Gr B, coolant water 

SA333

Gr6, 

SA1 55-Gr 

KCF70
IV Reactor Vessel, Internals, and Reactor Coolant System 

C1. Reactor Coolant Pressure Boundary ( oilina Water Reactor)

z 

C 

m 

0 

0 

.--

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C1.1-d Piping and fittings Carbon Up to 2250C Cumulative Fatigue is a time-limited aging analysis Yes, C1.1.2 Feedwater steel (437°F) fatigue damage/ (TLAA) to be performed for the period TLAA 

SA1 06- reactor Fatigue of extended operation, and, for Class 1 

Gr B, coolant water components, environmental effects on 

SA333- fatigue are to be addressed. See the 

Gr 6, Standard Review Plan, Section 4.3 

SA1 55-Gr "Metal Fatigue," for acceptable 

KCF70 methods for meeting the requirements 

of 10 CFR 54.21 (c)(1)(i) and (ii), and 

for addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

10 CFR 54.21 (c)(1)(iii). Cl.1-e Piping and fittings Carbon 2880C Cumulative Fatigue is a time-limited aging analysis Yes, 

C1.1.3 High pressure coolant steel (550-F) fatigue damage/ (TLAA) to be performed for the period TLAA 

injection SA1 06- reactor Fatigue of extended operation, and, for Class 1 

C1.1.4 Reactor core isolation Gr B, coolant water components, environmental effects on 

cooling SA333- or steam fatigue are to be addressed. See the 

Gr 6, Standard Review Plan, Section 4.3 

SA155-Gr "Metal Fatigue," for acceptable 

KCF70 methods for meeting the requirements 

of 10 CFR 54.21 (c)(1)(i) and (ii), and 

for addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

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

N> 

0• 

0
( ( (

N, 

0 

61

IV Reactor Vessel, Internals, and Reactor Coolant System 

C1. Reactor Coolant Pressure Boundary ( oiling Water Re actor) 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C1.1-f Piping and fittings Stainless 2880C' Crack initiation Chapter XI.M7, "BWR Stress Corrosion No 

C1.1.5 Recirculation steel (e.g., (5500F) and growth/ Cracking" and 

C1.1.6 Residual heat removal type 304, reactor Stress corrosion 

C1.1.7 Low pressure coolant 316, or coolant water cracking, inter- Chapter XI.M2, "Water Chemistry," for 

injection 316NG); or steam granular stress BWR water in BWRVIP-29 (EPRI C1.1.8 Low pressure core spray cast corrosion cracking TR-103515) 

C1.1.9 High pressure core spray austenitic 

C1.1.10 Lines to isolation condenser stainless 

C1.1.11 Lines to reactor water steel; 

cleanup and standby liquid nickel 

control systems alloys (e.g., 

alloys 600, 

182, or 82) 

Cl.1-g Piping and fittings Cast 2880C Loss of fracture Chapter XI.M12, "Thermal Aging No 

C1.1.6 Residual heat removal austenitic (5500F) toughness/ Embrittlement of Cast Austenitic 

C1.1.7 Low pressure coolant stainless reactor Thermal aging Stainless Steel (CASS)" 

injection steel coolant water embrittlement 

C1.1.8 Low pressure core spray or steam 

C1.1.9 High pressure core spray 

C1.1.10 Lines to isolation condenser 

C1.1.11 Lines to reactor water 

cleanup and standby liquid 

control systems

z c 

m 

0 R
Reactor Vessel, Internals, and Reactor Coolant System 

r~l- Reactor Conlnnt Pressure Boundarv ( ollina Water Reactor)

(

z C IV

m 0 

0 

0 

6)

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

01.1-h Piping and fittings Carbon 2880C (5500F) Cumulative Fatigue is a time-limited aging analysis Yes, 

01.1.5 Recirculation steel, cast reactor fatigue damage/ (TLAA) to be performed for the period TLAA 

01.1.6 Residual heat removal austenitic coolant water Fatigue of extended operation, and, for Class 1 

C1.1.7 Low pressure coolant stainless or steam components, environmental effects on 

injection steel, fatigue are to be addressed. See the 

C1.1.8 Low pressure core spray stainless Standard Review Plan, Section 4.3 

C(1.1.9 High pressure core spray steel "Metal Fatigue," for acceptable 

C1.1.10 Lines to isolation condenser methods for meeting the requirements 

C1.1.11 Lines to reactor water of 10 CFR 54.21 (c)(1)(i) and (ii), and 

cleanup and standby liquid for addressing environmental effects on 

control systems fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

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

0 

0

Q
(

IV

(

Reactor Vessel, Internals, and Reactor Coolant System C1. Reactor Coolant Pressure Boundarv (B oilino Water Reactor)

(

0 

ý> 

0• 

o)

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C1.1-i Piping and fittings Stainless 2880C Crack initiation Chapter XI.M1, "ASME Section XI Yes, 

C1.1.13 Small bore piping less than steel, (550°F) and growth/ Inservice Inspection, Subsections IWB, parameters 

NPS 4 carbon reactor Stress corrosion IWC, and IWD," for Class 1 monitored/ 

steel coolant water cracking, inter- components and inspected 

granular stress and detection 

corrosion Chapter XI.M2, "Water Chemistry," for of aging 

cracking, thermal BWR water in BWRVIP-29 (EPRI TR- effects are to 

and mechanical 103515) be evaluated 

loading 

Inspection in accordance with ASME 

Section Xl does not require volumetric 

examination of pipes less than NPS 4. 

A plant-specific destructive examination 

or a nondestructive examination (NDE) 

that permits inspection of the inside 

surfaces of the piping is to be 

conducted to ensure that cracking has 

not occurred and the component intended function will be maintained 

during the extended period of 

operation. 

The AMPs are to be augmented by verifying that service-induced weld 

cracking is not occurring in the small

bore piping less than NPS 4, including 

pipe, fittings, and branch connections. 

See Chapter XI.M32, "One-Time 

Inspection" for an acceptable 

verification method.

z 

m 

co 0
IV Reactor Vessel, Internals, and Reactor Coolant System C1. Reactor Coolant Pressure Boundary (B oilina Water Reactor•

z C 

m 

0 

eo 

0 

"0 

0

K

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C1.2-a Recirculation pump Cast 288°C Cumulative Fatigue is a time-limited aging analysis Yes, 

C1.2.1 Casing austenitic (5500F) fatigue damage/ (TLAA) to be performed for the period TLAA 

C1.2.2 Cover stainless reactor Fatigue of extended operation, and, for Class 1 

C1.2.3 Seal flange steel, coolant water components, environmental effects on 

stainless fatigue are to be addressed. See the 

steel Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable 

methods for meeting the requirements of 10 CFR 54.21 (c)(1)(i) and (ii), and 

for addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

10 CFR 54.21 (c)(1)(iii). C1.2-b Recirculation pump Cast 2880C Crack initiation Chapter XI.M7, "BWR Stress Corrosion No 

C1.2.1 Casing austenitic (5500F) and growth/ Cracking" and 

stainless reactor stress corrosion 

steel coolant water cracking, inter- Chapter XI.M2, 'Water Chemistry," for 

granular stress BWR water in BWRVIP-29 (EPRI 

corrosion cracking TR-103515) 

C1.2-c Recirculation pump Cast 2880C (550'F) Loss of fracture Chapter XI.M1, "ASME Section Xl No 

C1.2.1 Casing austenitic reactor toughness/ Inservice Inspection, Subsections IWB, 

stainless coolant water Thermal aging IWC, and IWD," for Class 1 

steel embrittlement components 

For pump casings, screening for 

susceptibility to thermal aging is not 

required. The ASME Section Xl 

inspection requirements are sufficient 

for managing the effects of loss of 

fracture toughness due to thermal 

aging embrittlement of CASS valve 

bodies.
(

IV Reactor Vessel, Internals, and Reactor Coolant System C1. Reactor Coolant Pressure Boundarv (Rniilinn Watar Ranctnr•

(

V 

N, 

0 

0 

C) 

(0

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

Cl.2-d Recirculation pump Flange: Air with mnetal Loss of material/ Chapter XI.M18, "Bolting Integrity," No 

C1.2.3 Seal flange stainless temperature Wear 

C1.2.4 Closure bolting steel; up to 2880C 

bolting: (5500F) 

high

strength 

low-alloy 

steel 

SA193 

Gr. B7 

C1.2-e Recirculation pump High- Air with metal Loss of preload/ Chapter XI.M1 8, "Bolting Integrity" No 

C1.2.4 Closure bolting strength temperature Stress relaxation 

low-alloy up to 2880C 

steel (550°F) 

SA193 

Gr. B7 I 

C1.2-f Recirculation pump High- Air with metal Cumulative Fatigue is a time-limited aging analysis Yes, C1.2.4 Closure bolting strength temperature fatigue damage/ (TLAA) to be performed for the period TLAA 

low-alloy up to 2880C Fatigue of extended operation; check Code 

steel (550-F) limits for allowable cycles (less than 

SA1 93 7000 cycles) of thermal stress range. Gr. B7 See the Standard Review Plan, Section 

4.3 "Metal Fatigue," for acceptable 

methods for meeting the requirements 

of 10 CFR 54.21(c). C1.3-a Valves (check, control, hand, Carbon 2880C (5500F) Wall thinning/ Chapter XI.M 17, "Flow-Accelerated No 

motor-operated, relief, and steel reactor Flow-accelerated Corrosion" 

containment isolation) coolant water corrosion 

C1.3.1 Body

z 

C 

m 

00 

cc 0
IV Reactor Vessel, Internals, and Reactor Coolant System 

C1. Reactor Coolant Pressure oundary oiling Water Reactor) 

Structure and/or Aging Effect! Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C1.3-b Valves Cast 288°C (5500F) Loss of fracture Chapter XI.M1, "ASME Section Xl No 

(check, control, hand, motor- austenitic reactor toughness/ Inservice Inspection, Subsections IWB, 

operated, relief, and stainless coolant water Thermal aging IWC, and IWD," for Class 1 

containment isolation) steel embrittlement components 

C1.3.1 Body 

C1.3.2 Bonnet For valve bodies, screening for 

susceptibility to thermal aging is not 

required. The ASME Section Xl 

inspection requirements are sufficient 

for managing the effects of loss of 

fracture toughness due to thermal 

aging embrittlement of CASS valve 

bodies. 

C1.3-c Valves Cast 2880C Crack initiation Chapter XI.M7, "BWR Stress Corrosion No 

(check, control, hand, motor- austenitic (5500F) and growth/ Cracking" and 

operated, relief, and stainless reactor Stress corrosion 

containment isolation) steel, coolant water cracking, inter- Chapter XI.M2, "Water Chemistry," for 

C1.3.1 Body stainless granular stress BWR water in BWRVIP-29 (EPRI 

C1.3.2 Bonnet steel corrosion cracking TR-103515) 

C1.3-d Valves (check, control, hand, Carbon 2880C Cumulative Fatigue is a time-limited aging analysis Yes, 

motor-operated, relief, and steel, cast (5500F) fatigue damage/ (TLAA) to be performed for the period TLAA 

C1.3.1 containment isolation) austenitic reactor Fatigue of extended operation, and, for Class 1 

C1.3.2 Body stainless coolant water components, environmental effects on 

C1.3.3 Bonnet steel, fatigue are to be addressed. See the 

Seal flange stainless Standard Review Plan, Section 4.3 

steel "Metal Fatigue," for acceptable 

methods for meeting the requirements 

of 10 CFR 54.21 (c)(1)(i) and (ii), and 

for addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

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

K (
IV Reactor Vessel, Internals, and Reactor Coolant System C1. Reactnr Cnnlant Prat_.,ra Rnirrianura If rlllnn Wafdr 0iot!•sA

0 

N) 

0 

9

(

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C1l.3-e Valves Flange: Air with metal Loss of material/ Chapter XI.M18, "Bolting Integrity' No 

C1.3.4 Closure bolting carbon temperature Wear 

steel, up to 2880C 

stainless (5500F) 

steel; 

bolting: 

high

strength 

low-alloy 

steel 

C1.3-f Valves High- Air with metal Loss of preload/ Chapter XI.M18, "Bolting Integrity" No 

C1.3.4 Closure bolting strength temperature Stress relaxation 

low-alloy up to 2880C 

steel (550°F) 

SA1 93 

GrB7 

C1.3-g Valves High- Air with metal Cumulative Fatigue is a time-limited aging analysis Yes, C1.3.4 Closure bolting strength temperature fatigue damage/ (TLAA) to be performed for the period TLAA 

low-alloy up to 2880C Fatigue of extended operation; check Code 

steel (550°F) limits for allowable cycles (less than 

SAl 93 7000 cycles) of thermal stress range. GrB7 See the Standard Review Plan, Section 

4.3 "Metal Fatigue," for acceptable methods for meeting the requirements 

of 10 CFR 54.21 (c).

z 

C :0 

m 

00 9 0
Reactor Vessel, Internals, and Reactor Coolant System C1. Reactor Coolant Pressure Boundary lE lillna Water Reactor•i

0 

0> 

-S.

(

z C IV

m 

0 

0

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C1.4-a Isolation condenser Tubes: Tube side: Crack initiation Chapter XI.M1, "ASME Section XI Yes, plant 

C1.4.1 Tubing stainless steam; and growth/ Inservice Inspection, Subsections IWB, specific C1.4.2 Tubesheet steel; shell side: Stress corrosion IWC, and IWD," for Class 1 

C1.4.3 Channel head tubesheet: demineralized cracking, cyclic components and 

C1.4.4 Shell carbon water loading 

steel, Chapter XI.M2, "Water Chemistry," for 

stainless BWR water in BWRVIP-29 (EPRI 

steel; TR-103515) 

channel 

head: The AMP in Chapter XI.M1 is to be 

carbon augmented to detect cracking due to 

steel, stress corrosion cracking and cyclic stainless loading or loss of material due to pitting 

steel; and crevice corrosion, and verification 

shell: of the effectiveness of the program is 

carbon required to ensure that significant steel degradation is not occurring and the 

component intended function will be 

maintained during the extended period of operation. An acceptable verification 

program is to include temperature and 

radioactivity monitoring of the shell side 

water, and eddy current testing of 

tubes.
(

IV Reactor Vessel, Internals, and Reactor Coolant System 

C1. ReacItnr Cnnlant PrAessiuA Rneinrnd-rv I Rilnn Watar RnAt-tnrl

0. 0o 

C-

(

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C1.4-b Isolation condenser Tubes: Tube side: Loss of material/ Chapter XI.M1, "ASME Section X1 Yes, plant C1.4.1 Tubing stainless steam; General, pitting, Inservice Inspection, Subsections IWB, specific 

C1.4.2 Tubesheet steel; shell side: and crevice IWC, and IWD," for Class 1 

C1.4.3 Channel head tubesheet: demineralized corrosion components and 

C1.4.4 Shell carbon water 

steel, Chapter XI.M2, "Water Chemistry," for 

stainless BWR water in BWRVIP-29 (EPRI 

steel; TR-103515) 

channel 

head: The AMP in Chapter XI.M1 is to be 

carbon augmented to detect cracking due to 

steel, stress corrosion cracking and cyclic stainless loading or loss of material due to pitting 

steel; and crevice corrosion, and verification 

shell: of the effectiveness of the program is 

carbon required to ensure that significant 

steel degradation is not occurring and the 

component intended function will be 

maintained during the extended period 

of operation. An acceptable verification 

program is to include temperature and 

radioactivity monitoring of the shell side 

water, and eddy current testing of 

tubes.

z 

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C2. REACTOR COOLANT SYSTEM AND CONNECTED LINES 

(PRESSURIZED WATER REACTOR) 

C2.1 Reactor Coolant System Piping and Fittings 

C2.1.1 Cold Leg 

C2.1.2 Hot Leg 

C2.1.3 Surge Line 

C2.1.4 Spray Line 

C2.1.5 Small-Bore RCS Piping, Fittings, and Branch Connections 

Less than NPS 4 

C2.2 Connected Systems Piping and Fittings 

C2.2.1 Residual Heat Removal (RHR) or Low Pressure Injection System 

(Decay Heat Removal [DHR] Shutdown System) 

C2.2.2 Core Flood System (CFS) 

C2.2.3 High Pressure Injection System (Makeup & Letdown Functions) 

C2.2.4 Chemical and Volume Control System 

C2.2.5 Sampling System 

C2.2.6 Drains and Instrument Lines 

C2.2.7 Nozzles and Safe Ends 

C2.2.8 Small-Bore Piping, Fittings, and Branch Connections Less than NPS 4 in 

Connected Systems 

C2.3 Reactor Coolant Pump 

C2.3.1 Casing 

C2.3.2 Cover 

C2.3.3 Closure Bolting 

C2.4 Valves (Check, Control, Hand, Motor-Operated, Relief, and Containment Isolation) 

C2.4.1 Body 

C2.4.2 Bonnet 

C2.4.3 Closure Bolting 

C2.5 Pressurizer 

C2.5.1 Shell/Heads 

C2.5.2 Spray Line Nozzle 

C2.5.3 Surge Line Nozzle 

C2.5.4 Spray Head 

C2.5.5 Thermal Sleeves 

C2.5.6 Instrument Penetrations 

C2.5.7 Safe Ends 

C2.5.8 Manway and Flanges 

C2.5.9 Manway and Flange Bolting 

C2.5.10 Heater Sheaths and Sleeves 

C2.5.11 Support Keys, Skirt, and Shear Lugs 

C2.5.12 Integral Support

April 2001 IV C2-1 NUREG-1801
C2.6 Pressurizer Relief Tank

C2.6.1 Tank Shell and Heads 

C2.6.2 Flanges and Nozzles

NUREG-1801 IV C2-2 April 2001

I I
C2. REACTOR COOLANT SYSTEM AND CONNECTED LINES (PRESSURIZED WATER 

REACTOR) 

Systems, Structures, and Components 

This section comprises 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 spray 

(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. 

Therefore, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

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.El).

April 2001 IV C2-3 NUREG-1801
IV Reactor Vessel, Internals, and Reactor Coolant System 

U2 Reator Coolant System and Connected Lines (Pressurized Water Reactor

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Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C2.1-a Reactor coolant system Stainless Chemically Cumulative Fatigue is a time-limited aging analysis Yes, 

piping and fittings steel, cast treated fatigue damage/ (TLAA) to be performed for the period of TLAA 

C2.1.1 Cold leg austenitic borated water Fatigue extended operation, and, for Class 1 

C2.1.2 Hot leg stainless up to 3400C components, environmental effects on 

steel, carbon (6440F) fatigue are to be addressed. See the 

steel with Standard Review Plan, Section 4.3 

stainless steel "Metal Fatigue," for acceptable methods 

cladding for meeting the requirements of 

10 CFR 54.21 (c)(1)(i) and (ii), and for 

addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

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

C2.1-b Reactor coolant system Surge line: Chemically Cumulative Fatigue is a time-limited aging analysis Yes, 

piping and fittings stainless treated fatigue damage/ (TLAA) to be performed for the period of TLAA 

C2.1.3 Surge line steel, cast borated water Fatigue extended operation, and, for Class 1 

C2.1.4 Spray line austenitic up to 3400C components, environmental effects on 

stainless (644°F) fatigue are to be addressed. See the 

steel; spray Standard Review Plan, Section 4.3 

line: stainless "Metal Fatigue," for acceptable methods 

steel for meeting the requirements of 

10 CFR 54.21 (c)(1)(i) and (ii), and for 

addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

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

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Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C2.1-c Reactor coolant system Stainless Chemicalliy Crack initiation Chapter XI.M1, "ASME Section Xl No 

piping and fittings steel, treated and growth/ Inservice Inspection, Subsections IWB, C2.1.1 Cold leg stainless steel borated water Stress corrosion IWC, and IWD," for Class 1 components C2.1.2 Hot leg cladding on up to 3400C cracking and 

C2.1.3 Surge line carbon steel (644°F) (stainless steel 

C2.1.4 Spray line piping), Chapter XI.M2, "Water Chemistry," for 

I cyclic loading PWR primary water in EPRI TR-105714 

C2.1-d Reactor coolant system Carbon steel Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

piping and fittings chemically Boric acid 

C2.1.1 Cold leg treated corrosion of 

C2.1.2 Hot leg (external borated water external surfaces 

surfaces) 

C2.1 -e Reactor coolant system Cast Chemically Crack initiation Monitoring and control of primary water Yes, plant piping and fittings austenitic treated and growth/ chemistry in accordance with the specific C2.1.1 Cold leg stainless steel borated water Stress corrosion guidelines in EPRI TR-105714 (Rev. 3 or 

C2.1.2 Hot leg up to 3400C cracking later revisions or update) minimize the 

C2.1.3 Surge line (644°F) potential of SCC, and material selection 

according to the NUREG-0313, Rev. 2 

guidelines of <0.035% C and >7.5% 

ferrite has reduced susceptibility to SCC. 

For CASS components that do not meet 

either one of the above guidelines, a 

plant-specific aging management 

program is to be evaluated. The program 

is to include (a) adequate inspection 

methods to ensure detection of cracks, 

and (b) flaw evaluation methodology for 

CASS components that are susceptible to thermal aging embrittlement. 

C2.1 -f Reactor coolant system Cast Chemically Loss of fracture Chapter XI.M12, "Thermal Aging No 

piping and fittings austenitic treated toughness/ Embrittlement of Cast Austenitic 

C2.1.1 Cold-leg stainless steel borated water Thermal aging Stainless Steel (CASS)" 

C2.1.2 Hot-leg up to 3400C embrittlement 

C2.1.3 Surge line (6440F) I I I _I
IV Reactor Vessel, Internals, and Reactor Coolant System 

C2. Reactor Coolant Svstem and Connected Lines (Pressurized Water Reactor

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C2.1 -g Reactor coolant system Stainless steel Chemically Crack initiation Chapter XI.M1, "ASME Section Xl Yes, piping and fittings treated and growth/ Inservice Inspection, Subsections IWB, parameters 

C2.1.5 RCS piping, fittings, and borated water Stress corrosion IWC, and IWD," for Class 1 components monitored/ 

branch connections less up to 3400C cracking, thermal and inspected 

than NPS 4 (644°F) and mechanical and 

loading Chapter XI.M2, "Water Chemistry," for detection of 

PWR primary water in EPRI TR-1 05714 aging effects 

are to be 

Inspection in accordance with ASME evaluated 

Section Xl does not require volumetric 

examination of pipes less than NPS 4. A 

plant-specific destructive examination or 

a nondestructive examination (NDE) that 

permits inspection of the inside surfaces 

of the piping is to be conducted to 

ensure that cracking has not occurred 

and the component intended function will 

be maintained during the extended 

period of operation. 

The AMPs are to be augmented by 

verifying that service-induced weld 

cracking is not occurring in the small

bore piping less than NPS 4, including pipe, fittings, and branch connections. 

See Chapter XI.M32, "One-Time 

Inspection" for an acceptable verification 

method. I
IV

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10 CFR 54.21 (c)(1)(i) and (ii), and for 

addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for meeting the requirements of 

10 CFR 54.21 (c)(1)(iii). C2.2-b Connected systems piping Carbon steel Chemically Cumulative Fatigue is a time-limited aging analysis Yes, and fittings with stainless treated fatigue damage/ (TLAA) to be performed for the period of TLAA C2.2.5 Sampling system steel cladding, borated water Fatigue extended operation, and, for Class 1 C2.2.6 Drains and instrument stainless steel up to 3400C components, environmental effects on lines (644-F) fatigue are to be addressed. See the 

Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 

10 CFR 54.21 (c)(1)(i) and (ii), and for 

addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

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

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C2.2-c Connected systems piping Stainless Chemically Cumulative Fatigue is a time-limited aging analysis Yes, and fittings steel, cast treated fatigue damage/ (TLAA) to be performed for the period of TLAA 

C2.2.7 Nozzles and safe ends austenitic borated water Fatigue extended operation, and, for Class 1 

stainless steel up to 3400C components, environmental effects on 

(644°F) fatigue are to be addressed. See the 

Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 

10 CFR 54.21 (c)(1)(i) and (ii), and for 

addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

10 CFR 54.21 (c)(1)(iii). C2.2-d Connected systems piping Carbon steel Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

and fittings chemically Boric acid 

C2.2.5 Sampling system treated corrosion of 

C2.2.6 Drains and instrument borated water external surfaces 

lines (external surfaces) 

C2.2-e Connected systems piping Cast Chemically Loss of fracture Chapter Xl.M12, "Thermal Aging No 

and fittings austenitic treated toughness/ Embrittlement of Cast Austenitic 

C2.2.7 Nozzles and safe ends stainless steel borated water Thermal aging Stainless Steel (CASS)" 

up to 3400C embrittlement 

1(6440F) I
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Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C2.2-f Connected systems piping Stainless steel Chemically Crack initiation Chapter XI.M1, "ASME Section Xl No 

and fittings treated and growth/ Inservice Inspection, Subsections IWB, 

C2.2.1 Residual heat removal borated water Stress corrosion IWC, and IWD," for Class 1 components 

02.2.2 Core flood system up to 3400C cracking and 

C2.2.3 High pressure injection (644°F) 

system Chapter XI.M2, "Water Chemistry," for 

C2.2.4 Chemical and volume PWR primary water in EPRI TR-1 05714 

control system 

C2.2.5 Sampling system 

02.2.6 Drains and instrument 

lines 

C2.2.7 Nozzles and safe ends 

C2.2-g Connected systems piping Cast Chemically Crack initiation Monitoring and control of primary water Yes, plant 

and fittings austenitic treated and growth/ chemistry in accordance with the specific 

C2.2.7 Nozzles and safe ends stainless steel borated water Stress corrosion guidelines in EPRI TR-1 05714 (Rev. 3 or 

up to 3400C cracking later revisions or update) minimize the 

(644°F) potential of SCC, and material selection 

according to the NUREG-0313, Rev. 2 

guidelines of <0.035% C and a7.5% 

ferrite has reduced susceptibility to SCC. 

For CASS components that do not meet 

either one of the above guidelines, a 

plant-specific aging management 

program is to be evaluated. The program 

is to include (a) adequate inspection 

methods to ensure detection of cracks, 

and (b) flaw evaluation methodology for 

CASS components that are susceptible 

I to thermal aging embrittlement.

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02.2-h Connected systems piping Stainless Chemic ally Crack initiation Chapter XI.M1, "ASME Section XI Yes, 

and fittings steel, carbon treated and growth/ Inservice Inspection, Subsections IWB, parameters 

C2.2.8 Small-bore piping, fittings, steel borated water Stress corrosion IWC, and IWD," for Class 1 components monitored/ 

and branch connections up to 3400C cracking, thermal and inspected 

less than NPS 4 in (644°F) and mechanical and 

connected systems loading Chapter XI.M2, "Water Chemistry," for detection of 

PWR primary water in EPRI TR-105714 aging effects 

are to be 

Inspection in accordance with ASME evaluated 

Section XI does not require volumetric 

examination of pipes less than NPS 4. A 

plant-specific destructive examination or 

a nondestructive examination (NDE) that 

permits inspection of the inside surfaces 

of the piping is to be conducted to 

ensure that cracking has not occurred 

and the component intended function will 

be maintained during the period of 

extended operation. 

The AMPs are to be augmented by 

verifying that service-induced weld 

cracking is not occurring in the small

bore piping less than NPS 4, including 

pipe, fittings, and branch connections. 

See Chapter XI.M32, "One-Time 

Inspection" for an acceptable verification 

method.
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C2.3-a Reactor coolant pump Bowl: cast Chemically Cumulative Fatigue is a time-limited aging analysis Yes, C2.3.1 Casing austenitic treated fatigue damage/ (TLAA) to be performed for the period of TLAA 

C2.3.2 Cover stainless steel borated water Fatigue extended operation, and, for Class 1 

CF-8 or up to 3400C components, environmental effects on 

CF-8M, (644°F) fatigue are to be addressed. See the 

carbon steel Standard Review Plan, Section 4.3 

with stainless "Metal Fatigue," for acceptable methods 

steel cladding; for meeting the requirements of 

cover: 10 CFR 54.21 (c)(1)(i) and (ii), and for 

stainless steel addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

10 CFR 54.21 (c)(1)(iii). C2.3-b Reactor coolant pump Cast Chemically Crack initiation Monitoring and control of primary water No 

C2.3.1 Casing austenitic treated and growth/ chemistry in accordance with the 

stainless steel borated water Stress corrosion guidelines in EPRI TR-1 05714 (Rev. 3 or 

CF-8 or up to 3400C cracking later revisions or update) minimize the 

CF-8M, (644°F) potential of SCC, and material selection 

carbon steel according to the NUREG-0313, Rev. 2 

with stainless guidelines of 50.035% C and a7.5% 

steel cladding ferrite has reduced susceptibility to SCC. 

For CASS components that do not meet 

either one of the above guidelines, see 

Chapter XI.M1, "ASME Section Xi, Subsections IWB, IWC, and IWD." 

C2.3-c Reactor coolant pump Cast Chemically Loss of fracture Chapter XI.M1, "ASME Section Xi No 

C2.3.1 Casing austenitic treated toughness/ Inservice Inspection, Subsections IWB, stainless steel borated water Thermal aging IWC, and IWD," for Class 1 components 

CF-8 or up to 3400C embrittlement 

CF-8M (644°F) For pump casings, screening for 

susceptibility to thermal aging is not 

I__IIrequired.
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Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C2.3-d Reactor coolant pump High-strength Air with metal Cumulative Fatigue is a'time.limited aging analysis Yes, 

C2.3.3 Closure bolting low-alloy steel temperature fatigue damage/ (TLAA) to be performed for the period of TLAA 

SA540 GrB23, up to 3400C Fatigue extended operation. See the Standard 

SA193 GrB7 (6440F) Review Plan, Section 4.3 "Metal 

Fatigue," for acceptable methods for 

meeting the requirements of 

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

See Chapter X.M1 of this report for 

meeting the requirements of 

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

C2.3-e Reactor coolant pump High-strength Air, leaking Crack initiation Chapter XI.M1 8, "Bolting Integrity' No 

C2.3.3 Closure bolting low-alloy steel chemically and growth/ 

SA540 GrB23, treated Stress corrosion 

SA1 93 GrB7 borated water cracking 

or steam up to 

3400C (644°F) 

C2.3-f Reactor coolant pump High-strength Air, leaking Loss of material/ Chapter XI.M1 0, "Boric Acid Corrosion" No 

C2.3.3 Closure bolting low-alloy steel chemically Boric acid 

SA540 GrB23, treated corrosion of 

SA1 93 GrB7 borated water external surfaces 

or steam up to 

I_ 3400C (6440F) 

C2.3-g Reactor coolant pump High-strength Air with metal Loss of preload/ Chapter XI.M1 8, "Bolting Integrity' No 

C2.3.3 Closure bolting low-alloy steel temperature Stress relaxation 

SA540 GrB23, up to 3400C 

SA1 93 GrB7 (6440F)

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C2.4-a Valves (check, control, Cast Chemically Cumulative Fatigue is a time-limited aging analysis Yes, 

hand, motor operated, austenitic treated fatigue damage/ (TLAA) to be performed for the period of TLAA 

relief, and containment stainless steel borated water Fatigue extended operation. See the Standard 

isolation) CF-8M, up to 3401C Review Plan, Section 4.3 "Metal 

C2.4.1 Body SA1 82 (644QF) Fatigue," for acceptable methods for 

C2.4.2 Bonnet F316, meeting the requirements of 

SA582 10 CFR 54.21 (c)(1)(i) and (ii). 

Type 416 

See Chapter X.M1 of this report, for 

meeting the requirements of 

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

C2.4-b Valves (check, control, Cast Chemically Crack initiation Monitoring and control of primary water No 

hand, motor operated, austenitic treated and growth/ chemistry in accordance with the 

relief, and containment stainless steel borated water Stress corrosion guidelines in EPRI TR-105714 (Rev. 3 or 

isolation) CF-8M up to 3400C cracking later revisions or update) minimize the 

C2.4.1 Body (644°F) potential of SCC, and material selection 

according to the NUREG-0313, Rev. 2 

guidelines of <0.035% C and >7.5% 

ferrite has reduced susceptibility to SCC. 

For CASS components that do not meet 

either one of the above guidelines, see 

Chapter XI.M1, "ASME Section XI, 

Subsections IWB, IWC, and IWD." 

C2.4-c Valves (check, control, Cast Chemically Loss of fracture Chapter XI.M1, "ASME Section Xi No 

hand, motor operated, austenitic treated toughness/ Inservice Inspection, Subsections IWB, 

relief, and containment stainless steel borated water Thermal aging IWC, and IWD," for Class 1 components 

isolation) CF-8M up to 3400C embrittlement 

C2.4.1 Body (644°F) For valve body, screening for 

susceptibility to thermal aging is not 

1 required. I
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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C2.4-d Valves High-strength Air with metal Cumulative Fatigue is a time-limited aging analysis Yes, 

C2.4.3 Closure bolting low-alloy temperature fatigue damage/ (TLAA) to be performed for the period of TLAA 

steel, up to 3400C Fatigue extended operation. See the Standard 

stainless steel (6440F) Review Plan, Section 4.3 "Metal 

Fatigue," for acceptable methods for 

meeting the requirements of 

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

See Chapter X.M1 of this report for 

meeting the requirements of 

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

C2.4-e Valves High-strength Air, leaking Crack initiation Chapter XI.M18, "Bolting Integrity' No 

C2.4.3 Closure bolting low-alloy chemically and growth/ 

steel, treated Stress corrosion 

stainless steel borated water cracking 

or steam 

C2.4-f Valves High-strength Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

C2.4.3 Closure bolting low-alloy steel chemically Boric acid 

treated corrosion of 

borated water external surfaces 

or steam 

C2.4-g Valves High-strength Air with metal Loss of preload/ Chapter XI.M1 8, "Bolting Integrity' No 

C2.4.3 Closure bolting low-alloy temperature Stress relaxation 

steel, up to 3400C 

stainless steel (6440F)
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C2. Reactor Coolant Svstem and Connected Lines (Pressurized Water Reactor

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C2.5-a Pressurizer Low-alloy Chemically Cumulative Fatigue is a time-limited aging analysis Yes, 

C2.5.1 Shell/heads steel with treated fatigue damage/ (TLAA) to be performed for the period of TLAA 

stainless steel borated water Fatigue extended operation, and, for Class 1 

or alloy 600 or saturated components, environmental effects on 

cladding steam fatigue are to be addressed. See the 

290-3430C Standard Review Plan, Section 4.3 

(554-6500F) "Metal Fatigue," for acceptable methods 

for meeting the requirements of 

10 CFR 54.21 (c)(1)(i) and (ii), and for 

addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

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

C2.5-b Pressurizer Low-alloy Air, leaking Loss of material/ Chapter XI.M1 0, "Boric Acid Corrosion" No 

C2.5.1 Shell/heads (outer steel chemically Boric acid 

surfaces) treated corrosion of 

borated water external surfaces 

or steam up to 

I 3400C (6440F) I

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Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C2.5-c Pressurizer Low-alloy Chemically Crack initiation Chapter XI.M1, "ASME Section XI No 

C2.5.1 Shell/heads steel with type treated and growth/ Inservice Inspection, Subsections IWB, 

308, 308L, or borated water Stress corrosion IWC, and IWD," for Class 1 components 

309 stainless or saturated cracking, cyclic and 

steel or alloy steam loading 

82 or 182 290-343°C Chapter XI.M2, "Water Chemistry," for 

cladding (554-650°F) PWR primary water in EPRI TR-1 05714 

Cracks in the pressurizer cladding could 

propagate from cyclic loading into the 

ferrite base metal and weld metal. 

However, because the weld metal 

between the surge nozzle and the vessel 

lower head is subjected to the maximum 

stress cycles and the area is periodically 

inspected as part of the ISI program, the 

existing AMP is adequate for managing 

__the effect of pressurizer clad cracking. 

C2.5-d Pressurizer Nozzle: Chemically Cumulative Fatigue is a time-limited aging analysis Yes, 

C2.5.2 Spray line nozzle carbon steel treated fatigue damage/ (TLAA) to be performed for the period of TLAA 

C2.5.4 Spray head or low-alloy borated water Fatigue extended operation, and, for Class 1 

steel with or saturated components, environmental effects on 

stainless steel steam fatigue are to be addressed. See the 

cladding; 290-343°C Standard Review Plan, Section 4.3 

spray head: (554-650°F) "Metal Fatigue," for acceptable methods 

alloy 600, for meeting the requirements of 

stainless 10 CFR 54.21 (c)(1)(i) and (ii), and for 

steel, addressing environmental effects on 

cast austenitic fatigue. 

stainless steel 

See Chapter X.M1 of this report for 

meeting the requirements of 

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

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C2.5-e Pressurizer Carbon steel Chemically Cumulative Fatigue is a time-limited aging analysis Yes, C2.5.3 Surge line nozzle or low-alloy treated fatigue damage/ (TLAA) to be performed for the period of TLAA 

steel with borated water Fatigue extended operation, and, for Class 1 

stainless steel up to 3400C components, environmental effects on 

cladding, cast (6440F) fatigue are to be addressed. See the 

austenitic Standard Review Plan, Section 4.3 

stainless steel "Metal Fatigue," for acceptable methods 

for meeting the requirements of 

10 CFR 54.21 (c)(1)(i) and (ii), and for 

addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

1 10 CFR 54.21 (c)(1)(iii). C2.5-f Pressurizer Thermal Chemically Cumulative Fatigue is a time-limited aging analysis Yes, C2.5.5 Thermal sleeves sleeves: alloy treated fatigue damage/ (TLAA) to be performed for the period of TLAA 

C2.5.6 Instrument penetrations 600; borated water Fatigue extended operation, and, for Class 1 

C2.5.7 Safe ends penetrations: or saturated components, environmental effects on 

Alloy 600, steam fatigue are to be addressed. See the 

stainless 290-3430C Standard Review Plan, Section 4.3 

steel; (554-650°F) "Metal Fatigue," for acceptable methods 

safe ends: for meeting the requirements of 

stainless steel 10 CFR 54.21 (c)(1)(i) and (ii), and for 

addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

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

Z 

m 0 

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Reactor C2. Reactor Vessel, Coolant Internals, and Reactor Coolant System System and Connected Lin•e (Prmqm, riTad W~t~r I•n,',A, r

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0

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation C2.5-g Pressurizer Carbon steel Chemically Crack initiation Chapter XI.M1, "ASME Section Xi No C2.5.2 Spray line nozzle or low-alloy treated and growth/ Inservice Inspection, Subsections IWB, C2.5.3 Surge line nozzle steel with borated water Stress corrosion IWC, and IWD," for Class 1 components C2.5.6 Instrument penetrations stainless steel or saturated cracking and 

cladding; or steam 

stainless steel 290-3430C Chapter XI.M2, "Water Chemistry," for (554-650-F) PWR primary water in EPRI TR-1 05714 

Cracks in the pressurizer cladding could 

propagate from cyclic loading into the 

ferrite base metal and weld metal. 

However, because the weld metal 

between the surge nozzle and the vessel 

lower head is subjected to the maximum 

stress cycles and the area is periodically 

inspected as part of the ISI program, the 

existing AMP is adequate for managing the effect of pressurizer clad cracking. C2.5-h Pressurizer Stainless steel Chemically Crack initiation Chapter XI.M1, "ASME Section Xl No C2.5.7 Safe ends treated and growth/ Inservice Inspection, Subsections IWB, borated water Stress corrosion IWC, and IWD," for Class 1 components 

or saturated cracking and 

steam 

290-3430C Chapter XI.M2, "Water Chemistry," for 

(554-650°F) PWR primary water in EPRI TR-105714

C
(

IV Reactor Vessel, Internals, and Reactor Coolant System C2. Reactor Coolant System and Connected Lines (Pressurized Weter Renitnr~ N) 

C) 

0 

z C 

m 

,c 

0

(

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C2.5-i Pressurizer Cast Chemically Crack initiation Monitoring and control of primary water Yes, plant C2.5.3 Surge line nozzle austenitic treated and growth/ chemistry in accordance with the specific stainless steel borated water Stress corrosion guidelines in EPRI TR-105714 (Rev. 3 or 

up to 3400C cracking later revisions or update) minimize the 

(644-F) potential of SCC, and material selection 

according to the NUREG-0313, Rev. 2 

guidelines of 50.035% C and >7.5% 

ferrite has reduced susceptibility to SCC. 

For CASS components that do not meet 

either one of the above guidelines, a 

plant-specific aging management 

program is to be evaluated. The program 

is to include (a) adequate inspection methods to ensure detection of cracks, 

and (b) flaw evaluation methodology for 

CASS components that are susceptible to thermal aging embrittlement. 

C2.5-j Pressurizer Alloy 600, Chemically Crack initiation A plant-specific aging management Yes, plant C2.5.4 Spray head stainless treated and growth/ program is to be evaluated, specific steel, cast borated water Primary water 

austenitic or saturated stress corrosion 

stainless steel steam cracking, stress 

290-343°C corrosion cracking 

(554-6500 F) C2.5-k Pressurizer Alloy 600 Chemically Crack initiation Chapter XI.M1, "ASME Section Xl Yes, C2.5.6 Instrument penetrations treated and growth/ Inservice Inspection, Subsections IWB, an AMP for 

borated water Primary water IWC, and IWD," for Class 1 components, PWSCC of 

or saturated stress corrosion Chapter XI.M2, "Water Chemistry," for Incone1182 

steam cracking PWR primary water in EPRI TR-105714 weld is to be 

290-3430C (PWSCC) and evaluated 

(554-650°F) 

the applicant is to provide a plant

specific AMP or participate in industry 

programs to determine appropriate AMP 

for PWSCC of Inconel 182 weld. I
IV Reactor Vessel, Internals, and Reactor Coolant System C2. Reactor Coolant Svstem and Conneacted Lines (Preqssuerizd Wetar Il-nretnrz 

C 

m 

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0 

0 

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C2.5-1 Pressurizer Cast Chemically Loss of fracture Chapter XI.M1 2, "Thermal Aging No C2.5.3 Surge line nozzle austenitic treated toughness/ Embrittlement of Cast Austenitic C2.5.4 Spray head stainless steel borated water Thermal aging Stainless Steel (CASS)" 

or saturated embrittlement 

steam 

290.3430C (554-6500F) 

C2.5-m Pressurizer Low-alloy Chemically Crack initiation Chapter XI.M1, "ASME Section XA No C2.5.8 Manway and flanges steel with type treated and growth/ Inservice Inspection, Subsections IWB, 

308, 308L, or borated water Stress corrosion IWC, and IWD," for Class 1 components 309 stainless or saturated cracking, primary and 

steel cladding; steam water stress 

or 290-343°C corrosion cracking Chapter XI.M2, "Water Chemistry," for alloy 82 or (554-6500F) PWR primary water in EPRI TR-1 05714 

182 cladding C2.5-n Pressurizer High-strength Air, leaking Crack initiation Chapter XI.M1 8, "Bolting Integrity" No 

C2.5.9 Manway and flange low-alloy steel chemically and growth/ bolting treated Stress corrosion 

borated water cracking 

or steam up to 

3400

C (6440F) C2.5-o Pressurizer Low-alloy Air, leaking Loss of material/ Chapter XI.M1 0, "Boric Acid Corrosion" No C2.5.8 Manway and flanges steel, chemically Boric acid 

C2.5.9 Manway and flange High-strength treated corrosion of 

bolting low-alloy steel borated water external surfaces 

or steam up to 

3400C (644°F) C2.5-p Pressurizer High-strength Air, leaking Loss of preload/ Chapter XI.M18, "Bolting Integrity' No C2.5.9 Manway and flange low-alloy steel chemically Stress relaxation 

bolting treated 

borated water 

or steam up to 3400C (644°F) I
(

IV

(

Reactor Vessel, Internals, and Reactor Coolant System 

C2. Reactor Coolant Svstem and Cnnnartari I Inca 11r,-acerim,,rl Wntavr Dpa.j,, A

(

9 

0 

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C2.5-q Pressurizer Alloy 600 or Chemically Cumulative Fatigue is a time-limited aging analysis Yes, C2.5.10 Heater sheaths and austenitic treated fatigue damage/ (TLAA) to be performed for the period of TLAA 

sleeves stainless steel borated water Fatigue extended operation, and, for Class 1 

up to 3400C components, environmental effects on 

(644°F) fatigue are to be addressed. See the 

Standard Review Plan, Section 4.3 

"Metal Fatigue," for acceptable methods 

for meeting the requirements of 

10 CFR 54.21 (c)(1)(i) and (ii), and for 

addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

10 CFR 54.21 (c)(1)(iii). C2.5-r Pressurizer Austenitic Chemically Crack initiation Chapter XI.M1, "ASME Section XI No C2.5.10 Heater sheaths and stainless steel treated and growth/ Inservice Inspection, Subsections IWB, sleeves borated water Stress corrosion IWC, and IWD," for Class 1 components 

up to 340°C cracking and 

(6440F) 

Chapter XI.M2, "Water Chemistry," for 

PWR primary water in EPRI TR-1 05714 C2.5-s Pressurizer Alloy 600 Chemically Crack initiation Chapter XI.M1, "ASME Section Xl Yes, C2.5.10 Heater sheaths and treated and growth/ Inservice Inspection, Subsections IWB, AMP for sleeves borated water Primary water IWC, and IWD," for Class 1 components, PWSCC of 

up to 3400C stress corrosion Chapter XI.M2, "Water Chemistry," for Inconel 182 

(6440F) cracking PWR primary water in EPRI TR-1 05714 weld is to be 

(PWSCC) and evaluated 

the applicant is to provide a plant specific AMP or participate in industry 

programs to determine appropriate AMP 

for PWSCC of Inconel 182 weld.
IV Reactor Vessel, Internals, and Reactor Coolant System C2. Ra•actnr Cnnlant A atom nnrl (tennnvtaI I nac £Dvaei,.m. t1AI.* .. In

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation C2.5-t Pressurizer Carbon steel, Air, with metal Cumulative Fatigue is a time-limited aging analysis Yes, C2.5.11 Support keys, skirt, and low-alloy steel temperatures fatigue damage/ (TLAA) to be performed for the period of TLAA shear lugs up to 3400C Fatigue extended operation. See the Standard 

(644°F) Review Plan, Section 4.3 "Metal 

Fatigue," for acceptable methods for 

meeting the requirements of 

10 CFR 54.21(c)(1). C2.5-u Pressurizer Carbon steel Air, Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No C2.5.12 Integral support leaking Boric acid 

chemically corrosion of 

treated external surfaces 

borated water 

C2.5-v Pressurizer Carbon steel, Air Crack initiation Chapter XI.M1, "ASME Section Xl No C2.5.12 Integral support stainless steel and growth/ Inservice Inspection, Subsections IWB, Cyclic loading IWC, and IWD," for Class 1 components C2.5-w Pressurizer Carbon steel, Air Cumulative Fatigue is a time-limited aging analysis Yes, C2.5.12 Integral support stainless steel fatigue damage/ (TLAA) to be performed for the period of TLAA 

Fatigue extended operation. See the Standard 

Review Plan, Section 4.3 "Metal 

Fatigue," for acceptable methods for 

meeting the requirements of 10 CFR 54.21(c)(1). C2.6-a Pressurizer relief tank Carbon steel Chemically Cumulative Fatigue is a time-limited aging analysis Yes, C2.6.1 Tank shell and heads with type 304 treated fatigue damage/ (TLAA) to be performed for the period of TLAA C2.6.2 Flanges and nozzles stainless steel borated water Fatigue extended operation. See the Standard 

cladding at 930C Review Plan, Section 4.3 "Metal 

(200°F) Fatigue," for acceptable methods for 

meeting the requirements of 

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

See Chapter X.M1 of this report, for 

meeting the requirements of 

10 CFR 54.21 (c)(1)(iii).
Reactor Vessel, Internals, and Reactor Coolant System C2. Reactor Coolant System and Connected Lines (Pressurized Water Ren~tor~ V IV

0. 

0O

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

02.6-b Pressurizer relief tank Carbon steel Air, leaking Loss of material/ Chapter XI.M1 0, "Boric Acid Corrosion" No 

C2.6.1 Tank shell and heads chemically Boric acid 

(external surfaces) treated corrosion of 

borated water external surfaces 

at 93°C 

I _(200 0F) 

C2.6-c Pressurizer relief tank Carbon steel Chemically Crack initiation Chapter XI.M1, "ASME Section XI No 

C2.6.1 Tank shell and heads with type 304 treated and growth/ Inservice Inspection, Subsections IWB, C2.6.2 Flanges and nozzles stainless steel borated water Stress corrosion IWC, and IWD," for Class 2 components 

cladding at 930C cracking and 

(200°F) 

Chapter XI.M2, "Water Chemistry," for 

I PWR primary water in EPRI TR-105714 I

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D1. STEAM GENERATOR (RECIRCULATING)

D1.1 Pressure Boundary and Structural 

D1.1.1 Top Head 

D1.1.2 Steam Nozzle and Safe End 

D1.1.3 Upper and Lower Shell 

D1.1.4 Transition Cone 

D1.1.5 Feedwater Nozzle and Safe End 

D1.1.6 Feedwater Impingement Plate and Support 

D1.1.7 Secondary Manway and Handhole Bolting 

D1.1.8 Lower Head 

D1.1.9 Primary Nozzles and Safe Ends 

D1.1.10 Instrument Nozzles 

D1.1.11 Primary Manway (Cover and Bolting) 

D1.2 Tube Bundle 

D1.2.1 Tubes and Sleeves 

D1.2.2 Tube Support Lattice Bars (Combustion Engineering) 

D1.2.3 Tube Plugs 

D1.2.4 Tube Support Plates 

D1.3 Upper Assembly and Separators 

D1.3.1 Feedwater Inlet Ring and Support

April 2001 IV D1-1 NUREG-1 801
D1. STEAM GENERATOR (RECIRCULATING)

Systems, Structures, and Components 

This section consists of 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. 

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-1 801 IV D1-2 April 2001
N) 

C) 

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00 

Cý

IV Reactor Vessel, Internals, and Reactor Coolant System 

D1. Steam Generator (Recirculating) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D1.1-a Pressure boundary and Low-alloy Up to 3000C Cumulative Fatigue is a time-limited aging analysis Yes, 

structural steel (572°F) fatigue damage/ (TLAA) to be performed for the period of TLAA D1.1.1 Top head steam Fatigue extended operation. See the Standard 

D1.1.2 Steam nozzle and safe end Review Plan, Section 4.3 "Metal Fatigue," 

for acceptable methods for meeting the 

requirements of 10 CFR 54.21 (c). D1.1-b Pressure boundary and Carbon Up to 3000C Cumulative Fatigue is a time-limited aging analysis Yes, 

structural steel, (572-F) fatigue damage/ (TLAA) to be performed for the period of TLAA 

D1.1.3 Upper and lower shell low-alloy Fatigue extended operation. See the Standard 

D1.1.4 Transition cone steel secondary- Review Plan, Section 4.3 "Metal Fatigue," D1.1.5 FW nozzle and safe end side water for acceptable methods for meeting the 

D1.1.6 FW impingement plate and chemistry at requirements of 10 CFR 54.21 (c). 

support 5.3-7.2 MPa _ 

D1.1-c Pressure boundary and Carbon Up to 3000C Loss of material/ Chapter XI.M1, "ASME Section Xl Yes, 

structural steel, (572°F) General, pitting, Inservice Inspection, Subsections IWB, detection 

D1.1.3 Upper and lower shell low-alloy and crevice IWC, and IWD," for Class 2 components of aging D1.1.4 Transition cone steel secondary- corrosion and effects is to 

side water be 

chemistry at Chapter XI.M2, "Water Chemistry," for evaluated 

5.3-7.2 MPa PWR secondary water in EPRI TR-1 02134 

As noted in NRC Information Notice 

IN 90-04, general and pitting corrosion of 

the shell exists, the program recommenda

tions may not be sufficient to detect 

general and pitting corrosion, and 

additional inspection procedures are to be 

developed, if required. Dl.1-d Pressure boundary and Carbon Up to 3000C Wall thinning/ Chapter XI.M17, "Flow-Accelerated No 

structural steel (5720F) steam Flow-accelerated Corrosion" 

D1.1.2 Steam nozzle and safe end or secondary- corrosion 

FW nozzle and safe end side water 

D1.1.5 chemistry at 

15.3-7.2 MPa I
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IV Reactor Vessel, Internals, and Reactor Coolant System DI. Steam Generator (Recirculating) 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D1.1-e Pressure boundary and Carbon Up to 3000C Loss of section A plant-specific aging management Yes, plant structural steel (572TF) thickness/ program is to be evaluated, specific D1.1.6 Feedwater impingement secondary- Erosion 

plate and support side water 

chemistry 

D1.1-f Pressure boundary and Low-alloy Air, with metal Loss of preload/ Chapter XI.M18, "Bolting Integrity' No 

structural steel temperature Stress relaxation 

D1.1.7 Secondary manway and up to 3400

C 

handhole bolting (644_F) D1.1 -g Pressure boundary and Low-alloy Air, Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

structural steel leaking Boric acid 

D1.1.8 Lower head (external chemically corrosion of 

surfaces) treated external surfaces 

borated water 

or steam up to 3400C (6440F) D1.1-h Pressure boundary and Carbon Chemically' Cumulative Fatigue is a time-limited aging analysis Yes, structural steel with treated fatigue damage/ (TLAA) to be performed for the period of TLAA D1.1.8 Lower head stainless borated water Fatigue extended operation, and, for Class 1 D1.1.9 Primary nozzles and safe steel up to 3400C components, environmental effects on 

ends cladding, (6440F) and fatigue are to be addressed. See the 

safe ends: 15.2 MPa Standard Review Plan, Section 4.3 "Metal 

stainless Fatigue," for acceptable methods for 

steel meeting the requirements of 

10 CFR 54.21 (c)(1)(i) and (ii), and for 

addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

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

0 0
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f3 

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0 

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IV Reactor Vessel, Internals, and Reactor Coolant System 

D1. Steam Generator (Recirculating) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D1.1-i Pressure boundary and Carbon Chemically Crack initiation Chapter XI.M1, "ASME Section Xl No 

structural steel with treated and growth/ Inservice Inspection, Subsections IWB, 

D1.1.9 Primary nozzles and safe stainless borated water Stress corrosion IWC, and IWD," for Class 1 components 

ends steel at cracking, primary and 

cladding, temperatures water stress 

safe ends: up to 3400C corrosion cracking Chapter XI.M2, "Water Chemistry," for 

stainless (6440F) and PWR primary water in EPRI TR-105714 

steel 15.2 MPa 

(NiCrFe 

buttering, 

and 

stainless 

steel or 

NiCrFe 

weld) 

D1.1 -j Pressure boundary and Alloy 600 Chemically Crack initiation A plant-specific aging management Yes, plant 

structural treated and growth/ program is to be evaluated. specific 

D1.1.10 Instrument nozzles borated water Primary water 

up to 3400C stress corrosion 

(6440F) and cracking 15.5 MPa 

D1.1-k Pressure boundary and Carbon Air, Loss of material/ Chapter XloM10, "Boric Acid Corrosion" No 

structural steel, leaking Boric acid 

D1.1.11 Primary manway low-alloy chemically corrosion of 

(cover and bolting) steel treated external surfaces 

borated water 

and/or steam 

up to 3400C (64T°)

z 

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0
Reactor Vessel, Internals, and Reactor Coolant System D1. Steam Generator (Reeireulatina•

C 

0

K

z IV

m 

OD 

0 

0 

0)

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D1.1-1 Pressure boundary and Carbon Air, Crack initiation Chapter XI.M18, "Bolting Integrity' No 

structural steel, leaking and growth/ D1.1.11 Primary manway low-alloy chemically Stress corrosion 

(bolting only) steel treated cracking 

borated water 

and/or steam 

up to 3400C (644°F) 

D1.2-a Tube bundle Alloy 600 Chemically Crack initiation Chapter XI.M1 9, "Steam Generator Tubing Yes, D1.2.1 Tubes and sleeves treated and growth/ Integrity" and effective

borated water Primary water ness of the 

up to 3400C stress corrosion Chapter XI.M2, "Water Chemistry," for AMP is to 

(6440F) and cracking PWR primary water in EPRI TR-105714 be 

15.5 MPa evaluated 

All PWR licensees have committed 

voluntarily to a SG degradation 

management program described in NEI 

97-06; these guidelines are currently under 

NRC staff review. An AMP based on the 

recommendations of staff-approved NEI 

97-06 guidelines, or other alternate 

regulatory basis for SG degradation 

management, is to be developed and 

incorporated in the plant technical 

specifications.
(

IV Reactor Vessel, Internals, and Reactor Coolant System D1 StRam enmrntnr Iv~.iafin I

(

-o 

:0 M 

00 

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation D1.2-b Tube bundle Alloy 600 Up to 3000C Crack initiation Chapter XI.M19, "Steam Generator Tubing Yes, D1.2.1 Tubes and sleeves (572°F) and growth/ Integrity" and effective

secondary- Outer diameter ness of the 

side water stress corrosion Chapter XI.M2, "Water Chemistry," for AMP is to 

chemistry at cracking PWR secondary water in EPRI TR-1 02134 be 5.3-7.2 MPa evaluated 

All PWR licensees have committed 

voluntarily to a SG degradation 

management program described in NEI 

97-06; these guidelines are currently under 

NRC staff review. An AMP based on the 

recommendations of staff-approved NEI 

97-06 guidelines, or other alternate 

regulatory basis for SG degradation 

management, is to be developed and 

incorporated in the plant technical 

specifications. D1.2-c Tube bundle Alloy 600 Up to 3000

C Crack initiation Chapter XI.M1 9, "Steam Generator Tubing Yes, D1.2.1 Tubes and sleeves (572°F) and growth/ Integrity' and effective

secondary- Intergranular ness of the 

side water attack Chapter XI.M2, "Water Chemistry," for AMP is to 

chemistry at PWR secondary water in EPRI TR-1 02134 be 5.3-7.2 MPa evaluated 

All PWR licensees have committed 

voluntarily to a SG degradation 

management program described in NEI 

97-06; these guidelines are currently under 

NRC staff review. An AMP based on the 

recommendations of staff-approved NEI 

97-06 guidelines, or other alternate 

regulatory basis for SG degradation 

management, is to be developed and 

incorporated in the plant technical 

specifications.
IV Reactor Vessel, Internals, and Reactor Coolant System D1. Steam Generator (Recirculatinn•

z C: 

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0 

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D1.2-d Tube bundle Alloy 600 ID chemically Cumulative Fatigue is a time-limited aging analysis Yes, 

D1.2.1 Tubes and sleeves treated fatigue damage/ (TLAA) to be performed for the period of TLAA 

borated water Fatigue extended operation, and, for Class 1 

up to 3400C components, environmental effects on 

(6440 F); fatigue are to be addressed. See the 

OD up to Standard Review Plan, Section 4.3 "Metal 

3000C Fatigue," for acceptable methods for 

(572°F) meeting the requirements of 

secondary- 10 CFR 54.21 (c)(1)(i) and (ii), and for 

side water addressing environmental effects on 

chemistry fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

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

Dl.2-e Tube bundle Alloy 600 Up to 3000C Loss of section Chapter XI.M19, "Steam Generator Tubing Yes, 

D1.2.1 Tubes and sleeves (572°F) thickness/ Integrity" and effective

secondary- Fretting and wear ness of the 

side water Chapter XI.M2, "Water Chemistry," for AMP is to 

chemistry at PWR secondary water in EPRI TR-102134 be 

5.3-7.2 MPa evaluated 

All PWR licensees have committed 

voluntarily to a SG degradation 

management program described in NEI 

97-06; these guidelines are currently under 

NRC staff review. An AMP based on the 

recommendations of staff-approved NEI 

97-06 guidelines, or other alternate 

regulatory basis for SG degradation 

management, is to be developed and 

incorporated in the plant technical 

specifications.

0 

0
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0O 

0 

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IV Reactor Vessel, Internals, and Reactor Coolant System D1. Steam Generator (Recirculating) 

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D1.2-f Tube bundle Alloy 600 Up to 3000C Loss of material/ Chapter XI.M19, "Steam Generator Tubing Yes, 

D1.2.1 Tubes and sleeves (572°F) Wastage and Integrity" and effective

(exposed to phosphate secondary- pitting corrosion ness of the 

chemistry) side water Chapter XI.M2, "Water Chemistry," for AMP is to 

chemistry at PWR secondary water in EPRI TR-1 02134 be 

5.3-7.2 MPa evaluated 

All PWR licensees have committed 

voluntarily to a SG degradation 

management program described in NEI 

97-06; these guidelines are currently under 

NRC staff review. An AMP based on the 

recommendations of staff-approved NEI 

97-06 guidelines, or other alternate 

regulatory basis for SG degradation 

management, is to be developed and 

incorporated in the plant technical specifications.

z 

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0 

M 

OD 

C?
z C: 

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CO co 

0

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IV Reactor Vessel, Internals, and Reactor Coolant System 

D1. Steam Generator (Recirculating) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D1.2-g Tube bundle Alloy 600 Up to 3000C Denting/ Chapter XI.M19, "Steam Generator Tubing Yes, 

D1.2.1 Tubes (572°F) Corrosion of Integrity" and effective

secondary- carbon steel tube ness of the 

side water support plate Chapter XI.M2, "Water Chemistry," for AMP is to 

chemistry at PWR secondary water in EPRI TR- be 

5.3-7.2 MPa 102134. evaluated 

For plants where analyses were completed 

in response to NRC Bulletin 88-02 "Rapidly 

Propagating Cracks in SG Tubes," the 

results of those analyses have to be 

reconfirmed for the period of license 

renewal. 

All PWR licensees have committed 

voluntarily to a SG degradation 

management program described in NEI 

97-06; these guidelines are currently under 

NRC staff review. An AMP based on the 

recommendations of staff-approved NEI 

97-06 guidelines, or other alternate 

regulatory basis for SG degradation 

management, is to be developed and 

incorporated in the plant technical 

specifications. 

D1.2-h Tube bundle Carbon Up to 3000C Loss of section A plant-specific aging management Yes, plant 

D1.2.2 Tube support lattice bars steel (572°F) thickness/ program is to be evaluated, specific 

secondary- Flow-accelerated 

side water corrosion 

chemistry at 

5.3-7.2 MPa

0
( ( (

CD 

0

IV Reactor Vessel, Internals, and Reactor Coolant System D1. Steam Generator (Recirculating) 

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation D1.2-i Tube bundle Alloy 600, Chemically Crack initiation Chapter XI.M19, "Steam Generator Tubing Yes, D1.2.3 Tube plugs (mechanical) alloy 690 treated and growth/ Integrity' and effective (Westinghouse) borated water Primary water ness of the 

at stress corrosion Chapter XI.M2, "Water Chemistry," for AMP is to 

temperatures cracking PWR primary water in EPRI TR-105714 be 

up to 3400C evaluated 

(6441F) and All PWR licensees have committed 

15.5 MPa voluntarily to a SG degradation 

management program described in NEI 

97-06; these guidelines are currently under 

NRC staff review. An AMP based on the 

recommendations of staff-approved NEI 

97-06 guidelines, or other alternate 

regulatory basis for SG degradation 

management, is to be developed and 

incorporated in the plant technical 

specifications. D1 .2-j Tube bundle Alloy 600, Chemically Crack initiation Chapter XI.M19, "Steam Generator Tubing Yes, D1.2.3 Tube plugs (mechanical) alloy 690 treated and growth/ Integrity" and effective (Babcock and Wilcox) borated water Primary water ness of the 

at stress corrosion Chapter XI.M2, "Water Chemistry," for AMP is to 

temperatures cracking PWR primary water in EPRI TR-105714 be 

up to 3400C evaluated 

(6440F) and All PWR licensees have committed 15.5 MPa voluntarily to a SG degradation 

management program described in NEI 

97-06; these guidelines are currently under 

NRC staff review. An AMP based on the 

recommendations of staff-approved NEI 

97-06 guidelines or other alternate 

regulatory basis for SG degradation 

management, is to be developed and 

incorporated in the plant technical specifications.

z 

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Reactor Vessel, Internals, and Reactor Coolant System D1. Steam Generator (Recirculatino•

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Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D1.2-k Tube bundle Carbon Up to 3000C Ligament Chapter XI.M19, "Steam Generator Tubing Yes, 

D1.2.4 Tube support plates steel (572-F) cracking/ Integrity' and effective

secondary- Corrosion ness of the 

side water Chapter XL.M2, "Water Chemistry," for AMP is to 

chemistry at PWR secondary water in EPRI TR-1 02134 be 

5.3-7.2 MPa evaluated 

All PWR licensees have committed 

voluntarily to a SG degradation 

management program described in NEI 

97-06; these guidelines are currently under 

NRC staff review. An AMP based on the 

recommendations of staff-approved NEI 

97-06 guidelines, or other alternate 

regulatory basis for SG degradation 

management, is to be developed and 

incorporated in the plant technical 

specifications. 

D1.3-a Upper assembly and Carbon Up to 3000C Loss of material/ A plant-specific aging management Yes, plant 

separators steel (572°F) Flow-accelerated program is to be evaluated. As noted in specific D1.3.1 Feedwater inlet ring and secondary- corrosion Combustion Engineering (CE) Information 

support side water Notice (IN) 90-04 and NRC IN 91-19 and 

chemistry at LER 50-362/90-05-01, this form of 

5.3-7.2 MPa degradation has been detected only in 

I certain CE System 80 steam generators.

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D2. STEAM GENERATOR (ONCE-THROUGH)

D2.1 Pressure Boundary and Structural 

D2.1.1 Upper and Lower Heads 

D2.1.2 Tube Sheets 

D2.1.3 Primary Nozzles 

D2.1.4 Shell Assembly 

D2.1.5 Feed Water and Auxiliary Feed Water Nozzles and Safe Ends 

D2.1.6 Steam Nozzles and Safe Ends 

D2.1.7 Primary Side Drain Nozzles 

D2.1.8 Secondary Side Nozzles (Vent, Drain, and Instrumentation) 

D2.1.9 Primary Manways (Cover and Bolting) 

D2.1.10 Secondary Manways and Handholes (Cover and Bolting) 

D2.2 Tube Bundle 

D2.2.1 Tubes and Sleeves 

D2.2.2 Tube Plugs

April 2001 IV D2-1 NUREG-1801
D2. STEAM GENERATOR (ONCE-THROUGH)

Systems, Structures, and Components 

This section consists of 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. 

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 IV D2-2 April 2001
IV

(

Reactor Vessel, Internals, and Reactor Coolant System D2. Steam Generator (Once-Throunh•

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Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation D2.1 -a Pressure boundary and Low-alloy Chemically Crack initiation Chapter XI.M1, "ASME Section XI No 

structural steel with treated and growth/ Inservice Inspection, Subsections IWB, D2.1.1 Upper and lower heads stainless borated water Stress corrosion IWC, and IWD," for Class 1 components D2.1.2 Tube sheets steel up to 340°C cracking and 

(head) and (6440F) alloy Chapter XI.M2, "Water Chemistry," for 

82/182 PWR primary water in EPRI TR-1 05714 

(tubesheet) 

cladding D2.1-b Pressure boundary and Low-alloy Air, Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

structural steel leaking Boric acid 

D2.1.1 Upper and lower heads chemically corrosion of 

(external surfaces) treated external surfaces 

D2.1.3 Primary nozzles borated water 

and/or steam 

up to 3400C (644°F) 

D2.1 -c Pressure boundary and Low-alloy Chemically Cumulative Fatigue is a time-limited aging analysis Yes, structural steel with treated fatigue damage/ (TLAA) to be performed for the period of TLAA D2.1.3 Primary nozzles stainless borated water Fatigue extended operation, and, for Class 1 

steel up to 3400C components, environmental effects on 

cladding (6440F) and fatigue are to be addressed. See the 

15.2 MPa Standard Review Plan, Section 4.3 "Metal 

Fatigue," for acceptable methods for 

meeting the requirements of 

10 CFR 54.21 (c)(1)(i) and (ii), and for 

addressing environmental effects on 

fatigue. 

See Chapter X.M1 of this report for 

meeting the requirements of 

10 CFR 54.21 (c)(1)(iii).
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IV Reactor Vessel, Internals, and Reactor Coolant System 

D2. Steam Generator (Once-Through) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D2.1 -d Pressure boundary and Carbon Up to 3000C Cumulative Fatigue is a time-limited aging analysis Yes 

structural steel secondary- fatigue damage/ (TLAA) to be performed for the period of TLAA 

D2.1.4 Shell assembly side water Fatigue extended operation. See the Standard 

D2.1.5 Feedwater (FW) and chemistry at Review Plan, Section 4.3 "Metal Fatigue," auxiliary FW (AFW) 5.3-7.2 MPa for acceptable methods for meeting the 

nozzles and safe ends requirements of 10 CFR 54.21 (c). D2.1 -e Pressure boundary and Carbon Up to 3000C Loss of material/ Chapter XI.M1, "ASME Section Xl Yes, structural steel (5720F) General, pitting, Inservice Inspection, Subsections IWB, detection 

D2.1.4 Shell assembly secondary- and crevice IWC, and IWD," for Class 2 components of aging 

side water corrosion and effects is to 

chemistry at be 

5.3-7.2 MPa Chapter XI.M2, "Water Chemistry," for evaluated 

PWR secondary water in EPRI TR-102134 

As noted in NRC Information Notice 90-04, 

general and pitting corrosion of the shell 

exists, the AMP guidelines in Chapter 

XI.M1 may not be sufficient to detect 

general and pitting corrosion, and 

additional inspection procedures may be 

required. 

D2.1 -f Pressure boundary and Carbon Up to 3000C Wall thinning/ Chapter XI.M17, "Flow-Accelerated No 

structural steel (5720F) steam Flow-accelerated Corrosion" 

D2.1.5 FW and AFW nozzles and or secondary- corrosion 

safe ends side water 

D2.1.6 Steam nozzles and safe chemistry at 

ends 5.3-7.2 MPa 

D2.1 -g Pressure boundary and Carbon Up to 3000C Cumulative Fatigue is a time-limited aging analysis Yes, structural steel (572°F) fatigue damage/ (TLAA) to be performed for the period of TLAA 

D2.1.6 Steam nozzles and safe steam Fatigue extended operation. See the Standard 

ends Review Plan, Section 4.3 "Metal Fatigue," 

for acceptable methods for meeting the I _requirements of 10 CFR 54.21 (c). 0 

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IV Reactor Vessel, Internals, and Reactor Coolant System D2. Steam Generator (One.-Thrnuah•h

(

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D2.1-h Pressure boundary and Alloy 600 Chemically Crack initiation A plant-specific aging management Yes, plant 

structural treated and growth/ program is to be evaluated. specific 

D2.1.7 Primary side drain nozzles borated water Primary water 

up to 3400C stress corrosion 

(644TF) and cracking 

15.2 MPa 

D2.1 -i Pressure boundary and Alloy 600 Up to 300'C Crack initiation A plant-specific aging management Yes, plant 

structural (572TF) and growth/ program is to be evaluated. specific 

D2.1.8 Secondary side nozzles secondary- Stress corrosion 

(vent, drain, and side water cracking 

instrumentation) chemistry at 

5.3-7.2 MPa 

D2.1-j Pressure boundary and Carbon Air, Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

structural steel, leaking Boric acid 

D2.1.4 External surfaces of shell low-alloy chemically corrosion of 

assembly steel treated external surfaces 

D2.1.5 FW and AFW nozzles and borated water 

safe ends and/or steam 

D2.1.6 Steam nozzles and safe at 

ends temperatures 

D2.1.9 Primary manways up to 3400C 

(cover and bolting) (6440F) 

D2.1.10 Secondary manways and 

handholes 

(cover and bolting) 

D2.1 -k Pressure boundary and Low-alloy Air, with metal Loss of preload/ Chapter XI.M1 8, "Bolting Integrity" No 

structural steel temperatures Stress relaxation 

D2.1.9 Primary manways up to 3400C 

D2.1.10 (bolting only) (6440F) 

Secondary manways and 

handholes 

I (bolting only)
IV Reactor Vessel, Internals, and Reactor Coolant System D2. Stenm G;•n~rntor ((Oni•-Thrnunh•

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D2.1-1 Pressure boundary and Carbon Air, Wall thinning/ Chapter XI.M1, "ASME Section Xi No 

structural steel leaking Erosion Inservice Inspection, Subsections IWB, D2.1.10 Secondary manways and secondary- IWC, and IWD," for Class 2 components 

handholes (cover only) side water 

and/or steam 

at 

temperatures 

up to 3000C (572°F) 

D2.2-a Tube bundle (Babcock and Alloy 600 Chemically Crack initiation Chapter XI.M19, "Steam Generator Tubing Yes, Wilcox) treated and growth/ Integrity" and effective

D2.2.1 Tubes and sleeves borated water Primary water ness of the 

up to 3400C stress corrosion Chapter XI.M2, "Water Chemistry," for AMP is to 

(6440 F) and cracking PWR primary water in EPRI TR-105714 be 

15.2 MPa evaluated 

All PWR licensees have committed 

voluntarily to a SG degradation 

management program described in NEI 

97-06; these guidelines are currently under 

NRC staff review. An AMP based on the 

recommendations of staff-approved NEI 

97-06 guidelines, or other alternate 

regulatory basis for SG degradation 

management, is to be developed and 

incorporated in the plant technical 

specifications.

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Reactor Vessel, Internals, and Reactor Coolant System D2. Steam Generator (Once.Throuah•

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0 

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D2.2-b Tube bundle (Babcock and Alloy 600 Up to 3000C Crack initiation Chapter XI.M19, "Steam-Generator Tubing Yes, 

Wilcox) (572°F) and growth/ Integrity" and effective

D2.2.1 Tubes and sleeves secondary- Outer diameter ness of the 

side water stress corrosion Chapter XI.M2, "Water Chemistry," for AMP is to 

chemistry at cracking PWR secondary water in EPRI TR-102134 be 

5.3-7.2 MPa evaluated 

All PWR licensees have committed 

voluntarily to a SG degradation 

management program described in NEI 

97-06; these guidelines are currently under 

NRC staff review. An AMP based on the 

recommendations of staff-approved NEI 

97-06 guidelines, or other alternate 

regulatory basis for SG degradation 

management, is to be developed and 

incorporated in the plant technical 

specifications. 

D2.2-c Tube bundle (Babcock and Alloy 600 Up to 3000C Crack initiation Chapter XI.M1 9, "Steam Generator Tubing Yes, 

Wilcox) (572°F) and growth/ Integrity" and effective

D2.2.1 Tubes and sleeves secondary- Intergranular ness of the 

side water attack Chapter XI.M2, "Water Chemistry," for AMP is to 

chemistry at PWR secondary water in EPRI TR-102134 be 

5.3-7.2 MPa evaluated 

All PWR licensees have committed 

voluntarily to a SG degradation 

management program described in NEI 

97-06; these guidelines are currently under 

NRC staff review. An AMP based on the 

recommendations of staff-approved NEI 

97-06 guidelines, or other alternate 

regulatory basis for SG degradation 

management, is to be developed and 

incorporated in the plant technical 

I specifications.
Reactor Vessel, Internals, and Reactor Coolant System D2. Steam Generator (Once.Thrnuah•

0 

0 

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D2.2-d Tube bundle (Babcock and Alloy 600 Up to 30000 Loss of section Chapter XI.M19, "Steam Generator Tubing Yes, 

Wilcox) (572°F) thickness/ Integrity" effective

D2.2.1 Tubes and sleeves secondary- Fretting and wear ness of the 

side water All PWR licensees have committed AMP is to 

chemistry at voluntarily to a SG degradation be 

5.3-7.2 MPa management program described in NEI evaluated 

97-06; these guidelines are currently under 

NRC staff review. An AMP based on the 

recommendations of staff-approved NEI 

97-06 guidelines, or other alternate 

regulatory basis for SG degradation 

management, is to be developed and 

incorporated in the plant technical 

specifications. 

D2.2-e Tube bundle (Babcock and Alloy 600 Up to 3000C Cumulative Fatigue is a time-limited aging analysis Yes, 

Wilcox) (572°F) fatigue damage/ (TLAA) to be performed for the period of TLAA 

D2.2.1 Tubes and sleeves secondary- Fatigue license renewal. See the Standard Review 

side water Plan, Section 4.3 "Metal Fatigue," for 

chemistry at acceptable methods for meeting the 

1 1 15.3-7.2 MPa I requirements of 10 CFR 54.21(c).

K
(

IV Reactor Vessel, Internals, and Reactor Coolant System D2. Steam Generator (Once.Thrnuah•

(

"C? V 

0 

0.i Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D2.2-f Tube bundle Alloy 600, Chemically Crack initiation Chapter XI.M1 9, "Steam Generator Tubing Yes, 

D2.2.2 Tube plugs (mechanical) alloy 690 treated and growth/ Integrity' and effective

(Westinghouse) borated water Primary water ness of the 

at stress corrosion Chapter XI.M2, "Water Chemistry," for AMP is to 

temperatures cracking PWR primary water in EPRI TR-1 05714 be 

up to 3400C evaluated 

(644°F) and All PWR licensees have committed 

15.5 MPa voluntarily to a SG degradation 

management program described in NEI 

97-06; these guidelines are currently under 

NRC staff review. An AMP based on the 

recommendations of staff-approved NEI 

97-06 guidelines, or other alternate 

regulatory basis for SG degradation 

management, is to be developed and 

incorporated in the plant technical 

specifications. D2.2-g Tube bundle Alloy 600, Chemically Crack initiation Chapter XI.M1 9, "Steam Generator Tubing Yes, 

D2.2.2 Tube plugs (mechanical) alloy 690 treated and growth/ Integrity' and effective

(Babcock and Wilcox) borated water Primary water ness of the 

at stress corrosion Chapter XI.M2, "Water Chemistry," for AMP is to 

temperatures cracking PWR primary water in EPRI TR-1 05714 be 

up to 3400C evaluated' 

(6440F) and All PWR licensees have committed 

15.5 MPa voluntarily to a SG degradation 

management program described in NEI 

97-06; these guidelines are currently under 

NRC staff review. An AMP based on the 

recommendations of staff-approved NEI 

97-06 guidelines, or other alternate 

regulatory basis for SG degradation 

management, is to be developed and 

incorporated in the plant technical 

specifications.

z C 

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Z! This Page Intentionally Left Blank 

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CHAPTER V 

ENGINEERED SAFETY FEATURES

April 2001 V-i NUREG-1801
This Page Intentionally Left Blank

NUREG-1801 V-ii April 2001

I I
MAJOR PLANT SECTIONS

A. Containment Spray System (Pressurized Water Reactor) 

B. Standby Gas Treatment System (Boiling Water Reactor) 

C. Containment Isolation Components 

Di. Emergency Core Cooling System (Pressurized Water Reactor) 

D2. Emergency Core Cooling System (Boiling Water Reactor) 

E. Carbon Steel Components

April 2001 V-iii NUREG-1 801
This Page Intentionally Left Blank

NUREG-1801 V-iv April 2001

I I
A. CONTAINMENT SPRAY SYSTEM (PRESSURIZED WATER REACTOR) 

A.1 Piping, Fittings and Miscellaneous Items 

A.1.1 Piping and Fittings up to Isolation Valve 

A.1.2 Flow Orifice/Elements 

A.1.3 Temperature Elements/Indicators 

A.1.4 Bolting 

A.1.5 Eductors 

A.2 Headers and Spray Nozzles 

A.2.1 Piping and Fittings 

A.2.2 Flow Orifice 

A.2.3 Headers 

A.2.4 Spray Nozzles 

A.3 Pumps 

A.3.1 Bowl/Casing 

A.3.2 Bolting 

A.4 Valves (Hand, Control, Check, Motor-Operated, and Containment Isolation) in 

Containment Spray System 

A.4.1 Body and Bonnet 

A.4.2 Bolting 

A.5 Valves (Hand, Control, and Containment Isolation) in Headers and Spray Nozzles 

A.5.1 Body and Bonnet 

A.5.2 Bolting 

A.6 Containment Spray Heat Exchanger 

A.6.1 Bonnet/Cover 

A.6.2 Tubing 

A.6.3 Shell 

A.6.4 Case/Cover 

A.6.5 Bolting

April 2001 V A-1 NUREG-1801
A. CONTAINMENT SPRAY SYSTEM (PRESSURIZED WATER REACTORS)

Systems, Structures, and Components 

This section comprises 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 and orifices, pumps, spray nozzles, eductors, and 

the containment spray system heat exchanger (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, or are subject to replacement based on qualified life or specified time period. Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in V.E. 

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 V A-2 April 2001
( (

-o i\)

V Engineered Safety Features 

A. Containment Spray System Pressurized Water Reactor 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A.1-a Piping, fittings and Stainless Chemically Crack initiation Chapter XI.M2, "Water Chemistry," for No miscellaneous items steel treated and growth/ PWR primary water in EPRI TR-1 05714 A.1.1 Piping and fittings up to borated water Stress corrosion 

isolation valve at cracking A. 1.2 Flow orifice/elements temperature A. 1 .3 Temperature elements/ < 930c 

indicators (200_F) A.1-b Containment spray system Carbon Air, Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

A.1.4 Bolting steel, leaking Boric acid 

low-alloy chemically corrosion 

steel treated 

borated water A.1 -c Containment spray system Stainless Chemically Crack initiation Chapter XI.M2, "Water Chemistry," for No A.1.5 Eductors steel treated and growth/ PWR primary water in EPRI TR-105714 

borated water Stress corrosion 

at cracking 

temperature 

< 930C 

I (200-F) A.2-a Headers and spray nozzles Carbon Air Loss of material/ A plant-specific aging management Yes, plant A.2.1 Piping and fittings steel General corrosion program is to be evaluated. specific A.2.2 Flow orifice 

A.2.3 Headers 

A.2.4 Spray nozzles 

A.3-a Pump Stainless Chemically Crack initiation Chapter XI.M2, "Water Chemistry," for No A.3.1 Bowl/casing steel treated and growth/ PWR primary water in EPRI TR-105714 

borated water Stress corrosion 

at cracking 

temperature 

< 930C 

MW00F) 

A.3-b Pump Carbon Air, Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No A.3.2 Bolting steel, leaking Boric acid 

low-alloy chemically corrosion 

steel treated borated water I

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A. Containment Spray System Pressurized Water Reactor 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A.4-a Valves (hand, Control, check, Stainless Chemically Crack initiation Chapter XI.M2, "Water Chemistry," for No motor-operated, and steel treated and growth/ PWR primary water in EPRI TR-105714 

containment isolation) in borated water Stress corrosion 

containment spray system at cracking A.4.1 Body and bonnet temperature 

< 930C 

(2000F) A.4-b Valves (hand, control, check, Carbon Air, Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

motor-operated, and steel, leaking Boric acid 

containment isolation) in low-alloy chemically corrosion 

containment spray system steel treated A.4.2 Bolting borated water A.5-a Valves (hand, control and Carbon Air Loss of material/ A plant-specific aging management Yes, plant containment isolation) in Steel General corrosion program is to be evaluated. specific headers and spray nozzles 

A.5.1 Body and bonnet 

A.5-b Valves (hand, control and Carbon Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No containment isolation) in steel, chemically Boric acid 

headers and spray nozzles low-alloy treated corrosion A.5.2 Bolting steel borated water A.6-a Containment spray heat Carbon Chemically Loss of material/ Chapter XI.M20, "Open-Cycle Cooling No exchanger (serviced by open- steel, treated General and Water System" cycle cooling water) stainless borated water microbiologically A.6.1 Bonnet/cover steel on one side influenced 

A.6.2 Tubing and open- corrosion and 

A.6.3 Shell cycle cooling biofouling A.6.4 Case/cover water (raw 

water) on the other side

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V Engineered Safety Features 

A. Containment Spray System Pressurized Water Reactor_ 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A.6-b Containment spray heat Carbon Chernically Buildup'of deposit/ Chapter XI.M20, "Open-Cycle Cooling No 

exchanger (serviced by open- steel, treated Biofouling Water System" cycle cooling water) stainless borated water 

A.6.2 Tubing steel on one side 

and open

cycle cooling 

water (raw 

water) on the 

I other side 

A.6-c Containment spray heat Carbon Clhemically Loss of material/ Chapter XI.M21, "Closed-Cycle Cooling No 

exchanger (serviced by closed- steel, treated General, pitting Water System" 

cycle cooling water) stainless borated water and crevice 

A.6.1 Bonnet/cover steel on tube side corrosion 

A.6.2 Tubing and closed

A.6.3 Shell cycle cooling A.6.4 Case/cover water on shell 

I_ side 

A.6-d Containment spray heat Carbon Air, leaking Loss of material/ Chapter XI.M1 0, "Boric Acid Corrosion" No 

exchanger steel, chemically Boric acid 

A.6.3 Shell low-alloy treated corrosion 

A.6.4 Case/cover (external steel borated water 

surfaces) 

A.6.5 Bolting

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B. STANDBY GAS TREATMENT SYSTEM (BOILING WATER REACTOR)

B.1 Ductwork 

B.1.1 Duct, Fittings, Access Doors, and Closure Bolts 

B.1.2 Equipment Frames and Housing 

B.1.3 Seals between Ducts and Fan 

B.1.4 Seals in Dampers and Doors 

B.2 Filters 

B.2.1 Housing and Supports 

B.2.2 Elastomer Seals

April 2001 V B-1 NUREG-1801
B. STANDBY GAS TREATMENT SYSTEM (BOILING WATER REACTOR) 

Systems, Structures, and Components 

This section comprises the standby gas treatment system found in boiling water reactors 

(BWRs) and consist 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. 

With respect to charcoal absorber filters, these items are to be addressed consistent with the 

NRC position on consumables, provided in the NRC letter from Christopher I. Grimes to 

Douglas J. Walters of 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). The 

application is to identify the standards that are relied on for replacement as part of the 

methodology description, for example, NFPA standards for fire protection equipment. 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in V.E. 

System Interfaces 

There are no system interfaces with the standby gas treatment system addressed in this 

section.

NUREG-1 801 V B-2 April 2001
(

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(

Engineered Safety Features B. Standby Gas Treatment Systems (Boilina Water Reactor~

(

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B.1-a Ductwork Carbon Internal: Loss of material/ A plant-specific aging management Yes, B.1.1 Fittings, access doors, and steel occasional General corrosion program is to be evaluated, plant closure bolts exposure to specific B.1.2 Equipment frames and moist air; 

housing external: 

ambient plant 

air 

environment 

B.1-b Ductwork Elastomer Internal: Hardening and A plant-specific aging management Yes, B.1.3 Seals between ducts and fan (Neoprene) occasional loss of strength/ program is to be evaluated, plant B.1.4 Seals in dampers and doors exposure to Elastomer specific 

moist air; degradation 

external: 

ambient plant 

air 

I environment 

B.2-a Filters Carbon Internal: Loss of material/ A plant-specific aging management Yes, B.2.1 Housing and supports steel occasional General corrosion program is to be evaluated, plant 

exposure to specific 

moist air; 

external: 

ambient plant 

air 

environment 

B.2-b Filters Elastomers Occasional Hardening and A plant-specific aging management Yes, B.2.2 Elastomer seals (Neoprene exposure to loss of strength/ program is to be evaluated, plant 

and similar moist air Elastomer specific materials) degradation

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C. CONTAINMENT ISOLATION COMPONENTS

C.1 Isolation Barriers 

C.1.1 Valve Body and Bonnet 

C.1.2 Pipe Penetrations

April 2001 V C-1 NUREG-1801
C. CONTAINMENT ISOLATION COMPONENTS

Systems, Structures, and Components 

This section comprises 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 Radioactive

Waste-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 ll.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 carbon steel 

components are included in V.E. 

System Interfaces 

There are no system interfaces with the containment isolation components addressed in this 

section.

NUREG-1801 V C-2 April 2001

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V Engineered Safety Features 

C. Containment Isolation Com ponents 

Structure and/or Aging Effect! Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

0.1-a BWR and PWR isolation Carbon steel Inside Loss of material/ A plant-specific aging management Yes, plant barriers and low- surface: General, pitting, program is to be evaluated. See IN 85- specific C.1.1 Valve body and bonnet alloy steel treated or raw crevice and 30 for evidence of microbiologically C.1.2 Pipe penetrations (piping water, liquid microbiologically influenced corrosion. 

between two isolation waste; outside influenced 

valves) surface: corrosion and 

ambient air biofouling C.1-b BWR and PWR isolation Stainless Inside Loss of material/ A plant-specific aging management Yes, plant barriers steel surface: Pitting, crevice program is to be evaluated. See IN 85- specific C.1.1 Valve body and bonnet treated or raw and 30 for evidence of microbiologically 0.1.2 Pipe penetrations (piping water, liquid microbiologically influenced corrosion. 

between two isolation waste; outside influenced 

valves) surface: corrosion and 

ambient air biofouling I

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D1. EMERGENCY CORE COOLING SYSTEM (PRESSURIZED WATER REACTOR) 

D1.1 Piping and Fittings 

D1.1.1 Core Flood System (CFS) 

D1.1.2 Residual Heat Removal (RHR) or Shutdown Cooling (SDC) 

D1.1.3 High-Pressure Safety Injection (HPSI) 

D1.1.4 Low-Pressure Safety Injection (LPSI) 

D1.1.5 Connecting lines to Chemical and Volume Control System (CVCS) 

and Spent Fuel Pool (SFP) Cooling 

D1.1.6 Lines to Emergency Sump 

D1.1.7 Bolting for Flange Connections 

D1.2 HPSI and LPSI Pumps 

D13.2.1 Bowl/Casing 

D1.2.2 Bolting 

D1.2.3 Orifice 

D1.3 RWT Circulation Pump 

D1.3.1 Bolting 

D1.4 Valves 

D13.4.1 Body and Bonnet 

D1.4.2 Bolting 

D1.5 Heat Exchangers (RCP, HPSI, and LPSI Pump Seals; and RHR or SDC) 

D1.5.1 Bonnet/Cover 

D1.5.2 Tubing 

D13.5.3 Shell 

D1.5.4 Case/Cover 

D13.5.5 Bolting 

D1.6 Heat Exchangers (RWT Heating) 

D1.6.1 Bonnet/Cover 

D1.6.2 Tubing 

D1.6.3 Shell 

D1.6.4 Bolting 

D1.7 Safety Injection Tank (Accumulator) 

D1.7.1 Shell 

D1.7.2 Manway 

D1.7.3 Penetrations/Nozzles

April 2001 V 131-1 NUREG-1801
D1.8 Refueling Water Tank (RWT)

D1.8.1 

D1.8.2 

D1.8.3 

D1.8.4 

D1.8.5

NUREG-1 801

Shell 

Manhole 

Penetrations/Nozzles 

Bolting 

Buried Portion of Tank 

V D1-2 April 2001

I I
D1. EMERGENCY CORE COOLING SYSTEM (PRESSURIZED WATER REACTORS) 

Systems, Structures, and Components 

This section comprises the emergency core cooling systems for pressurized water reactors 

(PWRs) designed to cool the reactor core and provide safe shutdown following a design basis 

accident. They consist of the core flood (CFS), residual heat removal (RHR) (or shutdown 

cooling (SDC)), high-pressure safety injection (HPSI), low-pressure safety injection (LPSI), and 

spent fuel pool (SFP) cooling systems; the lines to the chemical and volume control system 

(CVCS); the emergency sump, the HPSI and LPSI pumps; the pump seal coolers; the RHR 

heat exchanger; and the refueling water tank (RWT). Stainless steel components are not 

subject to significant general, pitting, and crevice corrosion in borated water and, therefore, for 

these stainless steel components, loss of material due to corrosion in borated water is not 

included in this section. 

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, or are subject to replacement based on qualified life or specified time period. Accordingly, they are not subject to an aging management review, pursuant to 10 CFR S54.21 (a) (1). 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in V.E. 

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).

April 2001 V D1-3 NUREG-1 801
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Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D1.1-a Piping and fittings Stainless Chemically Crack initiation Chapter XI.M2, "Water Chemistry," for No 

D1.1.1 Core flood system steel treated and growth/ PWR primary water in EPRI TR-1 05714 

D1.1.2 Residual heat removal or borated water Stress corrosion 

shutdown cooling at cracking 

D1.1.3 High-pressure safety injection temperature 

D1.1.4 Low-pressure safety injection < 93°C 

D1.1.5 Connecting lines to chemical (2000F) 

and volume control system 

D1.1.6 Spent fuel pool cooling 

lines to emergency sump 

D1.1-b Piping and fittings Cast Chemically Loss of fracture Chapter XI.M12, "Thermal Aging No 

D1.1.1 Core flood system austenitic treated toughness/ Embrittlement of Cast Austenitic 

D1.1.2 Residual heat removal or stainless borated water Thermal aging Stainless Steel (CASS)" 

shutdown cooling steel at embrittlement 

D1.1.3 High-pressure safety injection temperature 

D1.1.4 Low-pressure safety injection 25-3400C 

D1.1.5 Connecting lines to chemical (77-6440F) 

and volume control system 

D1.1.6 Spent fuel pool cooling 

lines to emergency sump 

D1.1-c Piping and fittings Stainless Chemically Cumulative Fatigue is a time-limited aging analysis Yes, 

D1.1.1 Core flood system steel treated fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

D1.1.2 Residual heat removal or borated water Fatigue extended operation. See the Standard 

shutdown cooling at Review Plan, Section 4.3, "Metal 

D1.1.3 High-pressure safety injection temperature Fatigue" for acceptable methods for 

D1.1.4 Low-pressure safety injection < 93°C meeting the requirements of 10 CFR 

I (2000F) 54.21 (c). 

D1.1-d Piping and fittings Nuts: Air, Loss of material/ Chapter XI.M1 0, "Boric Acid Corrosion" No 

D1.1.7 Bolting for flange connections carbon leaking Boric acid 

in items D1.1.1 through steel; chemically corrosion 

D1.1.6 bolts/studs: treated 

I alloy steel borated water I I I

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D1.2-a 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D1.2.1 

HPSI 

Bowl/casing 

and LPSI purnmps Stainless Chemically Crack initiation Chapter XI.M2, "Water Chemistry," for No steel, treated and growth/ PWR primary water in EPRI TR-1 05714 

carbon steel borated water Stress corrosion 

with at cracking stainless temperature 

steel < 931C cladding (2000F) D1.2-b HPSI and LPSI pumps Casing: Air, Loss of material/ Chapter XI.M1 0, "Boric Acid Corrosion" No D1.2.1 Bowl/casing (external carbon steel leaking Boric acid surfaces) with chemically corrosion D1.2.2 Bolting stainless treated 

steel borated water 

cladding; 

nuts: carbon 

steel; 

bolts/studs: 

alloy steel D1.2-c 

D1.2.3 

HPSI 

Orifice 

and LPSI pumps Stainless Chemically Loss of material/ A plant-specific aging management Yes, plant (miniflow recirculation) steel treated Erosion program is to be evaluated for erosion of specific borated water the orifice due to extended use of the at centrifugal HPSI pump for normal temperature charging. See LER 50-275/94-023 for 

< 93TC evidence of erosion. 

(2000 F) D1.3-a RWT circulation pump Nuts: Air; Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No D1.3.1 Bolting carbon leaking Boric acid 

steel; chemically corrosion 

bolts/studs: treated 

D1.4-a Valves alloy steel borated water (check, control, hand, Stainless Chemically Cumulative Fatigue is a time-limited aging analysis Yes, motor operated, and relief steel, treated fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

D1.4.1 

valves) carbon steel borated water Fatigue extended operation. See the Standard Body and bonnet with at Review Plan, Section 4.3, "Metal stainless temperature Fatigue" for acceptable methods for steel < 93°C meeting the requirements of 10 CFR cladding (200oF) 54.21 (c). I
V Engineered Safety Features 

rli Imarngn-i Conre (onnlinn S stem tPressurized Water Reactorl

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D1.4-b Valves (check, control, hand, Stailless Chemically Crack initiation Chapter XI.M2, "Water Chemistry," for No 

motor operated, and relief steel, treated and growth/ PWR primary water in EPRI TR-1 05714 

valves) carbon steel borated water Stress corrosion 

D1.4.1 Body and bonnet with at cracking 

stainless temperature 

steel < 930C 

cladding (2000F) 

D1.4-c Valves (check, control, hand, Body and Air, Loss of material/ Chapter XI.M1O, "Boric Acid Corrosion" No 

motor operated, and relief bonnet: leaking Boric acid 

valves) carbon chemically corrosion 

D1.4.1 Body and bonnet (external steel; nuts: treated 

surfaces) carbon borated water 

D1.4.2 Bolting steel; 

bolts/studs: 

alloy steel 

D1.5-a Heat exchangers (reactor Bonnet/ Chemically Loss of material/ Chapter XI.M21, "Closed-Cycle Cooling No 

coolant pump seal, HPSI pump cover and treated Pitting and crevice Water System" 

seal, LPSI pump seal, RHR or tubing: borated water; corrosion 

SDC) stainless and 

D1.5.1 Bonnet/cover steel; shell: treated 

D1.5.2 Tubing carbon component 

D1.5.3 Shell steel; cooling water 

D1.5.4 Case/cover case/cover: 

I_ cast iron 

D1.5-b Heat exchangers (RCP seal, Shell: Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

HPSI pump seal, LPSI pump carbon chemically Boric acid 

seal, RHR or SDC) steel; treated corrosion 

D1.5.3 Shell case/cover: borated water 

D1.5.4 Case/cover (external cast iron; 

surfaces) nuts: carbon 

D1.5.5 Bolting steel; 

bolts/studs: 

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D1.6-a Heat exchanger (RWT heating) Bonnet' Chemically - Loss of material/ Chapter XI.M21, "Closed-Cycle Cooling No 

serviced by closed-cycle cover and treated Pitting and crevice Water System" cooling water tubing: borated water corrosion 

D1.6.1 Bonnet/cover stainless and treated 

D1.6.2 Tubing steel; shell: component 

D1.6.3 Shell carbon steel cooling water 

D1.6-b Heat exchanger (RWT Heating) Carbon Chemically Loss of material/ Chapter XI.M20, "Open-Cycle Cooling No 

serviced by open-cycle cooling steel, treated General (carbon Water System" 

water stainless borated water steel only), pitting, D1.6.1 Bonnet/cover steel on one side crevice, and 

D1.6.2 Tubing and microbiologically D1.6.3 Shell open-cycle influenced 

cooling water corrosion and 

(raw water) on biofouling the other side 

D1.6-c Heat exchanger (RWT heating) Carbon Chermically Buildup of deposit/ Chapter XI.M20, "Open-Cycle Cooling No 

serviced by open-cycle cooling steel, treated Biofouling Water System" 

water stainless borated water 

D1.6.2 Tubing steel on one side 

and 

open-cycle 

cooling water 

(raw water) on 

the other side 

D1.6-d Heat exchanger (RWT heating) Shell: Air, leaking Loss of Material/ Chapter XI.M1 0, "Boric Acid Corrosion" No 

D1.6.3 Shell (external surface) carbon chemically Boric acid 

D1.6.4 Bolting steel; nuts: treated corrosion 

carbon borated water 

steel; 

bolts/studs: 

I alloy steel I I

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 01.7-a Safety injection tank Carbon Air, leaking Loss of material/ Chapter Xl.M10, "Boric Acid Corrosion" No 

(accumulator) steel with chemically Boric acid 

D1.7.1 Shell stainless treated corrosion 

D1.7.2 Manway steel borated water 

D1.7.3 Penetrations/ cladding nozzles (all external surface) D1.7-b Safety injection tank Carbon Chemically Crack initiation Chapter XI.M2, "Water Chemistry," for No (accumulator) steel with treated and growth/ PWR primary water in EPRI TR-105714 

D1.7.3 Penetrations/nozzles stainless borated water Stress corrosion 

steel at cracking 

cladding temperature 

< 93TC (2000F) 

D1.8-a Refueling water tank (RWT) Stainless Chemically Crack initiation Chapter XI.M2, "Water Chemistry," for No D1.8.1 Shell steel treated and growth/ PWR primary water in EPRI TR-1 05714 

D1.8.2 Manhole borated water Stress corrosion 

D1.8.3 Penetrations/nozzles at cracking 

temperature 

< 93°C 

(2000F) D1.8-b Refueling water tank (RWT) Nuts: Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

D1.8.4 Bolting carbon chemically Boric acid 

steel; treated corrosion 

bolts/studs: borated water 

alloy steel 

D1.8-c Refueling water tank (RWT) Stainless Moisture, Loss of material/ A plant-specific aging management Yes, plant D1.8.5 Buried portion of tank (outer steel water Pitting and crevice program is to be evaluated for pitting and specific surface) corrosion crevice corrosion of tank bottom 

because moisture and water can egress 

under the tank due to cracking of the perimeter seal from weathering.
D2. EMERGENCY CORE COOLING SYSTEM (BWR)

D2.1 Piping and Fittings 

D2.1.1 High Pressure Coolant Injection (HPCI) 

D2.1.2 Reactor Core Isolation Cooling (RCIC) 

D2.1.3 High-Pressure Core Spray (HPCS) 

D2.1.4 Low-Pressure Core Spray (LPCS) 

D2.1.5 Low-Pressure Coolant Injection (LPCI) and 

Residual Heat Removal (RHR) 

D2.1.6 Lines to Suppression Chamber (SC) 

D2.1.7 Lines to Drywell and Suppression Chamber Spray System (DSCSS) 

D2.1.8 Automatic Depressurization System (ADS) 

D2.1.9 Lines to HPCI and RCIC Pump Turbine 

D2.1.10 Lines from HPCI and RCIC Pump Turbines to Condenser 

D2.2 Pumps (HPCS or HPCI Main and Booster, LPCS, LPCI or RHR, and RCIC) 

D2.2.1 Bowl/Casing 

D2.2.2 Suction Head 

D2.2.3 Discharge Head 

D2.3 Valves (Check, Control, Hand, Motor Operated, and Relief Valves) 

D2.3.1 Body and Bonnet 

D2.4 Heat Exchangers (RHR and LPCI) 

D2.4.1 Tubes 

D2.4.2 Tubesheet 

D2.4.3 Channel Head 

D2.4.4 Shell 

D2.5 Drywell and Suppression Chamber Spray System (DSCSS) 

D2.5.1 Piping and Fittings 

D2.5.2 Flow Orifice 

D2.5.3 Headers 

D2.5.4 Spray Nozzles

April 2001 V D2-1 NUREG-1801
D2. EMERGENCY CORE COOLING SYSTEM (BOILING WATER REACTORS) 

Systems, Structures, and Components 

This section comprises the emergency core cooling systems for boiling water reactors (BWRs) 

designed to cool the reactor core and provide safe shutdown following a design basis accident. 

They consist of the high-pressure coolant injection (HPCI), reactor core isolation cooling 

(RCIC), high-pressure core spray (HPCS), automatic depressurization (ADS), low-pressure 

core spray (LPCS), low-pressure coolant injection (LPCI) and residual heat removal (RHR) 

systems, including various pumps and valves; the RHR heat exchangers; and the drywell and 

suppression chamber spray system (DSCSS). 

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 Standard. 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, or are subject to replacement based on qualified life or specified time period. 

Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in V.E. 

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 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 V D2-2 April 2001
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Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D2.1-a Piping and fittings Carbon 25-:288°C Loss of material/ Chapter XI.M2, "Water Chemistry," for Yes, 

D2.1.1 High-pressure coolant steel (77-550OF) General, pitting, BWR water in BWRVIP-29 (EPRI TR- detection of 

injection demineralized and crevice 103515) aging 

D2.1.2 Reactor core isolation cooling water corrosion effects is to 

D2.1.3 High-pressure core spray The AMP is to be augmented by verifying be 

D2.1.4 Low-pressure core spray the effectiveness of water chemistry evaluated 

D2.1.5 Low-pressure coolant control. See Chapter XI.M32, "One-Time 

injection and residual heat Inspection," for an acceptable verification 

removal program. 

D2.1.6 Lines to suppression 

chamber 

D2.1.7 Lines to drywell and 

suppression chamber spray 

system 

D2.1-b Piping and fittings Carbon 25-2880C Cumulative Fatigue is a time-limited aging analysis Yes, 

D2.1.1 HPCI steel, (77-550OF) fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

stainless demineralized Fatigue extended operation. See the Standard 

steel water Review Plan, Section 4.3, "Metal 

Fatigue" for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c). 

D2.1-c Piping and fittings Stainless 25-2880C Crack initiation Chapter XI.M7, "BWR Stress Corrosion No 

D2.1.1 HPCI steel (77-5500 F) and growth/ Cracking," and Chapter XI.M2, "Water 

D2.1.2 RCIC demineralized Stress corrosion Chemistry," for BWR water in 

D2.1.3 HPCS water cracking, BWRVIP-29 (EPRI TR-103515) 

D2.1.4 LPCS intergranular 

D2.1.5 LPCI and RHR stress corrosion 

D2.1.6 Lines to SC cracking 

D2.1.7 Lines to DSCSS

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u1. Emergency Gore Cooling s, fstem (Esomi g Water Reactor) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D2.1-d Piping and fittings Cast 254288°C Loss of fracture Chapter XI.M12, 'Thermal Aging No 

D2.1.1 HPCI austenitic (77-5500 F) toughness/ Embrittlement of Cast Austenitic 

D2.1.2 RCIC stainless demineralized Thermal aging Stainless Steel (CASS)" 

D2.1.3 HPCS steel water embrittlement 

D2.1.4 LPCS 

D2.1.5 LPCI and RHR 

D2.1.6 Lines to SC 

D2.1.7 Lines to DSCSS 

D2.1-e Piping and fittings Carbon Moist Loss of material/ A plant-specific aging management Yes, plant D2.1.8 Automatic depressurization steel, containment General (carbon program is to be evaluated, specific 

system stainless atmosphere steel only), pitting, 

steel (air/nitrogen), and crevice 

steam, or corrosion 

demineralized 

water 

D2.1-f Piping and fittings Carbon Air and steam Wall thinning/ Chapter XI.M1 7, "Flow-Accelerated No 

D2.1.9 Lines to HPCI and RCIC steel up to 3200C Flow-accelerated Corrosion" 

pump turbine (608OF) corrosion 

D2.1.10 Lines from HPCI and RCIC 

pump turbine to torus or 

I wetwell 

D2.2-a Pumps HPCS or HPCI main Carbon 25-2880C Loss of material/ Chapter XI.M2, "Water Chemistry," for Yes, 

and booster, LPCS, LPCI or steel (77-550°F) General, pitting, BWR water in BWRVIP-29 (EPRI TR- detection of 

RHR, and RCIC casting, demineralized and crevice 103515) aging D2.2.1 Bowl/casing carbon water corrosion effects is to 

D2.2.2 Suction head steel The AMP is to be augmented by verifying be 

D2.2.3 Discharge head the effectiveness of water chemistry evaluated 

control. See Chapter XI.M32, "One-Time 

Inspection," for an acceptable verification 

program. 

D2.3-a Valves (check, control, hand, Carbon 25-288°C Wall thinning/ Chapter XI.M1 7, "Flow-Accelerated No 

motor operated, and relief steel (77-550OF) Flow-accelerated Corrosion" 

valves) forging, demineralized corrosion 

D2.3.1 Body and bonnet carbon water 

steel 

1casting III

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation "02.3-b Valves (check, control, hand, Carbon 25-2880C Loss of material/ Chapter XI.M2, "Water Chemistry," for Yes, motor operated, and relief steel (77-5500 F) General, pitting, BWR water in BWRVIP-29 (EPRI TR- detection of valves) forging, demineralized and crevice 103515) aging D2.3.1 Body and bonnet carbon water corrosion effects is to 

steel The AMP is to be augmented by be 

casting verification of its effectiveness of the evaluated 

water chemistry control. See Chapter XI.M32, "One-Time Inspection," for an 

acceptable verification program. D2.3-c Valves (check, control, hand, Stainless 25-288°C Crack initiation Chapter XI.M7, "BWR Stress Corrosion No 

motor operated, and relief steel (77-550OF) and growth/ Cracking," and Chapter XI.M2, "Water valves) forging, demineralized Stress corrosion Chemistry," for BWR water in D2.3.1 Body and bonnet stainless water cracking BWRVIP-29 (EPRI TR-103515) 

steel casting 

D2.4-a Heat exchangers (RHR and Carbon Demineralized Loss of material/ Chapter XI.M20, "Open-Cycle Cooling No LPCI) (serviced by open-cycle steel, water on one General (carbon Water System" cooling water) stainless side; open- steel only), pitting, D2.4.1 Tubes steel cycle cooling crevice, and 

D2.4.2 Tubesheet water (raw microbiologically D2.4.3 Channel head water) on the influenced 

D2.4.4 Shell other side corrosion, and 

biofouling D2.4-b Heat exchangers (RHR and Carbon Demineralized Buildup of deposit/ Chapter XI.M20, "Open-Cycle Cooling No LPCI) (serviced by open-cycle steel, water on one Biofouling Water System" cooling water) stainless side; open D2.4.1 Tubes steel cycle cooling 

water (raw 

water) on the 

other side

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D2.4-c Heat exchangers (RHR and Carbon Demineralized Loss of material/ Chapter XI.M21, "Closed-Cycle Cooling No 

LPCI) (serviced by closed-cycle steel, water on one General (carbon Water System" 

cooling water) stainless side; closed- steel only), pitting, 

D2.4.1 Tubes steel cycle cooling and crevice 

D2.4.2 Tubesheet water (treated corrosion 

D2.4.3 Channel head water) on the 

D2.4.4 Shell other side 

D2.5-a Drywell and suppression Carbon' Air Loss of material/ A plant-specific aging management Yes, plant 

chamber spray system steel General corrosion program is to be evaluated, specific 

D2.5.1 Piping and fittings 

D2.5.2 Flow orifice 

D2.5.3 Headers 

D2.5.4 Spray nozzles 

D2.5-b Drywell and suppression Carbon Air Plugging of flow A plant-specific aging management Yes, plant 

chamber spray system steel orifice and spray program is to be evaluated, specific 

D2.5.1 Piping and fittings nozzles/ 

D2.5.2 Flow orifice General corrosion 

D2.5.3 Headers 

D2.5.4 Spray nozzles

•> 

N.) 

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E. CARBON STEEL COMPONENTS

E.1 Carbon Steel Components 

E.1.1 External Surfaces 

E.2 Closure Bolting 

E.2.1 In High-Pressure or High-Temperature Systems

April 2001 V E-1 NUREG-1801
E. CARBON STEEL COMPONENTS

Systems, Structures, and Components 

This section includes the aging management programs for the degradation of external surface 

of all carbon steel structures and components including closure boltings in the engineered safety features in pressurized water reactors (PWRs) and boiling water reactors (BWRs). For 

the carbon steel components in PWRs, this section addresses only boric acid corrosion of 

external surfaces as a result of the dripping borated water that is leaking from an adjacent PWR 

component. Boric acid corrosion can also occur for carbon 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-1 801 V E-2 April 2001

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V Engineered Safety Features 

E. Carbon Steel Components 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation E.1 -a Carbon steel components Carbon Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

(PWRs) steel, low- and dripping Boric acid E.1.1 External surfaces alloy steel chemically corrosion of 

treated external surfaces 

borated water 

up to 3400C 

(6440F) E.1-b Carbon steel components Carbon Air, moisture, Loss of material/ A plant-specific aging management Yes, plant (PWRs and BWRs) steel, low- and humidity General corrosion program is to be evaluated, specific E.1.1 External surfaces alloy steel < 100IC 

O(212F) E.2-a Closure bolting Carbon Air, moisture, Loss of material/ Chapter XI.M1 8, "Bolting Integrity" No E.2.1 In high-pressure or high- steel, low- humidity, and General corrosion 

temperature systems alloy steel leaking fluid E.2-b Closure bolting Carbon Air, moisture, Crack initiation Chapter XI.M18, "Bolting Integrity' No E.2.1 In high-pressure or high- steel, low- humidity, and and growth/ 

temperature systems alloy steel leaking fluid Cyclic loading, 

stress corrosion 

cracking

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CHAPTER VI 

ELECTRICAL COMPONENTS

April 2001 VI- NUREG-1801
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NUREG-1 801 VI-ii April 2001
ELECTRICAL COMPONENTS 

A. Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements 

B. Equipment Subject to 10 CFR 50.49 Environmental Qualification Requirements

April 2001 NUREG-1 801 Vl-iii
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NUREG-1 801 VI-iv April 2001

I I
A. ELECTRICAL CABLES AND CONNECTIONS NOT SUBJECT TO 10 CFR 50.49 

ENVIRONMENTAL QUALIFICATION REQUIREMENTS 

A.1 Conductor Insulation 

A.1.1 Electrical cables and connections exposed to an adverse localized 

environment caused by heat, radiation, or moisture 

A.1.2 Electrical cables used in instrumentation circuits that are sensitive to 

reduction in conductor insulation resistance (IR) exposed to an adverse 

localized environment caused by heat, radiation, or moisture 

A.1.3 Inaccessible medium-voltage (2kV to 15kV) cables (e.g., installed in conduit 

or direct buried) exposed to an adverse localized environment caused by 

exposure to moisture and voltage 

A.2 Connector Contacts 

A.2.1 Electrical connectors exposed to borated water leakage

April 2001 VI A-1 NUREG-1801
A. ELECTRICAL CABLES AND CONNECTIONS 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 (<1 OOOV) and medium-voltage (2kV to 15kV). High voltage (>15kV) power cables and connections have unique, specialized constructions and must be evaluated on an 

application specific basis. 

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, and terminal blocks. This common review is translated into program actions, which 

treat cables and connections in the same manner. 

Electrical cables and connections that are in the plant's environmental qualification (EQ) 

program are addressed in VI.B. 

System Interfaces 

Electrical cables and connections functionally interface with all plant systems that rely on 

electric power or instrumentation and control. Electrical cables and connections also interface 

with and are supported by structural commodities (e.g., cable trays, conduit, cable trenches, 

cable troughs, duct banks, cable vaults and manholes) that are reviewed, as appropriate, in the 

Structures and Components Supports section.

NUREG-1801 VI A-2 April 2001

I I
VI

( (

Electrical Components A. Electrical Cables and Connn~tionn Nnt Riihi.ntt tn Ifl C.I=R _fl A€1 IFnwirnnme~tnla .If~~aifijatIi~n IQ•,~m.~

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A.1-a Conductor insulation Various Adverse Embrittlement, Chapter XI.E1, "Electrical Cables and No 

A.1.1 Conductor insulation for organic localized cracking, melting, Connections Not Subject to 

electrical cables and polymers environment discoloration, 10 CFR 50.49 Environmental 

connections (e.g., EPR, caused by swelling, or loss of Qualification Requirements" 

SR, heat, dielectric strength 

EPDM, radiation, or leading to 

XLPE) moisture in reduced insulation 

the presence resistance, 

of oxygen electrical failure / 

(Thermal/ 

thermoxidative) 

degradation of 

organics, 

radiolysis and 

photolysis 

(UV sensitive 

materials only) of 

organics; 

radiation-induced 

oxidation, 

moisture intrusion

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A.1-b Conductor insulation Various Adverse Embrittlement, Chapter XI.E2, "Electrical Cables Not No 

A.1.2 Conductor insulation for organic localized cracking, melting, Subject to 10 CFR 50.49 Environmental 

electrical cables used in polymers environment discoloration, Qualification Requirements Used in 

instrumentation circuits that (e.g., EPR, caused by swelling, or loss of Instrumentation Circuits" 

are sensitive to reduction in SR, heat, dielectric strength 

conductor insulation EPDM, radiation, or leading to 

resistance (IR) XLPE) moisture in reduced insulation 

the presence resistance, 

of oxygen electrical failure / 

(Thermal/ 

thermoxidative) 

degradation of 

organics, 

radiation-induced 

oxidation, 

I _moisture intrusion 

A.1 -c Conductor insulation Various Adverse Formation of Chapter XI.E3, "Inaccessible Medium No 

A.1.3 Conductor insulation for organic localized water trees, Voltage Cables Not Subject to 

inaccessible medium-voltage polymers environment localized damage, 10 CFR 50.49 Environmental 

(2kV to 15kV) cables (e.g., EPR, caused by leading to Qualification Requirements" 

(e.g., installed in conduit or SR, exposure to electrical failure 

direct buried) EPDM, moisture and (breakdown of 

XLPE) voltage insulation)/ 

Moisture intrusion, I_ water trees 

A.2-a Connector contacts Various Exposure to Corrosion of Chapter XI.M1 0, "Boric Acid Corrosion" No 

A.2.1 Connector contacts for metals borated water connector contact 

electrical connectors used for leakage surfaces / 

exposed to borated water electrical Intrusion of 

leakage contacts borated water

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B. EQUIPMENT SUBJECT TO 10 CFR 50.49 ENVIRONMENTAL QUALIFICATION 

REQUIREMENTS 

B.1 Equipment Subject to 10 CFR 50.49 Environmental Qualification Requirements 

B.1.1 Electrical Equipment Subject to 10 CFR 50.49 Environmental Qualification 

Requirements

April 2001 VI B-1 NUREG-1801
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. 

System Interfaces 

Equipment subject to 10 CFR 50.49 environmental qualification requirements functionally interface with all plant systems that rely on electric power or instrumentation and control.

NUREG-1 801 VI B-2 April 2001

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VI Electrical Components 

B. Equipment Subject to 10 CFR 50.49 Environmental Qualification Requirements 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B.1-a Equipment subject to Various Adverse Various EQ is a time-limited aging analysis Yes, 

10 CFR 50.49 environmental polymeric localized degradation/ (TLAA) to be evaluated for the period of TLAA 

qualification requirements and environment Various extended operation. See the Standard 

B.1.1 Electrical equipment subject metallic caused by mechanisms Review Plan, Section 4.4, 

to 10 CFR 50.49 EQ materials heat, "Environmental Qualification (EQ) of 

requirements radiation, Electrical Equipment," for acceptable 

oxygen, methods for meeting the requirements of 

moisture, or 10 CFR 54.21 (c)(1)(i) and (ii). 

voltage 

See Chapter X.E1, "Environmental 

Qualification (EQ) of Electric 

Components," of this report for meeting 

the requirements of 10 CFR 

54.21 (c)(1)(iii).

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CHAPTER VII 

AUXILIARY SYSTEMS

April 2001 VII-i NUREG-1801
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NUREG-1 801 VII-ii April 2001

I I
MAJOR PLANT SECTIONS 

Al. 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 

El. Chemical and Volume Control System (PWR) 

E2. Standby Liquid Control System (BWR) 

"E3. Reactor Water Cleanup System (BWR) 

E4. Shutdown Cooling System (Older BWR) 

Fl. 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 

HI. Diesel Fuel Oil System 

H2. Emergency Diesel Generator System 

I. Carbon Steel Components 

April 2001 NAL;. NUREG-1 . 801 ¥ I1--111
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NUREG-1801 VII-iv April 2001

I I
Al. NEW FUEL STORAGE 

A1.1 New Fuel Rack 

A1.1.1 New Fuel Rack Assembly

April 2001 VII A1-1 NUREG-1 801
Al. NEW FUEL STORAGE

Systems, Structures, and Components 

This section comprises those structures and components used for new fuel storage, and 

includes 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 carbon steel 

components are included in VII.1. 

System Interfaces 

No other systems discussed in this report interface with those used for new fuel storage.

NUREG-1 801 VII A1-2 April 2001

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VII Auxiliary Systems Al. New Fuel Storage 

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

Al.1-a New fuel rack Carbon Indoors: Loss of material/ Chapter XI.S6, "Structures Monitoring No 

A1.1.1 New fuel rack assembly steel exposed to General, pitting, Program" 

variable and crevice 

temperature corrosion 

and humidity inside the 

auxiliary 

building or 

fuel handling building

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A2. SPENT FUEL STORAGE

A2.1 Spent Fuel Storage Rack 

A2.1.1 Neutron-Absorbing Sheets 

A2.1.2 Storage Rack

April 2001 VII A2-1 NUREG-1801
A2. SPENT FUEL STORAGE

Systems, Structures, and Components 

This section comprises those structures and components used for spent fuel storage and 

include stainless steel spent fuel storage racks and neutron absorbing materials (e.g., Boraflex, 

Boral, or boron-steel sheets, if used) submerged in chemically treated oxygenated (BWR) or 

borated (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 carbon steel 

components are included in VII.I. 

System Interfaces 

No other systems discussed in this report interface with those used for spent fuel storage.

NUREG-1801 VII A2-2 April 2001

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VII Auxiliary Systems 

A2. Spent Fuel Storage 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A2.1-a Spent fuel storage racks Boraflex Chemically Reduction of Chapter XI.M22, "Boraflex Monitoring" No 

A2.1.1 Neutron-absorbing sheets treated neutron-absorbing 

oxygenated capacity/ 

(BWR) or Boraflex 

borated degradation 

(PWR) water 

A2.1 -b Spent fuel storage racks Boral, Chemically Reduction of A plant-specific aging management Yes, plant 

A2.1.1 Neutron-absorbing sheets boron steel treated neutron-absorbing program is to be evaluated, specific 

oxygenated capacity and loss 

(BWR) or of material/ 

borated General corrosion 

(PWR) water 

A2.1-c Spent fuel storage racks Stainless Chemically Crack initiation Chapter XI.M2, "Water Chemistry," for No 

A2.1.2 Storage racks steel treated and growth/ BWR water in BWRVIP-29 (EPRI TR

oxygenated Stress corrosion 103515), or PWR primary water in EPRI 

(BWR) or cracking TR-1 05714 

borated 

(PWR) water III

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A3. SPENT FUEL POOL COOLING AND CLEANUP (PRESSURIZED WATER REACTOR)

A3.1 Piping 

A3.1.1 Closure Bolting 

A3.2 Filter 

A3.2.1 Housing 

A3.2.2 Closure Bolting 

A3.2.3 Elastomer Lining 

A3.3 Valves (Check and Hand Valves) 

A3.3.1 Body and Bonnet 

A3.3.2 Closure Bolting 

A3.3.3 Elastomer Lining (Hand Valves Only) 

A3.4 Heat Exchanger 

A3.4.1 Shell and Access Cover 

A3.4.2 Channel Head and Access Cover 

A3.4.3 Closure Bolting 

A3.5 Ion Exchanger 

A3.5.1 Shell 

A3.5.2 Nozzles 

A3.5.3 Closure Bolting 

A3.5.4 Elastomer Lining 

A3.6 Pump 

A3.6.1 Closure Bolting

April 2001 VII A3-1 NUREG-1801
A3. SPENT FUEL POOL COOLING AND CLEANUP (PRESSURIZED WATER REACTOR) 

Systems, Structures, and Components 

This section comprises the 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. Stainless steel components are not subject to significant aging 

degradation in borated water and, therefore, are not included in this section. 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 NRC position on 

consumables, provided in the NRC letter from Christopher I. Grimes to Douglas J. Walters of 

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). The application is to 

identify the standards that are relied on for replacement as part of the methodology description, 

for example, NFPA standards for fire protection equipment. 

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. 

Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in VII.I. 

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 VII A3-2 April 2001
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VII Auxiliary Systems 

A3. Spent Fuel Pool Cooling and Cleanup (Pressurized Water Reactor) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A3.1 -a Piping Carbon Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

A3.1.1 Closure bolting steel, chemically Boric acid 

low-alloy treated corrosion 

steel borated water 

A3.2-a Filter Carbon Chemically Loss of material/ Chapter XI.M2, "Water Chemistry," for Yes, 

A3.2.1 Housing steel with treated Pitting and crevice PWR primary water in EPRI TR-1 05714 detection 

elastomer borated water corrosion (only for of aging 

lining carbon steel after The AMP is to be augmented by effects is to 

lining degradation) verifying the effectiveness of water be 

chemistry control. See Chapter XI.M32, evaluated 

"One-Time Inspection," for an 

acceptable verification program. 

A3.2-b Filter Carbon Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

A3.2.1 Housing (external surface) steel chemically Boric acid 

treated corrosion 

borated water 

A3.2-c Filter Carbon Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

A3.2.2 Closure bolting steel, low- chemically Boric acid 

alloy steel treated corrosion 

borated water 

A3.2-d Filter Elastomers Chemically Hardening, A plant-specific aging management Yes, 

A3.2.3 Elastomer lining treated cracking/ program that determines and assesses plant 

borated water Elastomer the qualified life of the linings in the specific 

degradation environment is to be evaluated. 

A3.3-a Valves (check and hand Carbon Chemically Loss of material/ Chapter XI.M2, "Water Chemistry," for Yes, 

valves) steel with treated Pitting and crevice PWR primary water in EPRI TR-1 05714 detection 

A3.3.1 Body and bonnet elastomer borated water corrosion (only for of aging 

lining carbon steel after The AMP is to be augmented by effects is to 

lining degradation) verifying the effectiveness of water be 

chemistry control. See Chapter XI.M32, evaluated 

"One-Time Inspection," for an 

C Z 1 acceptable verification program.

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VII Auxiliary Systems A3. Snent Fuel Pool Coolinoa nd Cleanur (Pressurized Water Reactor•

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A3.3-b Valves (check and hand Carbon Chemically Crack initiation Chapter XI.M2, "Water Chemistry," for No 

valves) steel with treated and growth/ PWR primary water in EPRI TR-1 05714 

A3.3.1 Body and bonnet stainless borated water Stress corrosion 

steel cracking 

cladding 

A3.3-c Valves (check and hand Body: Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

valves) carbon chemically Boric acid 

A3.3.1 Body and bonnet (external steel; treated corrosion 

surface) bolting: borated water 

A3.3.2 Closure bolting carbon 

steel or 

low-alloy 

steel 

A3.3-d Valves (hand valve only) Elastomers Chemically Hardening, A plant-specific aging management Yes, 

A3.3.3 Elastomer lining treated cracking/ program that determines and assesses plant 

borated water Elastomer the qualified life of the linings in the specific degradation environment is to be evaluated. 

A3.4-a Heat exchanger (serviced by Carbon Shell side: Loss of material/ Chapter XI.M21, "Closed-Cycle Cooling No 

closed-cycle cooling water steel closed-cycle General, pitting Water System" 

system) cooling water and crevice 

A3.4.1 Shell and access cover (treated corrosion 

A3.4.2 Channel head and access water) 

cover 

A3.4-b Heat exchanger (serviced by Carbon Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

closed-cycle cooling water steel, low- chemically Boric acid 

system) alloy steel treated corrosion 

A3.4.1 Shell and access cover borated water 

A3.4.2 Channel head and access 

cover (external surface) 

A3.4.3 Closure bolting
(

Auxiliary Systems A3. Soent Fuel Pool Coolino and Cleanun Pre;•uriTed Water Rearitnr•

(

VII

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Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation A3.5-a Ion exchanger Carbon Chemically Loss of mraterial/ Chapter XI.M2, "Water Chemistry," for Yes, (demineralizer) steel with treated Pitting and crevice PWR primary water in EPRI TR-1 05714 detection 

A3.5.1 Shell elastomer borated water corrosion (only for of aging A3.5.2 Nozzles lining carbon steel after The AMP is to be augmented by effects is to 

lining degradation) verifying the effectiveness of water be 

chemistry control. See Chapter XI.M32, evaluated 

"One-Time Inspection," for an 

acceptable verification program. A3.5-b Ion exchanger Carbon Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

(demineralizer) steel, low- chemically Boric acid 

A3.5.1 Shell (external surface) alloy steel treated corrosion 

A3.5.2 Nozzles (external surface) borated water A3.5.3 Closure bolting A3.5-c Ion exchanger Elastomers Chemically Hardening, A plant-specific aging management Yes, (demineralizer) treated cracking/ program that determines and assesses plant A3.5.4 Elastomer lining borated water Elastomer the qualified life of the linings in the specific degradation environment is to be evaluated. 

A3.6-a Pump Carbon Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No A3.6.1 Closure bolting steel, low- chemically Boric acid 

alloy steel treated corrosion 

I borated water I

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A4. SPENT FUEL POOL COOLING AND CLEANUP (BOILING WATER REACTOR)

A4.1 Piping 

A4.1.1 Piping, Fittings, and Flanges 

A4.2 Filter 

A4.2.1 Housing 

A4.2.2 Elastomer Lining 

A4.3 Valves (Check and Hand Valves) 

A4.3.1 Body and Bonnet 

A4.3.2 Elastomer Lining (Hand Valves Only) 

A4.4 Heat Exchanger 

A4.4.1 Shell and Access Cover 

A4.4.2 Channel Head and Access Cover 

A4.4.3 Tubes 

A4.4.4 Tubesheet 

A4.5 Ion Exchanger 

A4.5.1 Shell 

A4.5.2 Nozzles 

A4.5.3 Elastomer Lining 

A4.6 Pump 

A4.6.1 Casing

April 2001 VII A4-11 NUREG-1801
A4. SPENT FUEL POOL COOLING AND CLEANUP (BOILING WATER REACTOR) 

Systems, Structures, and Components 

This section comprises the 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-Waste-Containing 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 NRC position on 

consumables, provided in the NRC letter from Christopher I. Grimes to Douglas J. Walters of 

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). The application is to 

identify the standards that are relied on for replacement as part of the methodology description, for example, NFPA standards for fire protection equipment. 

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. Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in VII.I. 

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 closed

cycle cooling water system (VII.C2) and the condensate system (VIII.E). 

NUREG-1801 VII A4-2 April 2001

I I
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VII Auxiliary Systems 

A4. Spent Fuel Pool Cooling and Cleanu (Boiling Water Reactor) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A4.1-a Piping Stainless Chemically Loss of material/ Chapter XI.M2, "Water Chemistry," for Yes, A4.1.1 Piping, fittings, and flanges steel treated Pitting and crevice BWR water in BWRVIP-29 (EPRI TR- detection 

oxygenated corrosion 103515) of aging 

water up to effects is to 

50°C (125°F) The AMP is to be augmented by be 

verifying the effectiveness of water evaluated 

chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

acceptable verification program. A4.2-a Filter Stainless Chemically Loss of material/ Chapter XI.M2, "Water Chemistry," for Yes, A4.2.1 Housing steel; treated Pitting and crevice BWR water in BWRVIP-29 (EPRI TR- detection 

carbon oxygenated corrosion (only for 103515) of aging 

steel with water up to carbon steel after effects is to 

elastomer 500C (125 0

F) lining/cladding The AMP Is to be augmented by be 

lining, or degradation) verifying the effectiveness of water evaluated 

stainless chemistry control. See Chapter XI.M32, 

steel "One-Time Inspection," for an 

cladding acceptable verification program. A4.2-b Filter Elast6mers Chemically Hardening, A plant-specific aging management Yes, plant A4.2.2 Elastomer lining treated cracking/ program that determines and assesses specific 

oxygenated Elastomer the qualified life of the linings in the 

water up to degradation environment is to be evaluated. 

50°C (1 25°F) A4.3-a Valves (check and hand Stainless Chemically Loss of material/ Chapter XI.M2, "Water Chemistry," for Yes, valves) steel; treated Pitting and crevice BWR water in BWRVIP-29 (EPRI TR- detection 

A4.3.1 Body and bonnet carbon oxygenated corrosion (only for 103515) of aging steel with water up to carbon steel after effects is to 

elastomer 500C (1250F) lining/cladding The AMP is to be augmented by be 

lining, or degradation) verifying the effectiveness of water evaluated 

stainless chemistry control. See Chapter XI.M32, steel "One-Time Inspection," for an 

I cladding I _ acceptable verification program. I
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VII Auxiliary Systems 

A4. Spent Fuel Pool Cooling and Cleanu (Boiling Water Reactor) 

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A4.3-b Valves (hand valve only) Elastomers Chemically Hardening, A plant-specific aging management Yes, plant A4.3.2 Elastomer lining treated cracking/ program that determines and assesses specific 

oxygenated Elastomer the qualified life of the linings in the 

water up to degradation environment is to be evaluated. 

50-C (125-F) 

A4.4-a Heat exchanger (serviced by Carbon Shell side: Loss of material/ Chapter XI.M21, "Closed-Cycle Cooling No 

closed-cycle cooling water steel closed-cycle General, pitting Water System" system) cooling water and crevice 

A4.4.1 Shell and access cover corrosion 

A4.4.2 Channel head and access 

cover 

A4.4.3 Tubes 

A4.4-b Heat exchanger (serviced by Channel Demineralized Loss of material/ Chapter XI.M2, "Water Chemistry," for Yes, closed-cycle cooling water head and oxygenated General, pitting BWR water in BWRVIP-29 (EPRI TR- detection 

system) access water and crevice 103515) of aging A4.4.2 Channel head and access cover: corrosion effects is to 

cover stainless The AMP is to be augmented by be A4.4.3 Tubes steel, verifying the effectiveness of water evaluated A4.4.4 Tubesheet carbon chemistry control. See Chapter XI.M32, 

steel with "One-Time Inspection," for an 

stainless acceptable verification program. 

steel 

cladding; 

tubes and 

tubesheet: 

stainless 

steel 

A4.5-a Ion exchanger Stainless Demineralized Loss of Material/ Chapter XI.M2, "Water Chemistry," for Yes, (demineralizer) steel, oxygenated Pitting and crevice BWR water in BWRVIP-29 (EPRI TR- detection A4.5.1 Shell carbon water corrosion (only for 103515) of aging A4.5.2 Nozzles steel with carbon steel after effects is to 

elastomer lining degradation) The AMP is to be augmented by be 

lining verifying the effectiveness of water evaluated 

chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

acceptable verification program.

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A4.5-b Ion exchanger Elastomers Chemically Hardening, A plant-specific aging management Yes, plant 

(demineralizer) treated cracking/ program that determines and assesses specific 

A4.5.3 Elastomer lining oxygenated Elastomer the qualified life of the linings in the 

water up to degradation environment is to be evaluated. 

500C (1 250F) 

A4.6-a Pump Stainless Demineralized Loss of material/ Chapter' XI.M2, "Water Chemistry," for Yes, 

A4.6.1 Casing steel, oxygenated Pitting and crevice BWR water in BWRVIP-29 (EPRI TR- detection 

carbon water corrosion 103515) of aging 

steel (with effects is to 

stainless The AMP is to be augmented by be 

steel verifying the effectiveness of water evaluated 

cladding) chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

acceptable verification program.

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A5. SUPPRESSION POOL CLEANUP SYSTEM (BOILING WATER REACTOR) 

Systems, Structures, and Components 

This section comprises 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, or are subject to replacement based on qualified life or specified time period. 

Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in VII.1. 

The system piping includes all pipe sizes, including instrument piping. 

System Interfaces 

The system that interfaces with the suppression pool cleanup system is the BWR containment 

(ll.B), or BWR emergency core cooling system (V.D2). 

Evaluation Summary 

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. 

The reader is therefore referred to the section for the spent fuel storage pool system for a 

listing of aging effects, aging mechanisms, and aging management programs that are to be 

applied to the suppression pool cleanup system components. (The only component in VII.A4 

that may not be applicable to the suppression pool cleanup system is the heat exchanger 

[VII.A4.4].)

April 2001 VII A5-1 NUREG-1 801
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NUREG-1801 VII A5-2 April 2001

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B. OVERHEAD HEAVY LOAD AND LIGHT LOAD (RELATED TO REFUELING) HANDLING 

SYSTEMS 

B.1 Cranes Including Bridge and Trolley (that fall within the scope of 10 CFR 54) 

B.1.1 Structural Girders 

B.2 Rail System 

B.2.1 Rail

April 2001 NUREG-1 801 VI1 B-1
B. OVERHEAD HEAVY LOAD AND LIGHT LOAD (RELATED TO REFUELING) HANDLING 

SYSTEMS 

Systems, Structures, and Components 

Most commercial nuclear facilities have between fifty and one hundred cranes. Many of these 

cranes are industrial grade cranes that must meet the requirements of 29 CRF 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 all 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 surface of carbon steel 

components are included in VII.L. 

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 VII B-2 April 2001
(

VII

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, %,. V uavy W,, ..-Vau ua -,11u, L-Oau Related 10 metuellng) Handling S stems 

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation B.1-a Cranes including bridge and Structural Air at 100% Cumulative Fatigue is a time-limited aging analysis Yes, 

trolley (for cranes that fall steel A-36, relative fatigue damage/ (TLAA) to be evaluated for the period of TLAA within the scope of A-7, or humidity and Fatigue extended operation for structural girders 10 CFR 54) A-285 49 0C (120°F) of cranes that fall within the scope of B.1.1 Structural girders 10 CFR 54. See the Standard Review 

Plan, Section 4.7, "Other Plant-Specific 

Time-Limited Aging Analyses," for 

generic guidance for meeting the 

requirements of 10 CFR 54.21 (c). B.1-b Cranes including bridge and Structural Air at 100% Loss of material/ Chapter XI.M23, "Inspection of No trolley (for cranes that fall steel A-36, relative General corrosion Overhead Heavy Load and Light Load within the scope of A-7, or humidity and (Related to Refueling) Handling 10 CFR 54) A-285 49-C (120-F) Systems" B.1.1 Structural girders B.2-a Rail system Structural Air at 100% Loss of material/ Chapter XI.M23, "Inspection of No B.2.1 Rail steel A-759 relative Wear Overhead Heavy Load and Light Load 

humidity and (Related to Refueling) Handling 49°C (120°F) Systems"

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Cl. OPEN-CYCLE COOLING WATER SYSTEM (SERVICE WATER SYSTEM)

C1.1 Piping 

C1.1.1 Piping and Fittings 

C1.1.2 Underground Piping and Fittings 

C1.2 Valves 

C1.2.1 Body and Bonnet 

C1.3 Heat Exchanger 

C1.3.1 Shell 

C1.3.2 Channel 

C1.3.3 Channel Head and Access Cover 

C1.3.4 Tubesheet 

C1.3.5 Tubes 

C1.4 Flow Orifice 

C1.4.1 Body 

C1.5 Pump 

C1.5.1 Casing 

C1.6 Basket Strainer 

C1.6.1 Body

April 2001 VII C1-1 NUREG-1801
Cl. OPEN-CYCLE COOLING WATER SYSTEM (SERVICE WATER SYSTEM) 

Systems, Structures, and Components 

This section comprises 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, or are subject to replacement based on qualified life or specified time period. 

Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in VII.1. 

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 closed

cycle 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 VII C1-2 April 2001
ViI

A 

Auxiliary Systems 

01. Ooen-Cvcle Coolina Water Svstem (Service Water Svste~m•

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

01.1-a Piping Carbon steel Raw, Loss of material/ Chapter XI.M20, "Open-Cycle Cooling No 

C1.1.1 Piping and fittings (with or (for fresh untreated salt General (only for Water System" and Chapter XI.M33, 

without internal lining- or water only) water or fresh carbon steel "Selective Leaching of Materials" 

coating) aluminum- water without 

bronze, brass, lining/coating or 

copper-nickel, with degraded 

stainless steel lining/coating), 

selective leaching 

(only for 

aluminum

bronze, brass, 

and copper

nickel), pitting, 

crevice, galvanic, 

microbiologically 

influenced 

corrosion and 

biofouling 

C1.1-b Piping Carbon steel Soil Loss of material/ Chapter XI.M28, "Buried Piping and No 

C1.1.2 Underground piping and General, pitting, Tanks Surveillance," or 

fittings (external surface, crevice, and 

with or without organic microbiologically Chapter XI.M34, "Buried Piping and Yes, 

coating or wrapping) influenced Tanks Inspection" detection 

corrosion of aging 

effects and 

operating 

experience 

are to be 

further 

evaluated 

C1.1-c Piping Cast iron Soil Loss of material/ Chapter XI.M33, "Selective Leaching No 

C1.1.2 Underground piping and selective leaching of Materials" 

fittings (external surface, and general 

with or without organic corrosion 

coating or wrapping) I
VII Auxiliary Systems C1. Open-Cycle Coolina Water System (Service Water SvRtam•

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation C1.2-a Valves (check, hand, control, Bronze, Aaw, Loss of material/ Chapter XI.M20, "Open-Cycle Cooling No and containment isolation aluminum- untreated salt General (only Water System," and Chapter XI.M33, valves) bronze, water or fresh carbon steel "Selective Leaching of Materials" 

C1.2.1 Body and bonnet (with or stainless water without 

without internal lining or steel, carbon lining/coating or 

coating) steel (fresh with degraded 

water only) lining/coating), 

selective leaching 

(only for bronze, 

aluminum

bronze), pitting, 

crevice, 

microbiologically 

influenced 

corrosion and 

biofouling C1.3-a Heat exchanger (between Shell, Shell side: Loss of material/ Chapter XI.M20, "Open-Cycle Cooling No open-cycle and closed-cycle channel, treated water; General (only for Water System" and Chapter XI.M33, cooling water systems) channel head tube side: raw carbon steel), "Selective Leaching of Materials" C1.3.1 Shell and access untreated salt selective leaching C1.3.2 Channel cover: carbon or fresh water (only for C1.3.3 Channel head and access steel; aluminum-bronze, 

cover tube sheet: copper-nickel, and C1.3.4 Tube sheet aluminum- aluminum brass), C1.3.5 Tubes bronze; galvanic, pitting, 

tubes: crevice, 

copper-nickel, microbiologically aluminum influenced 

brass corrosion and 

biofouling C1.3-b Heat exchanger (between Copper- Shell side: Buildup of Chapter XI.M20, "Open-Cycle Cooling No open-cycle and closed-cycle nickel, treated water/ deposit/ Water System" cooling water systems) aluminum tube side: raw Biofouling C1.3.5 Tubes brass untreated salt 

or fresh water
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ViI Auxiliary Systems C1. Open-Cycle Coolina Water Svstem (Service Water Svste m•

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Structure and/or Aging Effect! Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C1 .4-a Flow orifice Stainless Raw, Loss of material/ Chapter XI.M20, "Open-Cycle Cooling No C(1.4.1 Body steel untreated salt Pitting, crevice, Water System" 

water or fresh microbiologically 

water influenced 

corrosion and 

biofouling_ CI.5-a Pump Cast steel, Raw, Loss of material/ Chapter XI.M20, "Open-Cycle Cooling No 

C1.5.1 Casing Carbon steel untreated salt General, selective Water System," and Chapter XI.M33, 

water or fresh leaching (for cast "Selective Leaching of Materials" 

water steel), pitting, 

crevice, 

microbiologically 

influenced 

corrosion and 

biofouling Cl.6-a Basket strainer Carbon steel, Raw, Loss of material/ Chapter XI.M20, "Open-Cycle Cooling No 

C1.6.1 Body stainless steel untreated salt General (for Water System" 

water or fresh carbon steel only), 

water pitting, crevice, 

microbiologically 

influenced 

corrosion and 

biofouling

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C2. CLOSED-CYCLE COOLING WATER SYSTEM

C2.1 Piping 

C2.1.1 Pipe, Fittings, and Flanges 

C2.2 Valves (Check, Hand, Control, Relief, Solenoid, and Containment Isolation) 

C2.2.1 Body and Bonnet 

C2.3 Pump 

C2.3.1 Casing 

C2.4 Tank 

C2.4.1 Shell 

C2.5 Flow Orifice 

C2.5.1 Body

April 2001 VII C2-1 NUREG-1801
C2. CLOSED-CYCLE COOLING WATER SYSTEM

Systems, Structures, and Components 

This section comprises 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 and that has water chemistry control and is not subject to significant sources of 

contamination. 

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 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 PWR and BWR spent fuel pool cooling and cleanup systems 

(VII.A3 and VII.A4, respectively) and the chemical and volume control system (VII.E1). 

Pump and valve internals perform their intended functions with moving parts or with a change in 

configuration, or are subject to replacement based on qualified life or specified time period. 

Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in VII.1. 

The system piping includes all pipe sizes, including instrument piping. 

System Interfaces 

The systems that interface with the closed-cycle cooling water system include the open-cycle 

cooling water system (VII.C1), the PWR spent fuel pool cooling and cleanup system (VII.A3), 

the BWR spent fuel pool cooling and cleanup system (VII.A4), the chemical and volume control 

system (VII.E1), the BWR reactor water cleanup system (VII.E3), the shutdown cooling system 

(older BWR, VII.E5), the primary containment heating and ventilation system (VII.F3), the fire 

protection (VII.G), the emergency diesel generator system (VII.H2), the PWR containment 

spray system (V.A), the PWR and BWR emergency core cooling systems (V.D1 and V.D2), the 

PWR steam generator blowdown system (VIII.F), the condensate system (VIII.E), and the PWR 

auxiliary feedwater system (VIII.G). 

NUREG-1801 VII C2-2 April 2001

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VII Auxiliary Systems 

C2. Closed-Cycle Cooling Water System 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation C2.1-a Piping Carbon steel 35°C (950F) Loss of material/ Chapter XI.M21, "Closed-Cycle Cooling No C2.1.1 Pipe, fittings, and flanges treated water General, pitting, Water System" 

and crevice 

corrosion 

C2.2-a Valves (check, hand, control, Carbon steel, 35°C (95°F) Loss ofmaterial/ Chapter XI.M21, "Closed-Cycle Cooling No relief, solenoid, and stainless steel treated water General (only for Water System" containment isolation valves) carbon steel), C2.2.1 Body and bonnet pitting and crevice 

corrosion 

C2.3-a Pump Carbon steel, 350C (950F) Loss bf material/ Chapter XI.M21, "Closed-Cycle Cooling No C2.3.1 Casing cast iron treated water General (only for Water System," and Chapter XI.M33, 

carbon steel), "Selective Leaching of Materials" 

selective leaching 

(for cast iron 

only), pitting and 

crevice corrosion 

C2.4-a Tank Carbon steel 350C (950F) Loss of material/ Chapter XI.M21,"Closed-Cycle Cooling No C2.4.1 Shell treated water General, pitting Water System" 

and crevice 

corrosion 

C2.5-a Flow orifice Carbon steel 350C (950F) Loss of material/ Chapter XI.M21, "Closed-Cycle Cooling No C2.5.1 Body treated water General, pitting Water System" 

and crevice 

corrosion

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C3. ULTIMATE HEAT SINK

C3.1 Piping 

C3.1.1 Piping and Fittings 

C3.2 Valves (Check, Hand, and Control) 

C3.2.1 Body and Bonnet 

C3.3 Pump 

C3.3.1 Casing

April 2001 VII C3-1 NUREG-1 801
C3. ULTIMATE HEAT SINK

Systems, Structures, and Components 

The ultimate heat sink (UHS) consists of a lake, ocean, river, spray pond, or cooling tower and 

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 (Ill.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, or are subject to replacement based on qualified life or specified time period. Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21(a)(1). 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in VlI.I. 

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 emergency core cooling systems (V.D1 and V.D2). 

NUREG-1801 VII C3-2 April 2001

I I
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VII Auxiliary Systems 

C3. Ultimate Heat Sink 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

C3.1-a Piping Carbon steel, Raw, Loss of material/ Chapter XI.M20, "Open-Cycle Cooling No C3.1.1 Piping and fittings (with or brass, copper- untreated General (only for Water System," and Chapter XI.M33, without internal lining or nickel fresh water carbon steel "Selective Leaching of Materials" coating) without internal 

lining or coating), 

selective leaching 

(only for brass, 

copper-nickel), 

pitting, crevice 

and 

microbiologically 

influenced 

corrosion 

C3.2-a Valves (check, hand, and Bronze, Raw, Loss of material/ Chapter XI.M20, "Open-Cycle Cooling No control) stainless untreated General (only for Water System," and Chapter XI.M33, C3.2.1 Body and bonnet (with or steel, carbon fresh water carbon steel), "Selective Leaching of Materials" without internal lining or steel selective leaching coating) (for bronze), 

pitting, crevice 

and 

microbiologically 

influenced 

corrosion C3.3-a Pump Carbon steel Raw, Loss of material/ Chapter XI.M20, "Open-Cycle Cooling No C3.3.1 Casing (with or without untreated General, pitting, Water System" internal lining or coating) fresh water crevice and 

microbiologically 

influenced 

1 corrosion I

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D. COMPRESSED AIR SYSTEM

D.1 Piping 

D.1.1 Piping and Fittings 

D.1.2 Closure Bolting 

D.2 Valves (including check valves and containment isolation) 

D.2.1 Body and Bonnet 

D.2.2 Closure Bolting 

D.3 Air Receiver 

D.3.1 Shell and Access Cover 

D.3.2 Closure Bolting 

D.4 Pressure Regulators 

D.4.1 Body and Bonnet 

D.5 Filter 

D.5.1 Shell and Access Cover 

D.5.2 Closure Bolting 

D.6 Dryer 

D.6.1 Shell and Access Cover 

D.6.2 Closure Bolting

April 2001 VII D-1 NUREG-1801
D. COMPRESSED AIR SYSTEM

Systems, Structures, and Components 

This section comprises the compressed air system, which consists of piping, valves (including containment isolation valves), air receiver, pressure regulators, filters, and dryers. The system components and piping are located in various buildings at most nuclear power plants. Based on Regulatory Guide 1.26, "Quality Group Classifications and Standards for Water, Steam, and Radioactive-Waste- Containing Components of Nuclear Power Plants," all components of the compressed air system are classified as Group D Quality Standards, with the exception of those forming part of the containment penetration boundary which are Group B. However, the cleanliness of these components and high air quality is to be maintained because the air provides the motive power for instruments and active components (some of them safety related) that may not function properly if nonsafety Group D equipment is contaminated. 

With respect to filters, these items are to be addressed consistent with the NRC position on consumables, provided in the NRC letter from Christopher I. Grimes to Douglas J. Walters of 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). The application is to identify the standards that are relied on for replacement as part of the methodology description, for example, NFPA standards for fire protection equipment. 

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. Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in VII.L. 

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 VII D-2 April 2001
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D. Compressed Air System 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation D.1-a Piping Carbon steel Saturated air Loss of material/ Chapter XI.M24, "Compressed Air No D.1.1 Piping and fittings and low-alloy General and Monitoring" D.1.2 Closure bolting steel pitting corrosion D.2-a Valves (including check Carbon steel Saturated air Loss of material/ Chapter XI.M24, "Compressed Air No valves and containment General and Monitoring" isolation valves) pitting corrosion 

D.2.1 Body and bonnet 

D.2.2 Closure bolting D.3-a Air receiver Carbon steel Saturated air Loss of material/ Chapter XI.M24, "Compressed Air No D.3.1 Shell and access cover General and Monitoring" D.3.2 Closure bolting pitting corrosion D.4-a Pressure regulators Carbon steel Saturated air Loss of material/ Chapter XI.M24, "Compressed Air No D.4.1 Body and bonnet General and Monitoring" 

pitting corrosion D.5-a Filter Carbon steel Saturated air Loss of material/ Chapter XI.M24, "Compressed Air No D.5.1 Shell and access cover General and Monitoring" D.5.2 Closure bolting pitting corrosion D.6-a Dryer Carbon steel Moist air Loss of material/ Chapter XI.M24, "Compressed Air No D.6.1 Shell and access cover General and Monitoring" 0.6.2 Closure bolting I pitting corrosion III

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El. CHEMICAL AND VOLUME CONTROL SYSTEM (PRESSURIZED WATER REACTOR) 

E1.1 High-Pressure Piping (1500-psig rating) 

E1.1.1 Pipe, Fittings and Flanges 

E1.1.2 Closure Bolting 

E1.2 Low-Pressure Piping (150-psig rating) 

E1.2.1 Closure Bolting 

E1.3 High-Pressure Valves (check, control, hand, motor operated, pressure control and 

relief) 

E1.3.1 Body and Bonnet 

E1.3.2 Closure Bolting 

E1.4 Low-Pressure Valves (check, control, hand, motor operated, pressure control and 

relief) 

E1.4.1 Closure Bolting 

E1.5 High-Pressure Pump 

E1.5.1 Casing 

E1.5.2 Closure Bolting 

E1.6 Low-Pressure Pump 

E1.6.1 Closure Bolting 

E1.7 Regenerative Heat Exchanger 

E1.7.1 Channel Head and Access Cover 

E1.7.2 Tubesheet 

E1.7.3 Tubes 

E1.7.4 Shell and Access Cover 

E1.7.5 Closure Bolting 

E1.8 Letdown Heat Exchanger 

E1.8.1 Channel Head and Access Cover 

E1.8.2 Tubesheet 

E1.8.3 Tubes 

E1.8.4 Shell and Access Cover 

E1.8.5 Closure Bolting 

E1.9 Basket Strainers 

E1.9.1 Closure Bolting

April 2001 VII E1-1 NUREG-1801
E1.10 Volume Control Tank 

E1.1 0.1 Closure Bolting 

NUREG-1801 VII E1-2 April 2001

I I
El. CHEMICAL AND VOLUME CONTROL SYSTEM (PRESSURIZED WATER REACTOR) 

Systems, Structures, and Components 

This section comprises 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 high and 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). The effects of pitting and crevice corrosion 

on stainless steel components are not significant in chemically treated borated water and, 

therefore, are not included in this section. 

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, or are subject to replacement based on qualified life or specified time period. Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21(a)(1). 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in VII.1. 

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).

April 2001 VII E1-3 N UREG-1801
ViI Auxiliary Systems El. Chemical and Volume Control System (Pressurized Weter Reanttnr•

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Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

El.1-a High-pressure piping Pipe, fittings, Chemically Cumulative Fatigue is a time-limited aging analysis Yes, (1 500-psig rating) and flanges: treated fatigue damage/ (TLAA) to be evaluated for the period TLAA E1.1.1 Pipe, fittings, and flanges stainless borated water Fatigue of extended operation. See the 

E1.1.2 Closure bolting steel; closure up to 3400C Standard Review Plan, Section 4.3, 

bolting: low- (6440F) "Metal Fatigue," for acceptable alloy steel, methods for meeting the requirements carbon steel of 10 CFR 54.21 (c). E1.1-b High-pressure piping Low-alloy ' Air, leaking Loss of Material/ Chapter XI.M10, "Boric Acid No 

(1 500-psig rating) steel, carbon chemically Boric acid Corrosion" 

E1.1.2 Closure bolting steel treated corrosion 

borated water 

E1.2-a Low-pressure piping Low-alloy Air, leaking Loss of material/ Chapter XI.M1 0, "Boric Acid No 

(1 50-psig rating) steel, carbon chemically Boric acid Corrosion" 

E1.2.1 Closure bolting steel treated corrosion 

borated water 

E1.3-a High-pressure valves (check, Body and Chemically Cumulative Fatigue is a time-limited aging analysis Yes, control, hand, motor bonnet: treated fatigue damage/ (TLAA) to be evaluated for the period TLAA 

operated, pressure control, stainless borated water Fatigue of extended operation. See the 

and relief valves) steel; closure up to 340°C Standard Review Plan, Section 4.3, E1.3.1 Body and bonnet bolting: (6440F). "Metal Fatigue," for acceptable E1.3.2 Closure bolting carbon steel, methods for meeting the requirements low-alloy steel of 10 CFR 54.21 (c). E1.3-b High-pressure valves (check, Low-alloy Air, leaking Loss of material/ Chapter XI.M1 0, "Boric Acid No 

control, hand, motor steel, carbon chemically Boric acid Corrosion" 

operated, pressure control, steel treated corrosion 

and relief valves) borated water 

E1.3.2 Closure bolting E1.4-a Low-pressure valves (check, Low-alloy Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid No 

control, hand, motor steel, carbon chemically Boric acid Corrosion" 

operated, pressure control, steel treated corrosion 

and relief valves) borated water SE1.4.1 Closure bolting I I I
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El. Chemical and Volume Control System (Pressurized Water Reactor) 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation E1.5-a High-pressure pump Casing:' Chemically Crack initiation A plant-specific aging management Yes, plant E1.5.1 Casing stainless treated and growth/ program is to be evaluated, specific E1.5.2 Closure bolting steel; closure borated water cracking 

bolting: 

carbon steel, 

low-alloy steel 

El.5-b High-pressure pump Low-alloy Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid No 

E1.5.2 Closure bolting steel, carbon chemically Boric acid Corrosion" 

steel treated corrosion 

borated water 

E1.6-a Low-pressure pump Low-alloy Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid No E1.6.1 Closure bolting steel, carbon chemically Boric acid Corrosion" 

steel treated corrosion 

borated water 

E1.7-a Regenerative heat Stainless Tube and' Cumulative Fatigue is a time-limited aging analysis Yes, exchanger steel; closure shell side: fatigue damage/ (TLAA) to be evaluated for the period TLAA E1.7.1 Channel head (including bolting (low- chemically Fatigue of extended operation. See the 

channel weld) and access alloy steel, treated Standard Review Plan, Section 4.3, 

cover carbon steel) borated water "Metal Fatigue," for acceptable E1.7.2 Tubesheet up to 3400C methods for meeting the requirements E1.7.3 Tubes (6440F) of 10 CFR 54.21(c). 

E1.7.4 Shell and access cover 

E1.7.5 Closure bolting E1.7-b Regenerative heat Low-alloy Both sides: Loss of material/ Chapter XI.M1 0, "Boric Acid No 

exchanger steel, carbon chemically Boric acid Corrosion" 

E1.7.5 Closure bolting steel treated corrosion 

borated water 

up to 3400C 

1(6440F)

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Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

E1.7-c Regenerative heat' Stairnless Both sides: Crack initiation Chapter XI.M2, "Water Chemistry," Yes, plant exchanger steel chemically and growth/ for PWR primary water in EPRI specific E1.7.1 Channel head (including treated Stress corrosion TR-1 05714 

channel weld) and access borated water cracking, cyclic 

cover up to 3400C loading The AMP is to be augmented by E1.7.2 Tubesheet (644°F) verifying the absence of cracking due 

E1.7.3 Tubes to stress corrosion cracking and cyclic E1.7.4 Shell and access cover loading, or loss of material due to 

pitting and crevice corrosion. An 

acceptable verification program is to 

include temperature and radioactivity 

monitoring of the shell side water, and 

eddy current testing of tubes. 

E1.8-a Letdown heat exchanger Stainless Tube side: Cumulative Fatigue is a time-limited aging analysis Yes, (serviced by closed-cycle steel, carbon chemically fatigue damage/ (TLAA) to be evaluated for the period TLAA 

cooling water) steel treated Fatigue of extended operation. See the 

E1.8.1 Channel head (including borated water Standard Review Plan, Section 4.3, channel weld) and access up to 3400C "Metal Fatigue," for acceptable 

cover (644°F); shell methods for meeting the requirements E1.8.2 Tubesheet side: closed- of 10 CFR 54.21 (c). E1.8.3 Tubes cycle cooling 

E1.8.4 Shell and access cover water (treated 

E1.8.5 Closure bolting water)

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation E1.8-b Letdown heat exchanger Stainless Tube side: Crack initiation Chapter XI.M2, "Water Chemistry," Yes, plant (serviced by closed-cycle steel chemically and growth/ for PWR primary water in EPRI specific cooling water) treated Stress corrosion TR-105714 E1.8.1 Channel head (including borated water cracking, cyclic channel weld) and access up to 3400C loading The AMP is to be augmented by cover (6440F); shell verifying the absence of cracking due El .8.2 Tubesheet side: closed- to stress corrosion cracking and cyclic E1.8.3 Tubes cycle cooling loading, or loss of material due to 

water pitting and crevice corrosion. An 

acceptable verification program is to 

include temperature and radioactivity monitoring of the shell side water, and 

eddy current testing of tubes. (See 

Oconee operating experience, License 

Renewal Application, Revision 2, June 

1998, p. 3.4-26) E1.8-c Letdown heat exchanger Carbon steel Closed-cycle Loss of material/ Chapter XI.M21, "Closed-Cycle No (serviced by closed-cycle cooling water Pitting and crevice Cooling Water System" cooling water) corrosion 

E1.8.4 Shell and access cover 

E1.8-d Letdown heat exchanger Low-alloy Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid No (serviced by closed-cycle steel, carbon chemically Boric acid Corrosion" 

cooling water) steel treated corrosion E1.8.5 Closure bolting borated water El.9-a Basket strainer Low-alloy Air, leaking Loss of material/ Chapter XI.Ml10, "Boric Acid No E1.9.1 Closure bolting steel, carbon chemically Boric acid Corrosion" 

steel treated corrosion 

borated water E1.10- Volume control tank Low-alloy Air, leaking Loss of material/ Chapter XI.M10, "Boric Acid No 

a Closure bolting steel, carbon chemically Boric acid Corrosion" 

E1.10. steel treated corrosion 1 1 borated water I
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E2. STANDBY LIQUID CONTROL SYSTEM (BOILING WATER REACTOR) 

E2.1 Piping 

E2.1.1 Piping and Fittings 

E2.2 Solution Storage 

E2.2.1 Tank 

E2.2.2 Tank Heaters 

E2.3 Valves (Pump Suction, Relief, Injection, Containment Isolation, and Explosive Actuated Discharge) 

E2.3.1 Body and Bonnet 

E2.4 Injection Pumps 

E2.4.1 Casing

April 2001 NUREG-1801 V1I E2-1
E2. STANDBY LIQUID CONTROL SYSTEM (BOILING WATER REACTOR)

Systems, Structures, and Components 

This section comprises 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 (Na 2B100 16-1 0H20) 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 covered in IV.C1. 

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. Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in VII.I. 

The system piping includes all pipe sizes, including instrument piping. 

System Interfaces 

The system that interfaces with the standby liquid control system is the BWR reactor pressure 

vessel (IV.A1). If used, the standby liquid control system would inject sodium pentaborate 

solution into the pressure vessel near the bottom of the reactor core.

NUREG-1801 VII E2-2 April 2001

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Auxiliary Systems E2. Standby Liquid Control Syvstem (Boillin Weter R~Ai~tnr•

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation E2.1-a Piping Stainless Sodium' Crack initiation Chapter XI.M2, "Water Chemistry," No' E2.1.1 Piping and fittings in steel pentaborate and growth/ for BWR water in BWRVIP-29 (EPRI contact with sodium solution at Stress corrosion TR-103515) pentaborate solution 21 - 32 °C cracking 

(70 - 90 0F) 

(,24,500 ppm B) E2.2-a Solution storage Stainless Sodium Crack initiation Chapter XI.M2, "Water Chemistry," No E2.2.1 Tank steel pentaborate and growth/ for BWR water in BWRVIP-29 (EPRI E2.2.2 Tank heaters solution at Stress corrosion TR-103515) 

21 - 32 °C cracking 

(70 - 90 0F) 

(t24,500 ppm B) E2.3-a Valves (pump suction, relief, Stainless Sodium Crack initiation Chapter XI.M2, "Water Chemistry," No injection, containment steel pentaborate and growth/ for BWR water in BWRVIP-29 (EPRI isolation, and explosive solution at Stress corrosion TR-1 03515) actuated discharge valves) 21 - 32 °C cracking E2.3.1 Body and bonnet (70 - 90°F) (=24,500 ppm B) E2.4-a Injection pumps Stainless Sodium Crack initiation Chapter XI.M2, "Water Chemistry," No E2.4.1 Casing steel pentaborate and growth/ for BWR water in BWRVIP-29 (EPRI solution at Stress corrosion TR-103515) 

21 - 32 0C cracking 

(70 - 900F) 

__(__ 24,500 ppm B)

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E3. REACTOR WATER CLEANUP SYSTEM (BWR)

E3.1 Piping 

E3.1.1 Piping and Fittings (Beyond Second Isolation Valves) 

E3.2 Reactor Water Cleanup (RWCU) Pump 

E3.2.1 Casing 

E3.3 Regenerative Heat Exchanger 

E3.3.1 Channel Head and Access Cover 

E3.3.2 Tubesheet 

E3.3.3 Tubes 

E3.3.4 Shell and Access Cover 

E3.4 Non-Regenerative Heat Exchanger 

E3.4.1 Channel Head and Access Cover 

E3.4.2 Tubesheet 

E3.4.3 Tubes 

E3.4.4 Shell and Access Cover

April 2001 Vii E3-11 NUREG-1801
E3. REACTOR WATER CLEANUP SYSTEM (BOILING WATER REACTOR) 

Systems, Structures, and Components 

This section comprises 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 forms the primary pressure boundary, and is 

governed by Group A Quality Standards and 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 concern the reactor coolant pressure 

boundary in BWRs. 

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. 

Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in VII.l. 

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 VII E3-2 April 2001

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E3. Reactor Water Cleanup System (Bolin g Water Reactor) 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

E3.1-a Piping Stainless Oxygenated Crack initiation and Chapter XI.M25, "BWR Reactor Water No E3.1.1 Piping and fittings steel: types water growth/ Cleanup System" (beyond second isolation 304, 316, or 93 0

C -2880C Stress corrosion 

valve) 316NG (200°F-5500F) cracking, 

intergranular stress 

corrosion cracking E3.1-b Piping Stainless Oxygenated Cumulative'fatigue Fatigue is a time-limited aging analysis Yes, E3.1.1 Piping and fittings steel: types water damage/ (TLAA) to be evaluated for the period of TLAA (beyond second isolation 304, 316, or 93 0C -2880C Fatigue extended operation. See the Standard valve) 316NG (200°F-550°F) Review Plan, Section 4.3, "Metal 

Fatigue," for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c). E3.2-a Reactor water cleanup Cast Oxygenated Crack initiation and Chapter XI.M25, "BWR Reactor Water No 

(RWCU) pump austenitic water growth/ Cleanup System" E3.2.1 Casing stainless steel 93 0C -2880C Stress corrosion 

(2000 F-5500F) cracking, 

intergranular stress 

corrosion cracking E3.2-b RWCU pump Cast Oxygenated Cumulative fatigue Fatigue is a time-limited aging analysis Yes, E3.2.1 Casing austenitic water damage/ (TLAA) to be evaluated for the period of TLAA 

stainless 93°C -288°C Fatigue extended operation. See the Standard 

steel, (200°F-550OF) Review Plan, Section 4.3, "Metal 

stainless steel Fatigue," for acceptable methods for 

meeting the requirements of 10 CFR 54.21(c). 

E3.2-c RWCU pump High strength Air, Leaking Cumulative fatigue Fatigue is a time-limited aging analysis Yes, E3.2.2 Closure bolting low-alloy steel oxygenated damage/ (TLAA) to be evaluated for the period of TLAA 

water Fatigue extended operation. See the Standard 

Review Plan, Section 4.3, "Metal 

Fatigue," for acceptable methods for 

meeting the requirements of 10 CFR 54.21 (c).
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VII Auxiliary Systems E3. Reactor Water Cleanu System (Boiling Water React r) 

Structure and/or Aging Effect! Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation E3.3-d Regenerative heat Channel head Oxygenated Crack initiation and A plant-specific aging management Yes, plant exchanger and access water at growth/ program is to be evaluated, specific E3.3.1 Channel head and cover, 2880C (5500F) Stress corrosion 

access cover tubesheet, and cracking E3.3.2 Tubesheet tubes: 10 MPa max. 

E3.3.3 Tubes stainless 

E3.3.4 Shell and access cover steel; Shell 

and access 

cover: high 

strength low

alloy steel 

with stainless 

steel cladding E3.4-a Non-regenerative heat Channel head Reactor Crack initiation and A plant-specific aging management Yes, plant exchanger (serviced by and access coolant water growth/ program is to be evaluated, specific closed-cycle cooling cover, at 2880C Stress corrosion 

water) tubesheet, (550°F) and cracking E3.4.1 Channel head and tubes: 10 MPa max. 

access cover stainless 

E3.4.2 Tubesheet steel; Shell 

E3.4.3 Tubes and access 

E3.4.4 Shell and access cover cover: high 

strength low

alloy steel 

with stainless 

steel cladding E3.4-b Non-regenerative heat High strength Reactor Loss of material/ Chapter XI.M21, "Closed-Cycle Cooling No exchanger (serviced by low-alloy steel coolant water Microbiologically Water System" closed-cycle cooling with stainless at 10 MPa influenced 

water) steel cladding max. corrosion (for E3.4.4 Shell and access cover portions of the 

RWCU system <93°C (200TF]) I
E4. SHUTDOWN COOLING SYSTEM (OLDER BWR) 

E4.1 Piping 

E4.1.1 Piping and Fittings 

E4.2 Pump 

E4.2.1 Casing 

E4.3 Valves (Check, Control, Hand, Motor Operated, and Relief) 

E4.3.1 Body and Bonnet 

E4.4 Heat Exchanger 

E4.4.1 Channel Head and Access Cover 

E4.4.2 Tubesheet 

E4.4.3 Tubes 

E4.4.4 Shell and Access Cover

April 2001 V11 4-1 NUREG-1801
E4. SHUTDOWN COOLING SYSTEM (OLDER BWR)

Systems, Structures, and Components 

This section comprises 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 

covered in IV.C1. 

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. 

Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in VII.1. 

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 VII E4-2 April 2001

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VII Auxiliary Systems =4. Rhmitdnwn C~nnlinnJ Rv.•t•_ "(ld•_r Rnilnn Wathsr R•Anrtnr~

(

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

E4.1-a Piping Carbon steel, Oxygenated Loss of material/ Chapter XI.M2, "Water Chemistry," for Yes, 

E4.1.1 Piping and fittings stainless steel water, up to Pitting and crevice BWR water in BWRVIP-29 (EPRI TR- detection 

2880C (5500F) corrosion 103515) of aging 

effects is to 

The AMP is to be augmented by be 

verifying the effectiveness of water evaluated 

chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

acceptable verification program. E4.1 -b Piping Carbon steel, Oxygenated Cumulative Fatigue is a time-lirnited aging analysis Yes 

E4.1.1 Piping and fittings stainless steel water, up to fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

2881C (5501F) Fatigue extended operation. See the Standard 

Review Plan, Section 4.3, "Metal 

Fatigue," for acceptable methods for 

meeting the requirements of 10 CFR 

54.21(c). 

E4.1 -c Piping Stainless steel Oxygenated Crack initiation Chapter XI.M7, "BWR Stress Corrosion No 

E4.1.1 Piping and fittings water, up to and growth/ Cracking" and Chapter XI.M2, "Water 

288TC (5500 F) Stress corrosion Chemistry," for BWR water in BWRVIP

cracking 29 (EPRI TR-103515) 

E4.2-a Pump Carbon steel Oxygenated Loss of material/ Chapter XI.M2, "Water Chemistry," for Yes, 

E4.2.1 Casing water, up to Pitting and crevice BWR water in BWRVIP-29 (EPRI TR- detection 

2880

C (5500F) corrosion 103515) of aging 

effects is to 

The AMP is to be augmented by be 

verifying the effectiveness of water evaluated 

chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

acceptable verification program. E4.3-a Valves (check, control, hand, Stainless steel Oxygenated Crack initiation Chapter XI.M7, "BWR Stress Corrosion No 

motor operated, and relief forging, water, up to and growth/ Cracking" and Chapter XI.M2, "Water 

valves) stainless steel 2880C (5500F) Stress corrosion Chemistry," for BWR water in 

E4.3.1 Body and bonnet casting cracking BWRVIP-29 (EPRI TR-10351 5)
Auxiliary Systems 

E4. Shutdown Coollng Svsten (OIder Rnllinv WAtar RPanrtrI

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Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation E4.4-a Heat exchanger (serviced by Channel head Reactor Loss of material/ Chapter XI.M21, "Closed-Cycle Cooling No 

closed-cycle cooling water and access coolant water, Pitting, crevice Water System" system) cover: carbon and closed- and 

E4.4.1 Channel head and access steel; cycle cooling microbiologically 

cover tubesheet: water influenced 

E4.4.2 Tubesheet carbon steel corrosion 

E4.4.3 Tubes (stainless 

E4.4.4 Shell and access cover steel cladding 

on channel 

side; Tubes: 

stainless 

steel; Shell: 

I carbon steel I
Fl. CONTROL ROOM AREA VENTILATION SYSTEM 

F1.1 Duct 

F1.1.1 Duct Fittings, Access Doors, and Closure Bolts 

F1.1.2 Equipment Frames and Housing 

F1.1.3 Flexible Collars between Ducts and Fans 

F1.1.4 Seals in Dampers and Doors 

F1.2 Air Handler Heating/Cooling 

F1.2.1 Heating/Cooling Coils 

F1.3 Piping 

F1.3.1 Piping and Fittings 

F1.4 Filters 

F1.4.1 Housing and Supports 

F1.4.2 Elastomer Seals

April 2001 VII NUREG-1801 F1-1
Fl. CONTROL ROOM AREA VENTILATION SYSTEM

Systems, Structures, and Components 

This section comprises 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 

Radioactive-Waste-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 NRC 

position on consumables, provided in the NRC letter from Christopher I. Grimes to Douglas J. 

Walters of 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). The 

application is to identify the standards that are relied on for replacement as part of the 

methodology description, for example, NFPA standards for fire protection equipment. 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in VII.1. 

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 VII F1-2 April 2001

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VII Auxiliary Systems Fl. Control Room Area Ventilation System 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

Fl.1-a Duct Carbon steel Warm, Loss of material/ A plant-specific aging management Yes, plant F1.1.1 Duct fittings, access doors, (galvanized or moist air General, pitting, program is to be evaluated, specific and closure bolts painted) bolts: crevice corrosion, 

F1.1.2 Equipment frames and plated carbon and 

housing steel microbiologically 

influenced 

corrosion (for duct 

[drip-pan] and 

piping for 

moisture drainage) 

Fl.1-b Duct Elastomer Warm, Hardening and A plant-specific aging management Yes, plant F1.1.3 Flexible collars between (Neoprene) moist air loss of strength/ program is to be evaluated, specific ducts and fans Elastomer 

F1.1.4 Seals in dampers and degradation 

doors 

F1.1-c Duct Elastomer Warm, Loss of material/ A plant-specific aging management Yes, plant F1.1.3 Flexible collars between (Neoprene) moist air Wear program is to be evaluated, specific 

ducts and fans 

F1.1.4 Seals in dampers and 

doors 

F1.2-a Air handler heating/ cooling Copper/ nickel Warm, Loss of material/ A plant-specific aging management Yes, plant F1.2.1 Heating/ cooling coils moist air Pitting and crevice program is to be evaluated, specific 

I_ corrosion 

Fl.3-a Piping Carbon steel Hot or cold Loss of material/ Chapter XI.M21, "Closed-Cycle No 

F1.3.1 Piping and fittings treated water General, pitting, Cooling Water System" 

crevice corrosion 

F1.4-a Filters Carbon steel, Warm, Loss of material/ A plant-specific aging management Yes, plant F1.4.1 Housing and supports stainless steel moist air General (only for program is to be evaluated, specific 

carbon steel), 

pitting, and 

crevice corrosion 

F1.4-b Filters Elastomers Warm, Hardening and A plant-specific aging management Yes, plant F1.4.2 Elastomer seals (Neoprene moist air loss of strength/ program is to be evaluated, specific 

and similar Elastomer 

materials) degradation
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F2. AUXILIARY AND RADWASTE AREA VENTILATION SYSTEM 

F2.1 Duct 

F2.1.1 Duct Fittings, Access Doors, and Closure Bolts 

F2.1.2 Equipment Frames and Housing 

F2.1.3 Flexible Collars between Ducts and Fans 

F2.1.4 Seals in Dampers and Doors 

F2.2 Air Handler Heating/Cooling 

F2.2.1 Heating/Cooling Coils 

F2.3 Piping 

F2.3.1 Piping and Fittings 

F2.4 Filters 

F2.4.1 Housing and Supports 

F2.4.2 Elastomer Seals

April 2001 V1I F2-1 NUREG-1801
F2. Auxiliary and Radwaste Area Ventilation System

Systems, Structures, and Components 

This section comprises the auxiliary and radwaste areas ventilation systems (with warm moist 

air as the normal environment) and contains ducts, piping and fittings, equipment frames and 

housings, flexible collars and seals, filters, and heating and cooling air handlers. Based on 

Regulatory Guide 1.26, "Quality Group Classifications and Standards for Water, Steam, and 

Radioactive-Waste-Containing Components of Nuclear Power Plants," all components that 

comprise the auxiliary and radwaste area ventilation system are governed by Group B Quality 

Standards. 

With respect to filters and seals, these items are to be addressed consistent with the NRC 

position on consumables, provided in the NRC letter from Christopher I. Grimes to Douglas J. 

Walters of 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). The 

application is to identify the standards that are relied on for replacement as part of the 

methodology description, for example, NFPA standards for fire protection equipment. 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in VII.L 

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-1 801 VII F2-2 April 2001
(.. (. (

Vii Auxiliary Systems F2. Auxiliary and Radwaste Area Ventilation -Svst~m

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Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation F2.1 -a Duct Carbon steel Warm, moist Loss of material/ A plant-specific aging management Yes, plant F2.1.1 Duct fittings, access doors, (galvanized or air General, pitting, program is to be evaluated. specific and closure bolts painted) bolts: crevice corrosion, F2.1.2 Equipment frames and plated carbon and 

housing steel microbiologically 

influenced 

corrosion (for duct 

[drip-pan] and 

piping for 

moisture drainage) 

F2.1-b Duct Elastomer Warm, moist Hardening and A plant-specific aging management Yes, plant F2.1.3 Flexible collars between (Neoprene) air loss of strength/ program is to be evaluated, specific ducts and fans Elastomer 

F2.1.4 Seals in dampers and degradation 

doors 

F2.1 -c Duct Elastomer Warm, moist Loss of material/ A plant-specific aging management Yes, plant F2.1.3 Flexible collars between (Neoprene) air Wear program is to be evaluated, specific ducts and fans 

F2.1.4 Seals in dampers and 

doors _mo L o t l p - i a me F2.2-a Air handler heating/ cooling Copper/ Warm, moist Loss of material! A plant-specific aging management Yes, plant F2.2.1 Heating/ cooling coils nickel air Pitting and crevice program is to be evaluated, specific corrosion 

F2.3-a Piping Carbon steel Hot or cold Loss of material/ Chapter XI.M21, "Closed-Cycle No F2.3.1 Piping and fittings treated water General, pitting, Cooling Water System" 

crevice corrosion F2.4-a Filters Carbon steel, Warm, moist Loiss of material/ A plant-specific aging management Yes, plant F2.4.1 Housing and supports stainless steel air General (only for program is to be evaluated, specific 

carbon steel), 

pitting and crevice 

corrosion F2.4-b Filters Elastomers Warm, moist Hardening and A plant-specific aging management Yes, plant F2.4.2 Elastomer seals (Neoprene air loss of strength/ program is to be evaluated, specific and similar Elastomer materials) degradation I

i I
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F3. PRIMARY CONTAINMENT HEATING AND VENTILATION SYSTEM 

F3.1 Duct 

F3.1.1 Duct Fittings, Access Doors, and Closure Bolts 

F3.1.2 Equipment Frames and Housing 

F3.1.3 Flexible Collars between Ducts and Fans 

F3.1.4 Seals in Dampers and Doors 

F3.2 Air Handler Heating/Cooling 

F3.2.1 Heating/Cooling Coils 

F3.3 Piping 

F3.3.1 Piping and Fittings 

F3.4 Filters 

F3.4.1 Housing and Supports 

F3.4.2 Elastomer Seals

April 2001 VI1 F3-1 NUREG-1801
F3. PRIMARY CONTAINMENT HEATING AND VENTILATION SYSTEM

Systems, Structures, and Components 

This section comprises 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 NRC 

position on consumables, provided in the NRC letter from Christopher I. Grimes to Douglas J. 

Walters of 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). The 

application is to identify the standards that are relied on for replacement as part of the 

methodology description, for example, NFPA standards for fire protection equipment. 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in VII.I. 

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 ll.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 VII F3-2 April 2001

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VII Auxiliary Systems 

I='A Drimra tfojnfaInrnant UI- nn anti Itanfilf~nn *1 atg m

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1-

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Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

F3.1-a Duct Carbon steel Warm, moist Loss of material/ A plant-specific aging management Yes, plant F3.1.1 Duct fittings, access doors (galvanized or air General, pitting, program is to be evaluated, specific 

and closure bolts painted) bolts: crevice corrosion, 

F3.1.2 Equipment frames and plated carbon and 

housing steel microbiologically 

influenced 

corrosion (for duct 

[drip-pan] and 

piping for 

moisture drainage) 

F3.1-b Duct Elastomer Warm, moist Hardening and A plant-specific aging management Yes, plant F3.1.3 Flexible collars between (Neoprene) air loss of strength/ program is to be evaluated, specific 

ducts and fans Elastomer 

F3.1.4 Seals in dampers and degradation 

doors 

F3.1-c Duct Elastomer Warm, moist Loss of material/ A plant-specific aging management Yes, plant F3.1.3 Flexible collars between (Neoprene) air Wear program is to be evaluated, specific 

ducts and fans 

F3.1.4 Seals in dampers and 

doors 

F3.2-a Air handler heating/ cooling Copper/nickel Warm, moist Loss of material! A plant-specific aging management Yes, plant F3.2.1 Heating/ cooling coils air Pitting and crevice program is to be evaluated, specific 

corrosion 

F3.3-a Piping Carbon steel Hot or cold Loss of material/ Chapter XI.M21, "Closed-Cycle No 

F3.3.1 Piping and fittings treated water General, pitting, Cooling Water System" 

crevice corrosion 

F3.4-a Filters Carbon steel, Warm, moist Loss of m'naterial/ A plant-specific aging management Yes, plant F3.4.1 Housing and supports stainless steel air General (only for program is to be evaluated, specific 

carbon steel), 

pitting and crevice 

corrosion 

F3.4-b Filters Elastomers Warm, moist Hardening and A plant-specific aging management Yes, plant F3.4.2 Elastomer seals (Neoprene air loss of strength/ program is to be evaluated, specific 

and similar Elastomer 

_materials) degradation
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F4. DIESEL GENERATOR BUILDING VENTILATION SYSTEM 

F4.1 Duct 

F4.1.1 Duct Fittings, Access Doors, and Closure Bolts 

F4.1.2 Equipment Frames and Housing 

F4.1.3 Flexible Collars between Ducts and Fans 

F4.1.4 Seals in Dampers and Doors 

F4.2 Air Handler Heating/Cooling 

F4.2.1 Heating/Cooling Coils 

F4.3 Piping 

F4.3.1 Piping and Fittings

April 2001 VII F4-1 NUREG-1801
F4. DIESEL GENERATOR BUILDING VENTILATION SYSTEM

Systems, Structures, and Components 

This section comprises 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 Radioactive

Waste-Containing Components of Nuclear Power Plants," all components that comprise the 

diesel generator building ventilation system are governed by Group C Quality Standards. 

With respect to seals, these items are to be addressed consistent with the NRC position on 

consumables, provided in the NRC letter from Christopher I. Grimes to Douglas J. Walters of 

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). The application is to 

identify the standards that are relied on for replacement as part of the methodology description, for example, NFPA standards for fire protection equipment. 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in VII.I. 

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-1 801 VII F4-2 April 2001
(

ViI Auxiliary Systems 0 F4. Diesel Generator Buildina Ventilation S ystem

0 

,. 

_n

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

F4.1-a Duct Carbon steel Warm, moist Loss of material/ A plant-specific aging management Yes, plant F4.1.1 Duct fittings, access doors, (galvanized or air General, pitting, program is to be evaluated, specific and closure bolts painted); crevice corrosion, F4.1.2 Equipment frames and Bolts: plated and 

housing carbon steel microbiologically 

influenced 

corrosion (for duct 

[drip-pan] and 

piping for 

moisture 

drainage) 

F4.1 -b Duct Elastomer Warm, moist Hardening and A plant-specific aging management Yes, plant F4.1.3 Flexible collars between (Neoprene) air loss of strength/ program is to be evaluated, specific ducts and fans Elastomer 

F4.1.4 Seals in dampers and degradation 

doors 

F4.1-c Duct Elastomer Warm, moist Loss of material/ A plant-specific aging management Yes, plant F4.1.3 Flexible collars between (Neoprene) air Wear program is to be evaluated, specific ducts and fans 

F4.1.4 Seals in dampers and 

doors 

F4.2-a Air handler heating/cooling Copper/nickel Warm, moist Loss of material/ A plant-specific aging management Yes, plant F4.2.1 Heating/cooling coils air Pitting and crevice program is to be evaluated, specific I_ corrosion 

F4.3-a Piping Carbon steel Hot or cold Loss of material/ Chapter XI.M21, "Closed-Cycle No 

F4.3.1 Piping and fittings treated water General, pitting Cooling Water System" 

and crevice 

corrosion

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G. FIRE PROTECTION

G.1 Intake Structure 

G.1.1 Fire Barrier Penetration Seals 

G.1.2 Fire Barrier Walls, Ceilings, and Floors 

G.1.3 Fire Rated Doors 

G.2 Turbine Building 

G.2.1 Fire Barrier Penetration Seals 

G.2.2 Fire Barrier Walls, Ceilings, and Floors 

G.2.3 Fire Rated Doors 

G.3 Auxiliary Building 

G.3.1 Fire Barrier Penetration Seals 

G.3.2 Fire Barrier Walls, Ceilings, and Floors 

G.3.3 Fire Rated Doors 

G.4 Diesel Generator Building 

G.4.1 Fire Barrier Penetration Seals 

G.4.2 Fire Barrier Walls, Ceilings, and Floors 

G.4.3 Fire Rated Doors 

G.5 Primary Containment 

G.5.1 Fire Barrier Walls, Ceilings, and Floors 

G.5.2 Fire Rated Doors 

G.6 Water-Based Fire Protection System 

G.6.1 Piping and Fittings G.6.2 Filter, Fire Hydrants, Mulsifier, Pump Casing, Sprinkler, Strainer, and Valve 

Bodies (including containment isolation valves) 

G.7 Reactor Coolant Pump Oil Collection System 

G.7.1 Tank 

G.7.2 Piping, Tubing, and Valve Bodies 

G.8 Diesel Fire System 

G.8.1 Diesel-Driven Fire Pump and Fuel Supply Line

April 2001 VIi G-1 NUREG-1801
G. FIRE PROTECTION

Systems, Structures, and Components 

This section comprises 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 of the mechanical components 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 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). The application is to 

identify the standards that are relied on for replacement as part of the methodology description, 

for example, NFPA standards for fire protection equipment. 

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. 

Accordingly, they are not subject to an aging management review, pursuant to 

10 CFR 54.21 (a)(1)

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in VII.L. 

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 Ill.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-1 801 VII G-2 April 2001
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G. Fire Protection 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

G.1-a Intake structure Sealant Indoors: air; Increased Chapter XI.M26, "Fire Protection" No 

G.1.1 Fire barrier penetration outdoors: sun, hardness and 

seals (for piping, electrical weather, shrinkage/ 

conduit, cable tray, heating, humidity, and Weathering 

ventilation, air condition, moisture 

and expansion joint) 

G.1-b Intake structure Concrete and' Indoor and Concrete cracking Chapter XI.M26, "Fire Protection" and No 

G.1.2 Fire barrier walls, ceilings, reinforcement outdoor and spalling/ Chapter XI.S6, "Structures Monitoring and floors environments Freeze-thaw, Program" 

aggressive 

chemical attack, 

and reaction with 

aggregates G.1-c Intake structure Concrete and Indoor and Loss of material/ Chapter XI.M26, "Fire Protection" and No 

G. .2 Fire barrier walls, ceilings, reinforcement outdoor Corrosion of Chapter XI.S6, "Structures Monitoring and floors environments embedded steel Program" G.1 -d Intake structure Steel Indoor-and Loss of material/ Chapter XI.M26, "Fire Protection" No 

G.1.3 Fire rated doors outdoor Wear 

environments 

G.2-a Turbine building Sealant Indoors: air; Increased Chapter XI.M26, "Fire Protection" No 

G.2.1 Fire barrier penetration outdoors: sun, hardness and 

seals (for piping, electrical weather, shrinkage/ 

conduit, cable tray, heating, humidity, and Weathering 

ventilation, air condition, moisture 

and expansion joint) 

G.2-b Turbine building Concrete and Indoor and Concrete cracking Chapter XI.M26, "Fire Protection" and No 

G.2.2 Fire barrier walls, ceilings, reinforcement outdoor and spalling/ Chapter XI.S6, "Structures Monitoring and floors environments Freeze-thaw, Program" 

aggressive 

chemical attack, 

and reaction with 

Iaggregates I 

G.2-c Turbine building Concrete and Indoor and Loss of material/ Chapter XI.M26, "Fire Protection" and No G.2.2 Fire barrier walls, ceilings, reinforcement outdoor Corrosion of Chapter XI.S6, "Structures Monitoring and floors environments embedded steel Program"
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VII Auxiliary Systems 

G. Fire Protection 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

G.2-d Turbine building Steel Indoor and Loss of material/ Chapter XI.M26, "Fire Protection" No 

G.2.3 Fire rated doors outdoor Wear 

environments 

G.3-a Auxiliary building Sealant Indoors: air; Increased Chapter XI.M26, "Fire Protection" No 

G.3.1 Fire barrier penetration outdoors: sun, hardness and 

seals (for piping, electrical weather, shrinkage/ 

conduit, cable tray, heating, humidity, and Weathering 

ventilation, air condition, moisture 

and expansion joint) G.3-b Auxiliary building Concrete and Indoor and Concrete cracking Chapter XI.M26, "Fire Protection," and No 

G.3.2 Fire barrier walls, ceilings, reinforcement outdoor and spalling/ Chapter XI.S6, "Structures Monitoring and floors environments Freeze-thaw, Program" 

aggressive 

chemical attack, 

and reaction with 

aggregates 

G.3-c Auxiliary building Concrete and Indoor and Loss of material/ Chapter XI.M26, "Fire Protection," and No 

G.3.2 Fire barrier walls, ceilings, reinforcement outdoor Corrosion of Chapter XI.S6, "Structures Monitoring and floors environments embedded steel Program" G.3-d Auxiliary building Steel Indoor and Loss of material/ Chapter XI.M26, "Fire Protection" No 

G.3.3 Fire rated doors outdoor Wear ______ _ýýe___ _ environments InceasdCaptr _______FirPrtecion _N 

G.4-a Diesel generator building Sealant Ind6ors: air; Increased Chapter XI.M26, "Fire Protection" No 

G.4.1 Fire barrier penetration outdoors: sun, hardness and 

seals (for piping, electrical weather, shrinkage/ conduit, cable tray, heating, humidity, and Weathering 

ventilation, air condition, moisture 

and expansion joint) 

G.4-b Diesel generator building Concrete and Indoor and Concrete cracking Chapter XI.M26, "Fire Protection," and No G.4.2 Fire barrier walls, ceilings, reinforcement outdoor and spalling/ Chapter XI.S6, "Structures Monitoring 

and floors environments Freeze-thaw, Program" 

aggressive 

chemical attack, 

and reaction with 

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G. Fire Protection 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

GA-c Diesel generator building Concrete and Indboo and Loss of material/ Chapter XI.M26, "Fire Protection," and No 

G.4.2 Fire barrier walls, ceilings, reinforcement outdoor Corrosion of Chapter XI.S6, "Structures Monitoring 

and floors I environments embedded steel Program" G.4-d Diesel generator building Steel Indoor and Loss of material/ Chapter XI.M26, "Fire Protection" No 

G.4.3 Fire rated doors outdoor Wear 

environments 

G.5-a Primary containment Concrete and Indoor Concrete cracking Chapter XI.M26, "Fire Protection," and No 

G.5.1 Fire barrier walls, ceilings, reinforcement and spalling/ Chapter XI.S6, "Structures Monitoring and floors Aggressive Program" 

chemical attack, 

and reaction with 

aggregates G.5-b Primary containment Concrete and Indoor Loss of material/ Chapter XI.M26, "Fire Protection," and No 

G.5.1 Fire barrier walls, ceilings, reinforcement Corrosion of Chapter XI.S6, "Structures Monitoring and floors embedded steel Program" "G.5-c Primary containment Steel Indoor Loss of material!/ Chapter XI.M26, "Fire Protection" No 

G.5.2 Fire rated doors Wear 

G.6-a Water-based fire protection Carbon steel, Raw water Loss of material/ Chapter XI.M27, "Fire Water System" No 

system cast iron, and General, galvanic, G.6.1 Piping and fittings stainless steel pitting, crevice, 

microbiologically 

influenced 

corrosion and 

biofouling 

G.6-b Water-based fire protection Carbon steel, Raw water Loss of material/ Chapter XI.M27, "Fire Water System" No 

system cast iron, General, galvanic, G.6.2 Filter, fire hydrant, bronze, pitting, crevice, 

mulsifier, pump casing, copper, microbiologically 

sprinkler, strainer, and stainless steel influenced 

valve bodies (including corrosion and 

containment isolation biofouling valves) I __ I III
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VII Auxiliary Systems 

G. Fire Protection 

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

G.7-a Reactor coolant pump oil Carbon steel Lubricating oil loss ofmaterial/ A plant specific aging management Yes, collection system (with General, galvanic, program that determines the thickness detection G.7.1 Tank contaminants pitting and crevice of the lower portion of the tank is to be of aging 

and/or corrosion evaluated. See Chapter XI.M32, "One- effects is 

moisture) Time Inspection," for an acceptable to be 

verification program. evaluated 

G.7-b Reactor coolant pump oil Pipirng and Lubricating oil Loss of material/ A plant specific aging management Yes, collection system valve bodies: (with General, galvanic, program that monitors the degradation detection 

G.7.2 Piping, tubing, valve bodies carbon steel; contaminants pitting and crevice of the components is to be evaluated, of aging tubing: copper, and/or corrosion See Chapter XI.M32, "One-Time effects is 

brass moisture) Inspection," for an acceptable to be 

verification program. evaluated 

G.8-a Diesel fire system Carbon steel Fuel oil Loss of material/ Chapter XI.M26, "Fire Protection," and No G.8.1 Diesel-driven fire pump General, galvanic, Chapter XI.M30, "Fuel Oil Chemistry" (pump casing) and fuel oil pitting and crevice 

supply line corrosion

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H1. DIESEL FUEL OIL SYSTEM

H1.1 Piping 

H1.1.1 Aboveground Pipe and Fittings 

H1.1.2 Underground Pipe and Fittings 

H1.2 Valves 

H1.2.1 Body and Bonnet 

H1.2.2 Closure Bolting 

H1.3 Pump 

H1.3.1 Casing 

H1.3.2 Closure Bolting 

H1.4 Tank 

H1.4.1 Internal Surface 

H1.4.2 External Surface

April 2001 VII H1-1 NUREG-1801
H1. DIESEL FUEL OIL SYSTEM

Systems, Structures, and Components 

This section comprise 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 carbon steel 

components are included in VII.1. 

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 V11 H11-2 April 2001
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VII

(

Auxiliary Systems Hi. Diesel Fuel Oil Svstem

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

Hi.1-a Piping Carbon steel Outdoor Loss of material/ A plant-specific aging management Yes, plant H1.1.1 Aboveground piping and ambient General, pitting, program is to be evaluated, specific 

fittings conditions and crevice 

corrosion 

Hi.1-b Piping Carbon steel Soil and Loss of material/ Chapter XI.M28, "Buried Piping and No 

H1i.1.2 Underground piping and groundwater General, Tanks Surveillance," or 

fittings galvanic, pitting, 

crevice and Chapter XI.M34, "Buried Piping and Yes, 

microbiologically Tanks Inspection" detection 

influenced of aging 

corrosion effects and 

operating 

experience 

are to be 

further 

evaluated H1.2-a Valves Carbon steel or Outdoor Loss of material/ A plant-specific aging management Yes, plant H1.2.1 Body and bonnet low-alloy steel ambient General, pitting program is to be evaluated, specific H 1.2.2 Closure bolting conditions and crevice 

corrosion 

H1.3-a Pump Carbon steel or Outdoor Loss of material/ A plant-specific aging management Yes, plant H 1.3.1 Casing low-alloy steel ambient General, pitting program is to be evaluated. specific H 1.3.2 Closure bolting conditions and crevice 

I _corrosion 

Hi.4-a Tank Carbon steel Fuel oil, Loss of material/ Chapter XI.M30, "Fuel Oil Chemistry" Yes, H1i.4.1 Internal surface water (as General, pitting, detection 

contaminant) crevice, The AMP is to be augmented by verifying of aging 

microbiologically the effectiveness of fuel oil chemistry effects is 

influenced control. See Chapter XI.M32, "One-Time to be 

corrosion and Inspection," for an acceptable verification evaluated 

biofouling program. Hi.4-b Tank Carbon steel Outdoor Loss of material/ Chapter XI.M29, "Aboveground Carbon No 

H 1.4.2 External surface ambient General, pitting Steel Tanks" 

conditions and crevice 

corrosion
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H2. EMERGENCY DIESEL GENERATOR SYSTEM 

H2.1 Diesel Engine Cooling Water Subsystem 

H2.1.1 Pipe and Fittings 

H2.2 Diesel Engine Starting Air Subsystem 

H2.2.1 Pipe and Fittings 

H2.2.2 Valves (Hand and Check) 

H2.2.3 Drain Trap 

H2.2.4 Air Accumulator Vessel 

H2.3 Diesel Engine Combustion Air Intake Subsystem 

H2.3.1 Piping and Fittings 

H2.3.2 Filter 

H2.3.3 Muffler 

H2.4 Diesel Engine Combustion Air Exhaust Subsystem 

H2.4.1 Piping and Fittings 

H2.4.2 Muffler 

H2.5 Diesel Engine Fuel Oil Subsystem 

H2.5.1 Tanks (Day and Drip)

April 2001 VI1 H2-1 NUREG-1 801
H2. EMERGENCY DIESEL GENERATOR SYSTEM

Systems, Structures, and Components 

This section comprises the emergency diesel generator system, which contains piping, valves, 

filters, mufflers, strainers, and tanks. Based on Regulatory Guide 1.26, "Quality Group 

Classifications and Standards for Water, Steam, and Radioactive-Waste-Containing 

Components of Nuclear Power Plants," all components that comprise the emergency diesel 

generator system are governed by Group C Quality Standards. 

With respect to filters, these items are to be addressed consistent with the NRC position on 

consumables, provided in the NRC letter from Christopher I. Grimes to Douglas J. Walters of 

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). The application is to 

identify the standards that are relied on for replacement as part of the methodology description, 

for example, NFPA standards for fire protection equipment. 

Aging management programs for the degradation of external surfaces of carbon steel 

components are included in VII.l. 

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, for some plants, the 

open-cycle cooling water system (VII.C1).

NUREG-1801 VII H2-2 April 2001
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VII Auxiliary Systems 

H2. Emergency Diesel Generator System 

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

H2.1 -a Diesel engine cooling water Carbon steel Chemically Loss of Material/ Chapter XI.M21, "Closed-Cycle Cooling No 

subsystem (serviced by treated General, pitting Water System" 

closed-cycle cooling water demineralized and crevice 

system) water <900C corrosion 

H2.1.1 Piping and fittings (194TF) 

H2.1 -b Diesel engine cooling water Carbon steel Raw, Loss of Material/ Chapter XI.M20, "Open-Cycle Cooling No 

subsystem (serviced by untreated salt General, pitting, Water System" 

open-cycle cooling water water or fresh crevice, 

system) water microbiologically 

H2.1.1 Piping and fittings influenced 

corrosion and 

biofoulinq H2.2-a Diesel engine starting air Carbon steel Moist air Loss of material/ A plant-specific aging management Yes, plant subsystem General, pitting program is to be evaluated. specific H2.2.1 Piping and fittings and crevice 

H2.2.2 Valves (hand and check) corrosion 

H2.2.3 Drain trap 

H2.2.4 Air accumulator vessel 

H2.3-a Diesel engine combustion Carbon steel Moist air Loss of material/ A plant-specific aging management Yes, plant air intake subsystem General, pitting program is to be evaluated. specific H2.3.1 Piping and fittings and crevice 

H2.3.2 Filter corrosion 

H2.3.3 Muffler 

H2.4-a Diesel engine combustion Carbon steel Hot diesel Loss of material/ A plant-specific aging management Yes, plant air exhaust subsystem engine General, pitting program is to be evaluated, specific 

H2.4.1 Piping and fittings exhaust and crevice 

H2.4.2 Muffler gases corrosion 

containing 

moisture and 

particulates I I

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H2., iE_ el-gellcy Diesel Gelne tlor Syst~em 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

H2.5-a Diesel engine fuel oil Carbon steel Diesel fuel oil Loss of Material/ Chapter XI.M30, "Fuel Oil Chemistry" Yes, 

subsystem General, pitting, detection 

H2.5.1 Tanks (day and drip) crevice and The AMP is to be augmented by of aging 

microbiologically verifying the effectiveness of fuel oil effects is 

influenced chemistry control. See Chapter XI.M32, to be 

corrosion "One-Time Inspection," for an evaluated 

1 acceptable verification program. I

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I. CARBON STEEL COMPONENTS

1.1 Carbon Steel Components 

1.1.1 External Surfaces 

1.2 Closure Bolting 

1.2.1 In High-Pressure or High-Temperature Systems

April 2001 VII I-1 NUREG-1801
I. CARBON STEEL COMPONENTS

Systems, Structures, and Components 

This section includes the aging management programs for the external surfaces of all carbon 

steel structures and components including closure boltings in the Auxiliary Systems in 

pressurized water reactors (PWRs) and boiling water reactors (BWRs). For the carbon steel 

components in PWRs, this section addresses only boric acid corrosion of external surface as a 

result of the dripping borated water that is leaking from an adjacent PWR component. Boric 

acid corrosion can also occur for carbon 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 VII 1-2 April 2001
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VII Auxiliary Systems 

I. Carbon Steel Components 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

1.1-a Carbon steel components Carbon steel, Air, leaking Loss Of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

(PWRs) low-alloy steel and dripping Boric acid 

1.1.1 External surfaces chemically corrosion of 

treated external surfaces 

borated water 

up to 3400C (644TF) 

1.1-b Carbon steel components Carbon steel, Air, moisture, Loss of material/ A plant-specific aging management Yes, plant (PWRs and BWRs) low-alloy steel and humidity General corrosion program is to be evaluated, specific 

1.1.1 External surfaces < 100°C 

(212.F) 

1.2-a Closure bolting Carbon steel, Air, moisture, Loss of material/ Chapter XI.M1 8, "Bolting Integrity" No 

1.2.1 In high-pressure or high- low-alloy steel humidity, and General corrosion 

temperature systems leaking fluid 

1.2-b Closure bolting Carbon steel, Air, moisture, Crack initiation Chapter XI.M18, "Bolting Integrity" No 

1.2.1 In high-pressure or high- low-alloy steel humidity, and and growth/ 

temperature systems leaking fluid Cyclic loading, 

stress corrosion 

cracking

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CHAPTER Viii 

STEAM AND POWER CONVERSION SYSTEM

April 2001 VIII-i NUREG-1 801
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NUREG-1 801 VIII-ii April 2001

I I
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 (AFW) System (PWR) 

H. Carbon Steel Components

April 2001 NUREG-1801 Vlll-iii
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NUREG-1801 VIII-iv April 2001

I I
A. STEAM TURBINE SYSTEM

A.1 Piping and Fittings 

A.1.1 High Pressure (HP) Turbine to Moisture Separator/Reheater (MSR) 

A.1.2 MSR to Low Pressure (LP) Turbine 

A.2 Valves (Stop, Control or Governor, Intermediate Stop and Control or Combined 

Intermediate, Bypass or Steam Dumps, Atmospheric Dumps, Main Steam Safety, or 

Safety/Relief) 

A.2.1 Body and Bonnet

April 2001 Vill A-1 NUREG-1 801
A. STEAM TURBINE SYSTEM

Systems, Structures, and Components 

This section comprises 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 and does not require an 

aging management review under 10 CFR 54.21 (a)(1). 

Aging management programs for the degradation of the external surfaces of carbon steel 

components are included in VIII.H. 

The system piping includes all pipe sizes, including instrument piping. 

System Interfaces 

The systems that interface with the steam turbine system include the main steam system 

(VIII.B1 and VIII.B2), the extraction steam system (VIII.C), and the condensate system (VIII.E).

NUREG-1 801 VIII A-2 April 2001

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Viii Steam and Power Conversion System 

A. Steam Turbine System 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

A.1-a Piping and fittings Carbon Steam Wall thinning/ Chapter XI.M17, "Flow-Accelerated No 

A.1.1 HP turbine to MSR steel Flow-accelerated Corrosion" 

A.1.2 MSR to LP turbine corrosion 

A.1-b Piping and fittings Carbon Steam Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, A.1.1 HP turbine to MSR steel General, pitting, BWR water in BWRVIP-29 (EPRI TR- detection of 

A.1.2 MSR to LP turbine and crevice 103515) or PWR secondary water in aging effects 

corrosion EPRI TR-1 02134 is to be 

evaluated 

The AMP is to be augmented by 

verifying the effectiveness of water 

chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

acceptable verification program. 

A.2-a Valves (stop, control or Carbon Steam Wall thinning Chapter XI.M1 7, "Flow-Accelerated No 

governor, intermediate stop steel (body only)/ Corrosion" (body only) 

and control or combined Flow-accelerated 

intermediate, bypass or corrosion 

steam dumps, atmospheric 

dumps, main steam safety, 

or safety/relief) 

A.2.1 Body and bonnet 

A.2-b Valves (stop, control or Carbon Steam Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, 

governor, intermediate stop steel General, pitting, BWR water in BWRVIP-29 (EPRI TR- detection of 

and control or combined and crevice 103515) or PWR secondary water in aging effects 

intermediate, bypass or corrosion EPRI TR-102134 is to be 

steam dumps, atmospheric evaluated 

dumps, main steam safety, The AMP is to be augmented by 

or safety/relief) verifying the effectiveness of water 

A.2.1 Body and bonnet chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

acceptable verification program.
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B1. MAIN STEAM SYSTEM (PWR)

B1.1 Piping and Fittings 

B1.1.1 Steam Lines from Steam Generator to Isolation Valves 

(Group B or C) 

B1.1.2 Steam Lines from Isolation Valves to Main Turbine (Group D) 

B1.1.3 Lines to Feedwater (FW) and Auxiliary Feedwater (AFW) Pump 

Turbines 

B1.1.4 Lines to Moisture Separator/Reheater (MSR) 

B1.1.5 Turbine Bypass 

B1.1.6 Steam Drains 

B1.2 Valves (Check, Control, Hand, Motor Operated, Safety, and 

Containment Isolation Valves) 

B1.2.1 Body and Bonnet

April 2001 V111 131-1 NUREG-1 801
B1 MAIN STEAM SYSTEM (PWR)

Systems, Structures, and Components 

This section comprises 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 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 the 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, or they are subject to replacement on the basis of qualified life or specified time 

period. Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of the external surfaces of carbon steel 

components are included in VIII.H. 

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-1 801 VIII B1-2 April 2001
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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

Bl.1-a Piping and fittings Carbon Up to 3005C Loss of material/ Chapter XI.M2, 'Water Chemistry," for No 

B1.1.1 Steam lines from steam steel (5720F) steam Pitting and crevice PWR secondary water in EPRI TR

generator to isolation valves corrosion 102134 

(Group B or C) 

B1.1.2 Steam lines from isolation 

valves to main turbine 

(Group D) 

Bl.1-b Piping and fittings Carbon Up to 300"C Cumulative Fatigue is a time-limited aging analysis Yes, 

B1.1.1 Steam lines from steam steel (5720 F) steam fatigue damage/ (TLAA) to be evaluated for the period TLAA 

generator to isolation valves Fatigue of extended operation. See the 

(Group B or C) Standard Review Plan, Section 4.3, 

"Metal Fatigue" for acceptable 

methods for meeting the requirements 

of 10 CFR 54.21 (c). Bl.1-c Piping and fittings Carbon Up to 3000C Wall thinning/ Chapter XI.M1 7, "Flow-Accelerated No 

B1.1.1 Steam lines from steam steel (5720F) steam Flow-accelerated Corrosion" 

generator to isolation valves corrosion 

(Group B or C) 

B1.1.2 Steam lines from isolation 

valves to main turbine 

(Group D) 

B1.1.3 Lines to FW and AFW pump 

turbines 

B1.1.4 Lines to MSR 

B1.1.5 Turbine bypass 

B1.1.6 Steam drains 

Bl.2-a Valves (check, control, hand, Carbon Up to 3000C Loss of material/ Chapter XI.M2, 'Water Chemistry," for No 

motor operated, safety, and steel (572°F) steam Pitting and crevice PWR secondary water in EPRI TR

containment isolation valves) corrosion 102134 

B1.2.1 Body and bonnet 

B1.2-b Valves (check, control, hand, Carbon Up to 3000C Wall thinning Chapter XI.M1 7, "Flow-Accelerated No 

motor operated, safety, and steel (5720F) steam (body only)/ Corrosion" (body only) 

containment isolation valves) Flow-accelerated 

B1.2.1 Body and bonnet corrosion
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B2 MAIN STEAM SYSTEM (BWR)

B2.1 Piping and Fittings 

B2.1.1 Steam Lines to Main Turbine (Group B) 

B2.1.2 Steam Lines to Main Turbine (Group D) B2.1.3 Lines to FW Pump Turbines 

B2.1.4 Turbine Bypass 

B2.1.5 Steam Drains 

B2.1.6 Steam Line to HPCI Turbine 

B2.1.7 Steam Line to RCIC Turbine 

B2.2 Valves (Check, Control, Hand, Motor Operated, Safety Valves) 

B2.2.1 Body and Bonnet

April 2001 Vill NUREG-1 801 132-1
B2. MAIN STEAM SYSTEM (BWR)

Systems, Structures, and Components 

This section comprises 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, and lines to 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 the 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 are applied 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 valve internals perform their intended functions with moving parts or with a change in 

configuration, or they are subject to replacement on the basis of qualified life or specified time 

period. Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of the external surfaces of carbon steel 

components are included in VIII.H. 

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 

(IL.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-1 801 VIII B2-2 April 2001
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VIII Steam Power Conversion System B2. Main Steam System 1RWR•

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

B2.1-a Piping and fittings Carbon 2880C Loss of rmaterial/ Chapter XI.M2, 'Water Chemistry," No 

B2.1.1 Steam lines to main turbine steel (5500 F) Pitting and crevice for BWR water in BWRVIP-29 (EPRI 

(Group B) steam corrosion TR-103515) 

B2.1.2 Steam lines to main turbine 

(Group D) 

B2.1-b Piping and fittings Carbon 2880C Wall thinning/ Chapter XI.M17, "Flow-Accelerated No 

B2.1.1 Steam lines to main turbine steel (550°F) Flow-accelerated Corrosion" 

(Group B) steam corrosion 

B2.1.2 Steam lines to main turbine 

(Group D) 

B2.1.3 Lines to FW pump turbines 

B2.1.4 Turbine bypass 

B2.1.5 Steam drains 

B2.1.6 Steam line to HPCI turbine 

B2.1.7 Steam line to RCIC turbine 

B2.1-c Piping and fittings Carbon 2880C Cumulative Fatigue is a time-limited aging Yes, 

B2.1.1 Steam lines to main turbine steel (550-F) fatigue damage/ analysis (TLAA) to be evaluated for TLAA 

(Group B) steam Fatigue the period of extended operation. See 

B2.1.2 Steam lines to main turbine the Standard Review Plan, 

(Group D) Section 4.3, "Metal Fatigue," for 

B2.1.3 Lines to FW pump turbines acceptable methods for meeting the 

B2.1.4 Turbine bypass requirements of 10 CFR 54.21 (c). 

B2.1.5 Steam drains 

B2.1.6 Steam line to HPCI turbine 

B2.1.7 Steam line to RCIC turbine 

B2.2-a Valves (check, control, hand, Carbon 28800 Wall thinning Chapter XI.M17, "Flow-Accelerated No 

motor operated, safety valves) steel (550°F) (body only)/ Corrosion" (body only) B2.2.1 Body and bonnet steam Flow-accelerated 

corrosion 

B2.2-b Valves (check, control, hand, Carbon 2880C Loss ofmaterial/ Chapter XI.M2, 'Water Chemistry," No 

motor operated, safety valves) steel (550°F) Pitting and crevice for BWR water in BWRVIP-29 (EPRI 

B2.2.1 Body and bonnet steam corrosion TR-1 03515)
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C. EXTRACTION STEAM SYSTEM 

C.1 Piping and Fittings 

C.1.1 Lines to Feedwater Heaters 

C.1.2 Steam Drains 

C.2 Valves 

C.2.1 Body and Bonnet

April 2001 Vill C-1 NUREG-1801
C. EXTRACTION STEAM SYSTEM

Systems, Structures, and Components 

This section comprises 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, or they are subject to replacement on the basis of qualified life or specified time 

period. Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of the external surfaces of carbon steel 

components are included in VIII.H. 

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 feedwater system (VIII.D1 and VU1I.D2), and the condensate system (VIII.E).

NUREG-1801 VIII C-2 April 2001

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ViII Steam Power Conversion System 

C. Extraction Stream System 

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

0.1-a Piping and fittings Carbon Up to 300°C Wall thinning/ Chapter XI.M17, "Flow-Accelerated No 

C.1.1 Lines to feedwater heaters steel (572°F) Flow-accelerated Corrosion" 

C.1.2 Steam drains steam corrosion 

C.1-b Piping and fittings Carbon Up to 3000C Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, C.1.1 Lines to feedwater heaters steel (5720 F) General, pitting, BWR water in BWRVIP-29 (EPRI detection 

C.1.2 Steam drains steam and crevice TR-103515) or PWR secondary water in of aging 

corrosion EPRI TR-1 02134 effects is to 

be 

The AMP is to be augmented by evaluated 

verifying the effectiveness of water 

chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

acceptable verification program. C.2-a Valves Carbon Up to 3000C Wall thinning Chapter XI.M17, "Flow-Accelerated No 

C.2.1 Body and bonnet steel (572°F) (body only)/ Corrosion" (body only) 

steam Flow-accelerated 

corrosion 

C.2-b Valves Carbon Up to 3000C Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, C.2.1 Body and bonnet steel (572°F) General, pitting, BWR water in BWRVIP-29 (EPRI detection 

steam and crevice TR-103515) or PWR secondary water in of aging 

corrosion EPRI TR-102134 effects is to 

be 

The AMP is to be augmented by evaluated 

verifying the effectiveness of water 

chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

acceptable verification program. I

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D1. FEEDWATER SYSTEM (PWR)

D1.1 Main Feedwater Line 

D1.1.1 Pipe and Fittings (Group B, C, or D) 

D1.2 Valves (Control, Check, Hand, Safety, and Containment Isolation Valves) 

D1.2.1 Body and Bonnet 

D1.3 Feedwater Pump (Steam Turbine and Motor Driven) 

D1.3.1 Casing 

D1.3.2 Suction and Discharge Lines

April 2001 V111 D1-1 NUREG-1801
D1. FEEDWATER SYSTEM (PWR)

Systems, Structures, and Components 

This section comprises the main feedwater system for pressurized water reactors (PWRs), 

which extends from the condensate system to the steam generator. They consist 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, and all 

other components in the feedwater system located downstream from the 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, or they are subject to replacement on the basis of qualified life or specified time 

period. Accordingly, they not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of the external surfaces of carbon steel 

components are included in VIII.H. 

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 I.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 V111 D1-2 April 2001
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ViII Steam and Power Conversion System D1. Feedwater System (PWR) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

"D1.1-a Main feedwater line Carbon Treated'water Wall thinning/ Chapter XI.M17, "Flow-Accelerated No 

D1.1.1 Piping and fittings steel Flow-accelerated Corrosion" 

(Group B, C, or D) corrosion 

D1.1-b Main feedwater line Carbon Treated water Cumulative Fatigue is a time-limited aging analysis Yes, D1.1.1 Piping and fittings (Group B steel fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

or C from steam generator to Fatigue extended operation. See the Standard 

isolation valves) Review Plan, Section 4.3, "Metal 

Fatigue" for acceptable methods for 

meeting the requirements of 10 CFR 

54.21 (c). 

D1.1-c Main feedwater line Carbon Treated water Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, D1.1.1 Piping and fittings steel General, pitting, PWR secondary water in EPRI detection of 

(Group B, C, or D) and crevice TR-1 02134 aging 

corrosion effects is 

The AMP is to be augmented by to be 

verifying the effectiveness of water evaluated 

chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

acceptable verification program. D1.2-a Valves (control, check, hand, Carbon Treated water Wall thinning Chapter XI.M17, "Flow-Accelerated No 

safety, and containment steel (body only)/ Corrosion" (body only) 

isolation valves) Flow-accelerated 

D1.2.1 Body and bonnet corrosion 

D1.2-b Valves (control, check, and Carbon Treated water Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, 

hand, safety, and containment steel General, pitting, PWR secondary water in EPRI detection of 

isolation valves) and crevice TR-102134 aging D1.2.1 Body and bonnet corrosion effects is 

The AMP is to be augmented by to be 

verifying the effectiveness of water evaluated 

chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

acceptable verification program.

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ViII Steam and Power Conversion System 

D1. Feedwater System (PWR) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D1.3-a Feedwater pump (steam Carbon Treated water Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, 

turbine and motor driven) steel General, pitting, PWR secondary water in EPRI detection of 

D1.3.1 Casing and crevice TR-102134 aging 

D1.3.2 Suction and discharge lines corrosion effects is 

The AMP is to be augmented by to be 

verifying the effectiveness of water evaluated 

chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

acceptable verification program. 

D1.3-b Feedwater pump (steam Carbon Treated water Wall thinning/ Chapter XI.M1 7, "Flow-Accelerated No 

turbine and motor driven) steel Flow-accelerated Corrosion" 

D1.3.2 Suction and discharge lines corrosion
D2. FEEDWATER SYSTEM (BWR)

D2.1 Main Feedwater Line 

D2.1.1 Pipe and Fittings (Group B or D) 

D2.2 Valves (Control, Check, and Hand Valves) 

D2.2.1 Body and Bonnet 

D2.3 Feedwater Pump (Steam Turbine and Motor Driven) 

D2.3.1 Casing 

D2.3.2 Suction and Discharge Lines

April 2001 VIII D2-1 NUREG-1801
D2. FEEDWATER SYSTEM (BWR)

Systems, Structures, and Components 

This section comprises 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. They consist 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 and 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, or they are subject to replacement on the basis of qualified life or specified time 

period. Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of the external surfaces of carbon steel 

components are included in VIII.H. 

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, 1l.B2, and I1.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 VIII D2-2 April 2001
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ViII Steam and Power Conversion System 

D2. Feedwater System (BWR) 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aling Management Program (AMP) Evaluation 

D2.1-a Main feedwater line Carbon Treated water Wall thinning/ Chapter XI.M17, "Flow-Accelerated No 

D2.1.1 Piping and fittings steel Flow-accelerated Corrosion" 

(Group B or D) I corrosion 

D2.1-b Main feedwater line Carbon Treated water Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, 

D2.1.1 Piping and fittings steel General, pitting, BWR water in BWRVIP-29 (EPRI detection of 

(Group B or D) and crevice TR-1 03515) aging 

corrosion effects is 

The AMP is to be augmented by to be 

verifying the effectiveness of water evaluated 

chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

I_ acceptable verification program. 

D2.1-c Main feedwater line Carbon Treated water Cumulative Fatigue is a time-limited aging analysis Yes, 

D2.1.1 Piping and fittings steel fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

(Group B or D) Fatigue extended operation. See the Standard 

Review Plan, Section 4.3, "Metal 

Fatigue" for acceptable methods for 

meeting the requirements of 10 CFR 

1_ _ 54.21(c). 

D2.2-a Valves (control, check, and Carbon Treated water Wall thinning Chapter XI.M17, "Flow-Accelerated No 

hand valves) steel (body only)/ Corrosion" (body only) 

D2.2.1 Body and bonnet Flow-accelerated 

corrosion 

D2.2-b Valves (control, check, and Carbon Treated water Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, 

hand valves) steel General, pitting, BWR water in BWRVIP-29 (EPRI detection of 

D2.2.1 Body and bonnet and crevice TR-1 03515) aging 

corrosion effects is 

The AMP is to be augmented by to be 

verifying the effectiveness of water evaluated 

chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

I acceptable verification program. 

D2.3-a Feedwater pump (steam Carbon Treated water Wall thinning/ Chapter XI.M1 7, "Flow-Accelerated No 

turbine and motor driven) steel Flow-accelerated Corrosion" 

D2.3.2 Suction and discharge lines corrosion
Steam and Power Conversion System D2. Feedwater System (BWR• VIII z 

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

D2.3-b Feedwater pump (steam Carbon Treated water Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, 

turbine and motor driven) steel General, pitting, BWR water in BWRVIP-29 (EPRI detection of 

D2.3.1 Casing and crevice TR-1 03515) aging 

D2.3.2 Suction and discharge lines corrosion effects is 

The AMP is to be augmented by to be 

verifying the effectiveness of water evaluated 

chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

acceptable verification program.

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E. CONDENSATE SYSTEM

E.1 Condensate Lines 

E.1.1 Piping and Fittings 

E.2 Valves 

E.2.1 Body and Bonnet 

E.3 Condensate Pumps (Main and Booster Pumps) 

E.3.1 Casing 

E.4 Condensate Coolers/Condensers 

E.4.1 Tubes 

E.4.2 Tubesheet 

E.4.3 Channel Head 

E.4.4 Shell 

E.5 Condensate Storage 

E.5.1 Tank 

E.6 Condensate Cleanup System 

E.6.1 Piping and Fittings 

E.6.2 Demineralizer 

E.6.3 Strainer

April 2001 Vill E-1 NUREG-1801
E. CONDENSATE SYSTEM

Systems, Structures, and Components 

This section comprise 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-Waste

Containing 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, or they are subject to replacement on the basis of qualified life or specified time 

period. Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of the external surfaces of carbon steel 

components are included in VIII.H. 

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 main steam system (VIII.B1 and VIII.B2), the feedwater system (VIII.D1 and 

VIII.D2), the auxiliary feedwater system (VIII.G, PWR only), the reactor water cleanup system 

(VII.E3, BWR and PWR if used), the open or closed cycle cooling water systems (VII.C1 or 

VII.C2), and the condensate storage facility.

NUREG-1801 VIII E-2 April 2001

I I
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VIII Steam and Power Conversion System 

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

E.1-a Condensate lines Carbon steel Treated water Wall'thinning/ Chapter XI.M17, "Flow-Accelerated No 

E.1.1 Piping and fittings (BWRs: Flow-accelerated Corrosion" 

reactor corrosion 

coolant; 

PWRs: 

secondary 

side water) 

E.1-b Condensate lines Carbon steel Treated water Loss of material/ Chapter XI.M2, 'Water Chemistry," Yes, 

E.1.1 Piping and fittings (BWRs: General, pitting, for BWR water in BWRVIP-29 (EPRI detection of 

reactor and crevice TR-1 03515) or PWR secondary water aging 

coolant; corrosion in EPRI TR-102134 effects is 

PWRs: to be 

secondary The AMP is to be augmented by evaluated 

side water) verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, "One-Time Inspection," for an 

I_ acceptable verification program. 

E.2-a Valves Carbon steel Treated water Wall thinning Chapter XI.M1 7, "Flow-Accelerated No 

E.2.1 Body and bonnet (body only)/ Corrosion" (body only) 

Flow-accelerated 

corrosion 

E.2-b Valves Carbon steel Treated water Loss of material/ Chapter XI.M2, 'Water Chemistry," Yes, 

E.2.1 Body and bonnet General, pitting, for BWR water in BWRVIP-29 (EPRI detection of 

and crevice TR-1 03515) or PWR secondary water aging 

corrosion in EPRI TR-102134 effects is 

to be 

The AMP is to be augmented by evaluated 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, "One-Time Inspection," for an 

I acceptable verification program. I
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ViII Steam and Power Conversion System 

E. Condensate System 

Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

E.3-a Condensate pumps Carbon steel Treated water Loss of material/ Chapter XI.M2, 'Water Chemistry," Yes, (main and booster pumps) General, pitting, for BWR water in BWRVIP-29 (EPRI detection of E.3.1 Casing and crevice TR-103515) or PWR secondary water aging 

corrosion in EPRI TR-102134 effects is 

to be 

The AMP is to be augmented by evaluated 

verifying the effectiveness of water 

chemistry control. See Chapter XI.M32, "One-Time Inspection," for an 

acceptable verification program. E.4-a Condensate coolers/ Tubes: Treated water Loss of material/ Chapter XI.M2, 'Water Chemistry," Yes, condensers (serviced by stainless steel; side General (carbon for BWR water in BWRVIP-29 (EPRI detection of 

open-cycle cooling water) tubesheet: (condensate steel only), pitting, TR-1 03515) or PWR secondary water aging E.4.1 Tubes carbon steel; side) and crevice in EPRI TR-102134 effects is 

E.4.2 Tubesheet channel head: corrosion to be E.4.3 Channel head carbon steel; The AMP is to be augmented by evaluated 

E.4.4 Shell shell: carbon verifying the effectiveness of water 

steel chemistry control. See Chapter XI.M32, "One-Time Inspection," for an 

I_ acceptable verification program. E.4-b Condensate coolers/ Tubes: Open-cycle Loss of material/ Chapter XI.M20, "Open-Cycle No 

condensers (serviced by stainless steel; cooling water General (carbon Cooling Water System" open-cycle cooling water) tubesheet: (raw water) steel only), pitting, E.4.1 Tubes carbon steel; side crevice, and 

E.4.2 Tubesheet channel head: microbiologically E.4.3 Channel head carbon steel; influenced 

E.4.4 Shell shell: carbon corrosion, and 

I steel biofoulini 

E.4-c Condensate coolers/ Tubes: Open-cycle Buildup of Chapter XI.M20, "Open-Cycle No 

condensers (serviced by stainless steel cooling water deposit/ Cooling Water System" open-cycle cooling water) (raw water) Biofouling E.4.1 Tubes side
( (

M> 

mn

ViII Steam and Power Conversion System 

E. Condensate System 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

E.4-d Condensate coolers/ Tubes: Treated water Loss of material/ Chapter XI.M2, 'Water Chemistry," Yes, condensers (serviced by stainless steel; side (on other General (carbon for BWR water in BWRVIP-29 (EPRI detection of 

closed-cycle cooling water) tubesheet: side of steel only), pitting, TR-103515) or PWR secondary water aging E.4.1 Tubes carbon steel; condensate) and crevice in EPRI TR-102134 effects is 

E.4.2 Tubesheet channel head: corrosion to be E.4.3 Channel head carbon steel; The AMP is to be augmented by evaluated 

E.4.4 Shell shell: carbon verifying the effectiveness of water 

steel chemistry control. See Chapter 

XI.M32, "One-Time Inspection," for an 

acceptable verification program. E.4-e Condensate coolers/ Tubes: Closed-cycle Loss of material/ Chapter XI.M21, "Closed-Cycle No 

condensers (serviced by stainless steel; cooling water General (carbon Cooling Water System" closed-cycle cooling water) tubesheet: side steel only), pitting, E.4.1 Tubes carbon steel; and crevice 

E.4.2 Tubesheet channel head: corrosion 

E.4.3 Channel head carbon steel; 

E.4.4 Shell shell: carbon 

steel 

E.5-a Condensate storage Carbon steel <90°C Loss of material/ Chapter XI.M2, 'Water Chemistry," Yes, E.5.1 Tank (<194°F) General, pitting, for BWR water in BWRVIP-29 (EPRI detection of 

treated water and crevice TR-103515) or PWR secondary water aging corrosion in EPRI TR-102134 effects is 

to be 

The AMP is to be augmented by evaluated 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, "One-Time Inspection," for an 

I acceptable verification program. I

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E. Condensate System 

Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

E.5-b Condensate storage Stainless steel <90 0C Loss of material/ Chapter XI.M2, 'Water Chemistry," Yes, 

E.5.1 Tank (<1 94°F) Pitting and crevice for BWR water in BWRVIP-29 (EPRI detection of 

treated water corrosion TR-1 03515) or PWR secondary water aging 

in EPRI TR-102134 effects is 

to be 

The AMP is to be augmented by evaluated 

verifying the effectiveness of water 

chemistry control. See Chapter 

XI.M32, "One-Time Inspection," for an 

acceptable verification program. 

E.5-c Condensate storage Carbon steel Sun, weather, Loss of material/ Chapter XI.M29, "Aboveground No 

E.5.1 Tank (aboveground, humidity, and General corrosion Carbon Steel Tanks" 

external surface) moisture 

E.5-d Condensate storage Carbon steel Soil and Loss of material/ Chapter XI.M28, "Buried Piping and No 

E.5.1 Tank (buried, external ground water General, pitting, Tanks Surveillance," or 

surface) crevice, and 

microbiologically Chapter XI.M34, "Buried Piping and Yes, 

influenced Tanks Inspection" detection of 

corrosion aging 

effects and 

operating 

experience 

are to be 

further 

evaluated

V 

0• 

0
ViII Steam and Power Conversion System 

E. Condensate System 

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

E.6-a Condensate cleanup Carbon steel Treated water Loss of material/ Chapter XI.M2, 'Water Chemistry," Yes, 

system General, pitting, for BWR water in BWRVIP-29 (EPRI detection of 

E.6.1 Piping and fittings and crevice TR-103515) or PWR secondary water aging 

E.6.2 Demineralizer corrosion in EPRI TR-102134 effects is 

E.6.3 Strainer to be 

The AMP is to be augmented by evaluated 

verifying the effectiveness of water 

chemistry control. See 

Chapter XI.M32, "One-Time 

Inspection," for an acceptable 

verification program. I

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F. STEAM GENERATOR BLOWDOWN SYSTEM (PWR) 

F.1 Blowdown Lines 

F.1.1 Pipe and Fittings (Group B) 

F.1.2 Pipe and Fittings (Group D) 

F.2 Valves (including Containment Isolation Valves) 

F.2.1 Body and Bonnet 

F.3 Blowdown Pump 

F.3.1 Casing 

F.4 Blowdown Heat Exchanger 

F.4.1 Tubes 

F.4.2 Tubesheet 

F.4.3 Channel Head and Access Cover 

F.4.4 Shell and Access Cover

April 2001 V111 F-1 NUREG-1801
F. STEAM GENERATOR BLOWDOWN SYSTEM (PWR)

Systems, Structures, and Components 

This section comprises the steam generator blowdown system for pressurized water reactors 

(PWRs), which extends from the steam generator through the blowdown condenser and include 

the containment isolation valves and small bore piping less than NPS 2 (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, or they are subject to replacement on the basis of qualified life or specified time 

period. Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of the external surfaces of carbon steel 

components are included in VIII.H. 

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-1 801 VIII F-2 April 2001

I I
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ViII

(

Steam and Power Conversion System V 

0 

0 

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CA)

S • ,F• l ,,I;I ~ I•;I ~MI DIU'SJVVII_,•y IIIEVlll _.rVVr 

Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

F.1 -a Blowdown lines Carbon Secondary Wall'thinning/ Chapter XI.M1 7, "Flow-Accelerated No F.1.1 Piping and fittings (Group B) steel side treated Flow-accelerated Corrosion" 

F.1.2 Piping and fittings (Group D) water corrosion 

F.1-b Blowdown lines Carbon Secondary Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, F.1.1 Piping and fittings (Group B) steel side treated General, pitting, PWR secondary water in EPRI detection of F.1.2 Piping and fittings (Group D) water and crevice TR-102134 aging 

corrosion effects is 

The AMP is to be augmented by to be 

verifying the effectiveness of water evaluated 

chemistry control. See 

Chapter XI.M32, "One-Time 

Inspection," for an acceptable verification program. F.2-a Valves (including containment Carbon Secondary Wall thinning Chapter XI.M17, "Flow-Accelerated No isolation valves) steel side treated (body only)/ Corrosion" (body only) F.2.1 Body and bonnet water Flow-accelerated 

corrosion 

F.2-b Valves (including containment Carbon Secondary Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, isolation valves) steel side treated General, pitting, PWR secondary water in EPRI detection of F.2.1 Body and bonnet water and crevice TR-1 02134 aging 

corrosion effects is 

The AMP is to be augmented by to be 

verifying the effectiveness of water evaluated 

chemistry control. See 

Chapter XI.M32, "One-Time 

Inspection," for an acceptable 

verification program.

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

F.3-a Blowdown pump Carbon Secondary Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, F.3.1 Casing steel side treated General, pitting, PWR secondary water in EPRI detection of 

water and crevice TR-1 02134 aging 

corrosion effects is 

The AMP is to be augmented by to be 

verifying the effectiveness of water evaluated 

chemistry control. See 

Chapter XI.M32, "One-Time 

Inspection," for an acceptable 

verification program. 

F.4-a Blowdown heat exchanger Tubes: Secondary Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, 

(serviced by open-cycle stainless side treated General (carbon PWR secondary water in EPRI TR- detection of 

cooling water) steel; water steel only), pitting, 102134 aging F.4.1 Tubes tubesheet: and crevice effects is 

F.4.2 Tubesheet carbon corrosion The AMP is to be augmented by to be 

F.4.3 Channel head and access steel; verifying the effectiveness of water evaluated 

cover channel chemistry control. See 

F.4.4 Shell and access cover head: Chapter XI.M32, "One-Time 

carbon Inspection," for an acceptable I steel verification program. F.4-b Blowdown heat exchanger Tubes: Open-cycle Loss of material/ Chapter X I.M20, "Open-Cycle Cooling No 

(serviced by open-cycle stainless cooling water General (carbon Water System" 

cooling water) steel; (raw water) steel only), pitting, 

F.4.1 Tubes tubesheet: side crevice, and 

F.4.2 Tubesheet carbon microbiologically 

F.4.3 Channel head and access steel; influenced 

cover channel corrosion, and 

F.4.4 Shell and access cover head: biofouling 

carbon 

steel 

F.4-c Blowdown heat exchanger Tubes: Open-cycle Buildup of Chapter XI.M20, "Open-Cycle Cooling No 

(serviced by open cycle cooling stainless cooling water deposit/ Water System" 

water) steel (raw water) Biofouling 

.-- F.4.1 Tubes side
Steam and Power Conversion System F. Steam Generator Biowdown System (PWRF

(

V VIII

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation F.4-d Blowdown heat exchanger Tubes: Treated water Loss of'material/ Chapter XI.M2, 'Water Chemistry," for Yes , (serviced by closed-cycle stainless side (other General (carbon PWR secondary water in EPRI detection of cooling water) steel; side of steam steel only), pitting, TR-1 02134 aging F.4.1 Tubes tubesheet: generator and crevice effects is F.4.2 Tubesheet carbon blowdonwn) corrosion The AMP is to be augmented by to be F.4.3 Channel head and access steel; verifying the effectiveness of water evaluated 

cover channel chemistry control. See F.4.4 Shell and access cover head: Chapter XI.M32, "One-Time 

carbon Inspection," for an acceptable steel verification program. F.4-e Blowdown heat exchanger Tubes: Closed-cycle Loss of material/ Chapter XI.M21, "Closed-Cycle No (serviced by closed-cycle stainless cooling water General (carbon Cooling Water System" cooling water) steel; side steel only), pitting, F.4.1 Tubes tubesheet: and crevice 

F.4.2 Tubesheet carbon corrosion 

F.4.3 Channel head and access steel; 

cover channel 

F.4.4 Shell and access cover head: 

carbon 

steel

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G. AUXILIARY FEEDWATER SYSTEM (PWR)

G.1 Auxiliary Feedwater Piping 

G.1.1 Piping and Fittings (Aboveground) 

G.1.2 Piping and Fittings (Buried) 

G.2 AFW Pumps (Steam Turbine and Motor Driven) 

G.2.1 Casing 

G.2.2 Suction and Discharge Lines 

G.3 Valves (Control, Check, Hand, and Containment Isolation Valves) 

G.3.1 Body and Bonnet 

G.4 Condensate Storage (Emergency) 

G.4.1 Tank 

G.5 Bearing Oil Coolers (for Steam Turbine Pump) 

G.5.1 Shell 

G.5.2 Tubes 

G.5.3 Tubesheet

April 2001 NUREG-1801 VIII G-1
G. AUXILIARY FEEDWATER SYSTEM (PWR)

Systems, Structures, and Components 

This section comprises 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, and 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, or they are subject to replacement on the basis of qualified life or specified time 

period. Accordingly, they are not subject to an aging management review, pursuant to 10 CFR 

54.21 (a)(1). 

Aging management programs for the degradation of the external surfaces of carbon steel 

components are included in VIII.H. 

The system piping includes all pipe sizes, including instrument piping. 

System Interfaces 

The systems that interface with the auxiliary feedwater 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 VIII G-2 April 2001

I I
(

VIII Steam and Power Conversion System G. Auxiliary Feedwater System (PWR•,

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Structure and/or Aging Effectl Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

G.1-a Auxiliary feedwater piping Carbon Treated water Wall thinning/ Chapter XI.M17, "Flow-Accelerated No 

G.1.1 Piping and fittings steel >90°C Flow-accelerated Corrosion" 

(aboveground) for (>194°F) corrosion 

Westinghouse steam 

generators with preheaters 

G.1-b Auxiliary feedwater piping Carbon Treated water Cumulative Fatigue is a time-limited aging analysis Yes, G.1.1 Piping and fittings steel >90*C fatigue damage/ (TLAA) to be evaluated for the period of TLAA 

(aboveground) (>194°F) Fatigue extended operation. See the Standard 

Review Plan, Section 4.3, "Metal 

Fatigue" for acceptable methods for 

meeting the requirements of 10 CFR 

54.21 (c). 

G.1-c Auxiliary feedwater piping Carbon Treated water Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, G.1.1 Piping and fittings steel General, pitting, PWR secondary water in EPRI detection of 

(aboveground) and crevice TR-102134 aging G.1.2 Piping and fittings (buried) corrosion effects is 

The AMP is to be augmented by to be 

verifying the effectiveness of water evaluated 

chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

acceptable verification program. G.1-d Auxiliary feedwater piping Carbon Untreated Loss of material/ A plant-specific aging management Yes, plant G.1.1 Piping and fittings steel water from General, pitting, program is to be evaluated, specific (aboveground) backup water crevice, and 

G.1.2 Piping and fittings (buried) supply microbiologically 

influenced 

corrosion, and 

biofouling

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Structure and/or Aging Effect/ Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

G.1-e Auxiliary feedwater piping Carbon' Soil and Loss of material/ Chapter XI.M28, "Buried Piping and No 

G.1.2 Piping and fittings (buried) steel groundwater General, pitting, Tanks Surveillance," or 

external surface crevice, and 

microbiologically Chapter XI.M34, "Buried Piping and Yes, 

influenced Tanks Inspection" detection of 

corrosion aging 

effects and 

operating 

experience 

are to be 

further 

evaluated 

G.2-a AFW pumps (steam turbine Carbon Treated water Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, and motor driven) steel <90°C General, pitting, PWR secondary water in EPRI detection of 

G.2.1 Casing (<194°F) and crevice TR-102134 aging G.2.2 Suction and discharge lines corrosion effects is 

The AMP is to be augmented by to be 

verifying the effectiveness of water evaluated 

chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

acceptable verification program. G.3-a Valves (control, check, hand, Carbon Treated water Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, 

and containment isolation steel <90°C General, pitting, PWR secondary water in EPRI detection of 

valves) (<194°F) and crevice TR-102134 aging G.3.1 Body and bonnet corrosion effects is 

The AMP is to be augmented by to be 

verifying the effectiveness of water evaluated 

chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

acceptable verification program.

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Steam and Power Conversion System G. Auxiliary Feedwater System (PWR•

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Structure and/or Aging Effect/ Further Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

G.4-a Condensate storage Carbonr Treated water Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, (emergency) steel <90TC General, pitting, PWR secondary water in EPRI detection of G.4.1 Tank (<1940 F) and crevice TR-102134 aging 

corrosion effects is 

The AMP is to be augmented by to be 

verifying the effectiveness of water evaluated 

chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

G.4-b Condensate acceptable verification program. storage Stainless Treated water Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes, (emergency) steel <90°C Pitting and crevice PWR secondary water in EPRI detection of G.4.1 Tank (<194°F) corrosion TR-1 02134 aging 

effects is 

The AMP is to be augmented by to be 

verifying the effectiveness of water evaluated 

chemistry control. See Chapter XI.M32, 

"One-Time Inspection," for an 

acceptable verification program. G.4-c Condensate storage Carbon Sun, weather, Loss of material/ Chapter XI.M29, "Aboveground Carbon No (emergency) steel humidity, and General corrosion Steel Tanks" 

G.4.1 Tank (aboveground, moisture 

external surface) G.4-d Condensate storage Carbon Soil and Loss of material/ Chapter XI.M28, "Buried Piping and No (emergency) steel groundwater General, pitting, Tanks Surveillance," or G.4.1 Tank (buried, external crevice, and surface) microbiologically Chapter XI.M34, "Buried Piping and Yes, 

influenced Tanks Inspection" detection of 

corrosion aging 

effects and 

operating 

experience 

are to be 

further 

evaluated
z 

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ViII Steam and Power Conversion System 

G. Auxiliary Feedwater System (PWR) 

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

G.5-a Bearing oil coolers (for steam Stainless Open-cycle Loss of material/ Chapter XI.M20, "Open-Cycle Cooling No 

turbine pump) serviced by steel, cooling water General (carbon Water System" 

open-cycle cooling water carbon (raw water) steel only), pitting, 

G.5.1 Shell steel crevice, and 

G.5.2 Tubes microbiologically 

G.5.3 Tubesheet influenced 

corrosion, and 

I_ biofouling 

G.5-b Bearing oil coolers (for steam Stainless Open-cycle Buildup of Chapter XI.M20, "Open-Cycle Cooling No 

turbine pump) serviced by steel, cooling water deposit/ Water System" 

open-cycle cooling water carbon (raw water) Biofouling 

G.5.2 Tubes steel 

G.5-c Bearing oil coolers (for steam Stainless Closed-cycle Loss of material/ Chapter XI.M21, "Closed-Cycle Cooling No 

turbine pump) serviced by steel, cooling water General (carbon Water System" 

closed-cycle cooling water carbon (treated steel only), pitting, 

G.5.1 Shell steel water) and crevice 

G.5.2 Tubes corrosion 

G.5.3 Tubesheet 

G.5-d Bearing oil coolers (for steam Stainless Lubricating oil Loss of material/ A plant-specific aging management Yes, 

turbine pump) steel, (possibly General (carbon program is to be evaluated, plant 

G.5.1 Shell carbon contaminated steel only), pitting, specific 

G.5.2 Tubes steel with water) crevice, and 

G.5.3 Tubesheet microbiologically 

influenced 

I corrosion I

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H. CARBON STEEL COMPONENTS

H.1 Carbon Steel Components 

H.1.1 External Surfaces 

H.2 Closure Bolting 

H.2.1 In High-Pressure or High-Temperature Systems

April 2001 Vill H-1 NUREG-1801
H. CARBON STEEL COMPONENTS

Systems, Structures, and Components 

This section includes the aging management programs for the degradation of external surfaces of all carbon steel structures and components, including closure boltings in the steam and 

power conversion system in pressurized water reactors (PWRs) and boiling water reactors (BWRs). For the carbon steel components in PWRs, this section addresses only boric acid corrosion of external surfaces as a result of the dripping borated water that is 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-1 801 April 2001 V111 H-2
( ( (

C> 

9 

'A)

ViII Steam and Power Conversion System 

H. Carbon Steel Components 

Structure and/or Aging Effectl Further 

Item Component Material Environment Mechanism Aging Management Program (AMP) Evaluation 

H.1-a Carbon steel components Carbon Air,'leaking Loss of material/ Chapter XI.M10, "Boric Acid Corrosion" No 

(PWRs) steel, low- and dripping Boric acid 

H.1.1 External Surfaces alloy steel chemically corrosion of 

treated external surfaces 

borated water 

up to 34000 (644TF) 

H.1-b Carbon steel components Carbon Air, moisture, Loss of material/ A plant-specific aging management Yes, plant (PWRs and BWRs) steel, low- and humidity General corrosion program is to be evaluated, specific 

H.1.1 External surfaces alloy steel <100°C 

(212°F) 

H.2-a Closure bolting Carbon Air, moisture, Loss of material/ Chapter XI.M18, "Bolting Integrity" No 

H.2.1 In high-pressure or high- steel, low- humidity, and General corrosion 

temperature systems alloy steel leaking fluid 

H.2-b Closure bolting Carbon Air, moisture, Crack initiation Chapter XI.M1 8, "Bolting Integrity" No 

H.2.1 In high-pressure or high- steel, low- humidity, and and growth/ 

temperature systems alloy steel leaking fluid Cyclic loading, 

stress corrosion 

cracking

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CHAPTER IX 

NOT USED

April 2001 IX-1 NUREG-1 801
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NUREG-1801 IX-2 April 2001

I I
CHAPTER X 

TIME-LIMITED AGING ANALYSES 

EVALUATION OF AGING MANAGEMENT PROGRAMS 

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

April 2001 X-i NUREG-1801
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NUREG-1801 X-ii April 2001

I I
TIME-LIMITED AGING ANALYSES: EVALUATION OF AGING MANAGEMENT PROGRAMS 

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

X.M1 Metal Fatigue of Reactor Coolant Pressure Boundary 

X.S1 Concrete Containment Tendon Prestress 

X.E1 Environmental Qualification (EQ) of Electrical Components

April 2001 X-iii NUREG-1801
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NUREG-1801 X-iv April 2001
X.M1 METAL FATIGUE OF REACTOR COOLANT PRESSURE BOUNDARY 

Program Description 

In order not to exceed the design limit on fatigue usage, the aging management program (AMP) monitors and tracks the number of critical thermal and pressure transients for the selected 

reactor coolant system components. 

The AMP addresses the effects of the coolant environment on component fatigue life by assessing the impact of the reactor coolant environment on a sample of critical components that 

includes, as a minimum, those components selected in NUREG/CR-6260. The sample of critical 

components can be evaluated by applying environmental correction factors to the existing ASME Code fatigue analyses. Formulas for calculating the environmental life correction factors 

are contained in NUREG/CR-6583 for carbon and low-alloy steels and in NUREG/CR-5704 for 

austenitic stainless steels. 

As evaluated below, this is an acceptable option for managing metal fatigue for the reactor 

coolant pressure boundary, considering environmental effects. Thus, no further evaluation is 

recommended for license renewal if the applicant selects this option under 10 CFR 

54.21 (c)(1)(iii) to evaluate metal fatigue for the reactor coolant pressure boundary. 

Evaluation and Technical Basis 

1. Scope of Program: The program includes preventive measures to mitigate fatigue cracking of metal components of the reactor coolant pressure boundary caused by anticipated cyclic strains in the material. 

2. Preventive Actions: Maintaining the fatigue usage factor below the design code limit and 

considering the effect of the reactor water environment, as described under the program description, will provide adequate margin against fatigue cracking of reactor coolant system 

components due to anticipated cyclic strains. 

3. Parameters Monitored/Inspected: The program monitors all plant transients that cause 

cyclic strains, which are significant contributions to the fatigue usage factor. The number of 

plant transients that cause significant fatigue usage for each reactor coolant pressure boundary component is to be monitored. Alternatively, more detailed local monitoring of the 

plant transient may be used to compute the actual fatigue usage for each transient. 

4. Detection of Aging Effects: The program provides for periodic update of the fatigue usage 

calculations. 

5. Monitoring and Trending: The program monitors a sample of high fatigue usage locations. 

As a minimum, this sample is to include the locations identified in NUREG/CR-6260. 

6. Acceptance Criteria: The acceptance criteria involves maintaining the fatigue usage below 

the design code limit considering environmental fatigue effects as described under the 

program description. 

7. Corrective Actions: The program provides for corrective actions to prevent the usage factor from exceeding the design code limit during the period of extended operation.

April 2001 X M-1 NUREG-1801
Acceptable corrective actions include a more rigorous analysis of the component to 

demonstrate that the design code limit will not be exceeded, repair, or replacement of the 

component. For programs that monitor a sample of high fatigue usage locations, corrective 

actions include a review of additional affected reactor coolant pressure boundary locations. 

8. Conformation Process: Site quality assurance procedures, review and approval processes and administrative controls are implemented in accordance with the requirements of 

Appendix B to 10 CFR Part 50. As discussed in the appendix to this report, the staff finds 

the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing the confirmation 

process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: The program reviews industry experience regarding fatigue cracking. Applicable experience with fatigue cracking is to be considered in selecting the 

monitored locations. 

References 

NUREG/CR-5704, Effects of LWR Coolant Environments on Fatigue Design Curves of Austenitic Stainless Steels, U.S. Nuclear Regulatory Commission, April 1999. 

NUREG/CR-6260, Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear 

Power Plant Components, U.S. Nuclear Regulatory Commission, March 1995. 

NUREG/CR-6583, Effects of LWWR Coolant Environments on Fatigue Design Curves of Carbon 

and Low-Alloy Steels, U.S. Nuclear Regulatory Commission, March 1998.

NUREG-1801 X M-2 April 2001
X.S1 CONCRETE CONTAINMENT TENDON PRESTRESS

Program Description 

In order to ensure the adequacy of prestressing forces in prestressed concrete containments 

during the extended period of operation, an applicant can develop an aging management 

program (AMP) under 10 CFR 54.21 (c)(1)(iii). 

The AMP consists of an assessment of the results of inspections performed in accordance with 

the requirements of Subsection IWL of the ASME Section Xl Code, as supplemented by the 

requirements of 10 CFR 50.55a(b)(2)(ix) or (viii) in the later amendment of the regulation. The 

assessment related to the adequacy of the prestressing force will consist of the establishment of 

(1) acceptance criteria and (2) trend lines. The acceptance criteria will normally consist of 

predicted lower limit (PLL) and the minimum required prestressing force, also called minimum 

required value (MRV). NRC Regulatory Guide 1.35.1 provides guidance for calculating PLL and 

MRV. The trend line represents the trend of prestressing forces based on the actual measured 

forces. NRC Information Notice IN 99-10 provides guidance for constructing the trend line. The 

goal is to keep the trend line above the PLL because, as a result of any inspection performed in 

accordance with ASME Section Xl, Subsection IWL, if the trend line crosses the PLL, the 

existing prestress in the containment could go below the MRV soon after the inspection and 

would not meet the requirements of 10 CFR 50.55a(b)(2)(ix)(B) or 10 CFR 50.55a(b)(2)(viii)(B). 

As evaluated below, this is an acceptable option to manage containment tendon prestress force, 

except for the program element/attribute regarding operating experience. Thus, it is 

recommended that the staff should further evaluate an applicants operating experience related 

to the containment prestress force. 

The AMP related to the adequacy of prestressing force for containments with grouted tendons 

will be reviewed on a case-by-case basis. 

Evaluation and Technical Basis 

1. Scope of Program: The program addresses the assessment of containment prestressing force when an applicant chooses to perform the containment prestress force TLAA using 10 

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

2. Preventive Actions: Maintaining the prestress above the MRV, as described under 

program description above, will ensure that the structural and functional adequacy of the 

containment are maintained. 

3. Parameters Monitored: The parameters to be monitored are the containment prestressing 

forces in accordance with requirements specified in Subsection IWL of Section Xl of the 

ASME Code, as incorporated by reference in 10 CFR 50.55a. 

4. Detection of Aging Effects: The loss of containment prestressing forces is detected by the 

program. 

5. Monitoring and Trending: The estimated and measured prestressing forces are plotted against time and the PLL, MRV, and trending lines developed for the period of extended 

operation.

April 2001 X S-1 NUREG-1801
6. Acceptance Criteria: The prestressing force trend lines indicate that existing prestressing 

forces in the containment would not be below the MRVs prior to the next scheduled 

inspection, as required by 10 CFR 50.55a(b)(2)(ix)(B) or 10 CFR 50.55a(b)(2)(viii)(B). 

7. Corrective Actions: If acceptance criteria are not met, then either systematic retensioning 

of tendons or a reanalysis of the containment is warranted to ensure the design adequacy of 

the containment. As discussed in the appendix to this report, the staff finds the requirements 

of 10 CFR Part 50, Appendix B, acceptable to address corrective actions. 

8. Conformation Process: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process. 

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address administrative controls. 

10. Operating Experience: The program incorporates the relevant operating experience that 

has occurred at the applicant's plant as well as at other plants. The applicable portions of 

the experience with prestressing systems described in NRC Information Notice 99-10 could 

be useful for the purpose. However, tendon operating experience could be different at plants 

with prestressed concrete containments. The difference could be due to the prestressing 

system design (e.g., button-headed, wedge, or swaged anchorages), environment, and type 

of reactor (i.e., PWR and BWR). Thus, the applicant's plant-specific operating experience 

should be further evaluated for license renewal. 

References 

ASME Section XI, Rules for In-Service Inspection of Nuclear Power Plant Components, 

Subsection IWL, Requirements for Class CC Concrete Components of Light-Water Cooled 

Plants, 1992 Edition with 1992 Addenda; 1995 Edition with 1996 Addenda, The ASME 

Boiler and Pressure Vessel Code, The American Society of Mechanical Engineers, New 

York, NY. 

NRC Information Notice 99-10, Degradation of Prestressing Tendon Systems in Prestressed 

Concrete Containments, U. S. Nuclear Regulatory Commission, April 1999. 

NRC Regulatory Guide 1.35.1, Determining Prestressing Forces for Inspection of Prestressed 

Concrete Containments, U. S. Nuclear Regulatory Commission, July 1990. 

NUREG-1801 X S-2 April 2001

I I
X.E1 ENVIRONMENTAL QUALIFICATION (EQ) OF ELECTRIC COMPONENTS 

Program Description 

The Nuclear Regulatory Commission (NRC) has established nuclear station environmental 

qualification (EQ) requirements in 10 CFR Part 50, Appendix A, Criterion 4, and 10 CFR 50.49. 

10 CFR 50.49 specifically requires that an EQ program be established to demonstrate that 

certain electrical components located in harsh plant environments (that is, those areas of the 

plant that could be subject to the harsh environmental effects of a loss of coolant accident 

[LOCA], high energy line breaks [HELBs] or post-LOCA 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. 

All operating plants must meet the requirements of 10 CFR 50.49 for certain electrical 

components important to safety. 10 CFR 50.49 defines the scope of components to be included, 

requires the preparation and maintenance of a list of in-scope components, and requires the 

preparation and maintenance of a qualification file that includes component performance 

specifications, electrical characteristics, and the environmental conditions to which the 

components could be subjected. 10 CFR 50.49(e)(5) contains provisions for aging that require, 

in part, consideration of all significant types of aging degradation that can affect component 

functional capability. 10 CFR 50.49(e) also requires replacement or refurbishment of 

components not qualified for the current license term prior to the end of designated life, unless 

additional life is established through ongoing qualification. 10 CFR 50.49(f) establishes four 

methods of demonstrating qualification for aging and accident conditions. 10 CFR 50.49(k) and 

(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 DOR Guidelines, Guidelines for Evaluating Environmental Qualification of Class 

1 E Electrical Equipment in Operating Reactors; NUREG-0588, Interim Staff Position on 

Environmental Qualification of Safety-Related Electrical Equipment; and Regulatory Guide 1.89, 

Rev. 1, Environmental Qualification of Certain Electric Equipment Important to Safety for 

Nuclear Power Plants. Compliance with 10 CFR 50.49 provides reasonable assurance that the 

component can perform its intended functions during accident conditions after experiencing the 

effects of inservice aging. 

EQ programs manage component thermal, radiation, and cyclical aging through the use of 

aging evaluations based on 10 CFR 50.49(f) qualification methods. As required by 

10 CFR 50.49, EQ components not qualified for the current license term are to be refurbished, 

replaced, or have their qualification extended prior to reaching the aging limits established in the 

evaluation. Aging evaluations for EQ components that specify a qualification of at least 40 years 

are considered time-limited aging analyses (TLAAs) for license renewal. 

Under 10 CFR 54.21 (c)(1)(iii), plant EQ programs, which implement the requirements of 

10 CFR 50.49 (as further defined and clarified by the DOR Guidelines, NUREG-0588, and 

Regulatory Guide 1.89, Rev. 1), are viewed as aging management programs (AMPs) for license 

renewal. Reanalysis of an aging evaluation to extend the qualification of components under 

10 CFR 50.49(e) is performed on a routine basis as part of an EQ program. Important attributes 

for the reanalysis of an aging evaluation include analytical methods, data collection and 

reduction methods, underlying assumptions, acceptance criteria, and corrective actions (if

April 2001 X E-1 NUREG-1801
acceptance criteria are not met). These attributes are discussed in the "EQ Component 

Reanalysis Attributes" section. 

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. 

However, Generic Safety Issue (GSI) 168, which is related to low-voltage EQ instrumentation 

and control cables, is currently an open generic issue. NRC research is ongoing to provide 

information to resolve it. An applicant is to address GSI-1 68 in its application for staff review. 

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-by

case basis. 

Data Collection and Reduction Methods: Reducing excess conservatism in the component 

service conditions (for example, temperature, radiation, cycles) used in the prior aging 

evaluation is the chief method used for a reanalysis. Temperature data used in an aging 

evaluation is to be conservative and based on plant design temperatures or on actual plant 

temperature data. When used, plant temperature data can be obtained in several ways, 

including monitors used for technical specification compliance, other installed monitors, 

measurements made by plant operators during rounds, and temperature sensors on large 

motors (while the motor is not running). A representative number of temperature measurements 

are conservatively evaluated to establish the temperatures used in an aging evaluation. Plant 

temperature data may be used in an aging evaluation in different ways, such as (a) directly applying the plant temperature data in the evaluation, or (b) using the plant temperature data to 

NUREG-1801 X E-2 April 2001

I I
demonstrate conservatism when using plant design temperatures for an evaluation. Any 

changes to material activation energy values as part of a reanalysis are to be justified on a 

plant-specific basis. Similar methods of reducing excess conservatism in the component service 

conditions used in prior aging evaluations can be used for radiation and cyclical aging. 

Underlying Assumptions: EQ component aging evaluations contain sufficient conservatism to 

account for most environmental changes occurring due to plant modifications and events. When 

unexpected adverse conditions are identified during operational or maintenance activities that 

affect the normal operating environment of a qualified component, the affected EQ component 

is evaluated and appropriate corrective actions are taken, which may include changes to the 

qualification bases and conclusions. 

Acceptance Criteria and Corrective Actions: The reanalysis of an aging evaluation could extend 

the qualification of the component. If the qualification cannot be extended by reanalysis, the 

component is to be refurbished, replaced, or requalified prior to exceeding the period for which 

the current qualification remains valid. A reanalysis is to be performed in a timely manner (that 

is, sufficient time is available to refurbish, replace, or requalify the component if the reanalysis is 

unsuccessful). 

Evaluation and Technical Basis 

1. Scope of Program: EQ programs apply to certain electrical components that are important 

to safety and could be exposed to harsh environment accident conditions, as defined in 

10 CFR 50.49. 

2. Preventive Actions: 10 CFR 50.49 does not require actions that prevent aging effects. EQ 

program actions that could be viewed as preventive actions include (a) establishing the 

component service condition tolerance and aging limits (for example, qualified life or 

condition limit), and (b) where applicable, requiring specific installation, inspection, monitoring or periodic maintenance actions to maintain component aging effects within the 

bounds of the qualification basis. 

3. Parameters Monitored/Inspected: EQ component qualified life is not based on condition 

or performance monitoring. However, pursuant to Regulatory Guide 1.89, Rev. 1, such 

monitoring programs are an acceptable basis to modify a qualified life through reanalysis. 

Monitoring or inspection of certain environmental conditions or component parameters may 

be used to ensure that the component is within the bounds of its qualification basis, or as a 

means to modify the qualified life. 

4. Detection of Aging Effects: 10 CFR 50.49 does not require the detection of aging effects 

for in-service components. Monitoring or inspection of certain environmental conditions or 

component parameters may be used to ensure that the component is within the bounds of 

its qualification basis, or as a means to modify the qualified life. 

5. Monitoring and Trending: 10 CFR 50.49 does not require monitoring and trending of 

component condition or performance parameters of in-service components to manage the 

effects of aging. EQ program actions that could be viewed as monitoring include monitoring 

how long qualified components have been installed. Monitoring or inspection of certain 

environmental, condition, or component parameters may be used to ensure that a 

component is within the bounds of its qualification basis, or as a means to modify the 

qualification.

April 2001 X E-3 NUREG-1 801
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 to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address corrective actions. 

8. Confirmation Process: Confirmatory actions, as needed, are implemented as part of the 

station's corrective action program, pursuant to 10 CFR 50, Appendix B. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address the confirmation process. 

9. Administrative Controls: EQ programs are implemented through the use of station policy, directives, and procedures. EQ programs will continue to comply with 10 CFR 50.49 

throughout the renewal period, including development and maintenance of qualification documentation demonstrating reasonable assurance that a component can perform required functions during harsh accident conditions. EQ program documents identify the applicable environmental conditions for the component locations. EQ program qualification files are 

maintained at the plant site in an auditable form for the duration of the installed life of the 

component. EQ program documentation is controlled under the station's quality assurance 

program. As discussed in the appendix to this report, the staff finds the requirements of 

10 CFR Part 50, Appendix B, acceptable to address administrative controls. 

10. Operating Experience: EQ programs include consideration of operating experience to 

modify qualification bases and conclusions, including qualified life. Compliance with 

10 CFR 50.49 provides reasonable assurance that components can perform their intended 

functions during accident conditions after experiencing the effects of inservice aging. 

References 

10 CFR 50.49, Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants, Office of the Federal Register, National Archives and Records 

Administration, 2000. 

DOR Guidelines, Guidelines for Evaluating Environmental Qualification of Class 1E Electrical 

Equipment in Operating Reactors, November 1979. 

NUREG-1801 X E-4 April 2001

I I
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. 

NUREG-0588, Interim Staff Position on Environmental Qualification of Safety-Related Electrical 

Equipment, U. S. Nuclear Regulatory Commission, July 1981.

April 2001 X E-5 NUREG-1801
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NUREG-1 801 X E-6 April 2001

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CHAPTER XI 

AGING MANAGEMENT PROGRAMS 

(AMPs)

April 2001 XI -i NUREG-1801
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<---

NUREG-1 801 XI -ii April 2001
AGING MANAGEMENT PROGRAMS (AMPs) 

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

XI.M2 Water Chemistry 

XI.M3 Reactor Head Closure Studs 

XI.M4 BWR Vessel ID Attachment Welds 

XI.M5 BWR Feedwater Nozzle 

XI.M6 BWR Control Rod Drive Return Line Nozzle 

XI.M7 BWR Stress Corrosion Cracking 

XI.M8 BWR Penetrations 

XI.M9 BWR Vessel Internals 

XI.M1 0 Boric Acid Corrosion 

XI.M1 1 Nickel-Alloy Nozzles and Penetrations 

XI.M12 Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) 

XI.M13 Thermal Aging and Neutron Irradiation Embrittlement 

of Cast Austenitic Stainless Steel (CASS) 

XI.M14 Loose Part Monitoring 

XI.M15 Neutron Noise Monitoring 

XI.M16 PWR Vessel Internals 

XI.M17 Flow-Accelerated Corrosion 

XI.M18 Bolting Integrity 

XI.M19 Steam Generator Tube Integrity 

XI.M20 Open-Cycle Cooling Water System 

XI.M21 Closed-Cycle Cooling Water System 

XI.M22 Boraflex Monitoring 

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

Handling Systems 

XI.M24 Compressed Air Monitoring 

XI.M25 BWR Reactor Water Cleanup System 

XI.M26 Fire Protection 

XI.M27 Fire Water System 

XI.M28 Buried Piping and Tanks Surveillance 

XI.M29 Aboveground Carbon Steel Tanks 

XI.M30 Fuel Oil Chemistry 

XI.M31 Reactor Vessel Surveillance 

XI.M32 One-Time Inspection 

XI.M33 Selective Leaching of Materials 

XI.M34 Buried Piping and Tanks Inspection 

XI.S1 ASME Section XI, Subsection IWE 

XI.S2 ASME Section XI, Subsection IWL 

XI.S3 ASME Section XI, Subsection IWF 

XI.S4 10 CFR Part 50, Appendix J 

XI.S5 Masonry Wall Program 

XI.S6 Structures Monitoring Program 

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

Plants 

XI.S8 Protective Coating Monitoring and Maintenance Program 

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

Qualification Requirements 

XI.E2 Electrical Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Used in Instrumentation Circuits

April 2001 XI -iii NUREG-1801
XI.E3 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements

NUREG-1801 Xl -iv April 2001

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XI.M1 ASME SECTION XI INSERVICE INSPECTION, SUBSECTIONS IWB, IWC, AND IWD 

Program Description 

The Code of Federal Regulations, 10 CFR 50.55a, imposes the inservice inspection (ISI) 

requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure 

Vessel (B&PV) Code, Section XI, for Class 1, 2, and 3 pressure-retaining components and their 

integral attachments in light-water cooled power plants. Inspection, repair, and replacement of 

these components are covered in Subsections IWB, IWC, and IWD, respectively, in the 1995 

edition through the 1996 addenda. The program generally includes periodic visual, surface, 

and/or volumetric examination and leakage test of all Class 1, 2, and 3 pressure-retaining 

components and their integral attachments. 

The ASME Section Xl inservice inspection program in accordance with Subsections IWB, IWC, 

or IWD has been shown to be generally effective in managing aging effects in Class 1, 2, or 3 

components and their integral attachments in light-water cooled power plants. However, in 

certain cases, the ASME inservice inspection program is to be augmented to manage effects of 

aging for license renewal and is so identified in the GALL report. 

Evaluation and Technical Basis 

1. Scope of Program: The ASME Section Xl program provides the requirements for ISI, 

repair, and replacement. The components within the scope of the program are specified in 

Subsections IWB-1 100, IWC-1 100, and IWD-1 100 for Class 1, 2, and 3 components, respectively, and include all pressure-retaining components and their integral attachments 

in light-water cooled power plants. The components described in Subsections IWB-1220, 

IWC-1220, and IWD-1 220 are exempt from the examination requirements of Subsections 

IWB-2500, IWC-2500, and IWD-2500. 

2. Preventive Actions: The ASME Section XI does not provide guidance on methods to 

mitigate degradation. 

3. Parameters Monitored/Inspected: The ASME Section XI ISI program detects degradation 

of components by using the examination and inspection requirements specified in ASME 

Section XI Tables IWB-2500-1, IWC-2500-1, or IWD-2500-1, respectively, for Class 1, 2, or 

3 components. 

4. Detection of Aging Effects: The extent and schedule of the inspection and test techniques 

prescribed by the program are designed to maintain structural integrity and ensure that 

aging effects will be discovered and repaired before the loss of intended function of the 

component. Inspection can reveal crack initiation and growth; loss of material due to 

corrosion; leakage of coolant; and indications of degradation due to wear or stress 

relaxation, such as verification of clearances, settings, physical displacements, loose or 

missing parts, debris, wear, erosion, or loss of integrity at bolted or welded connections. 

Components are examined and tested as specified in Tables IWB-2500-1, IWC-2500-1, and 

IWD-2500-1, respectively, for Class 1, 2, and 3 components. The tables specify the 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.

April 2001 Xl M-1 NUREG-1801
The program uses three types of examination - visual, surface, and volumetric - in 

accordance with the general requirements of Subsection IWA-2000. Visual VT-1 

examination detects discontinuities and imperfections, such as cracks, corrosion, wear, or 

erosion, on the surface of components. Visual VT-2 examination detects evidence of 

leakage from pressure-retaining components, as required during the system pressure test. 

Visual VT-3 examination (a) determines the general mechanical and structural condition of 

components and their supports by verifying parameters, such as clearances, settings, and 

physical displacements; (b) detects discontinuities and imperfections, such as loss of 

integrity at bolted or welded connections, loose or missing parts, debris, corrosion, wear, or 

erosion; and (c) observes conditions that could affect operability or functional adequacy of 

constant-load and spring-type components and supports. 

Surface examination uses magnetic particle, liquid penetrant, or eddy current examinations 

to indicate the presence of surface discontinuities and flaws. 

Volumetric examination uses radiographic, ultrasonic, or eddy current examinations to 

indicate the presence of discontinuities or flaws throughout the volume of material included 

in the inspection program. 

For BWRs, the nondestructive examination (NDE) techniques appropriate for inspection of 

vessel internals and their implementation needs, including the uncertainties inherent in 

delivering and executing and NDE technique in a boiling water reactor (BWR), are included 

in the approved boiling water reactor vessel and intemals project (BWRVIP)-03. Also, an 

applicant may use the guidelines of the approved BWRVIP-62 for inspection relief for vessel 

internal components with hydrogen water chemistry. 

The ASME Section XI examination categories used in this report are given below. These 

examination categories are based on the 1989 edition of Section Xl of the ASME Code; any differences in the examination categories in the 1995 edition through the 1996 addenda 

from those in the 1989 edition are identified. 

Class 1 Components, Table IWB-2500-1 

Examination category B-B for pressure-retaining welds in vessels other than reactor 

vessels: This category specifies volumetric examination of circumferential and longitudinal shell-to-head welds and circumferential and meridional head welds in pressurizers, and 

circumferential and meridional head welds and tubesheet-to-head welds in steam 

generators (primary side). The welds selected during the first inspection interval are 

reexamined during successive inspection intervals. 

Examination category B-D, for full penetration welds of nozzles in reactor vessels, 

pressurizers, steam generators (primary side), and heat exchangers (primary side): This 

category specifies volumetric examination of all nozzle-to-vessel welds and the nozzle 

inside radius. 

Examination category B-E, for pressure-retaining partial penetration welds in vessels. This 

category specifies visual VT-2 examination of partial penetration welds in nozzles and 

penetrations in reactor vessels and pressurizers during the hydrostatic test. In the 1995 

edition of the ASME Code, examination category B-E is covered under examination 

category B-P. 

NUREG-1 801 XI M-2 April 2001

I I
Examination category B-F, for pressure-retaining dissimilar metal welds in reactor vessels, 

pressurizers, steam generators, heat exchangers, and piping: This category specifies volumetric examination of the inside diameter (ID) region and surface examination of the 

outside diameter (OD) surface for all nozzle-to-safe end butt welds of nominal pipe size 

(NPS) 4 in. or larger. Only surface examination is conducted for all butt welds less than NPS 

4 in. and for all nozzle-to-safe end socket welds. Examinations are required for each safe 

end weld in each loop and connecting branch of the reactor coolant system. In the 1995 

edition of the ASME Code, examination category B-F for piping is covered under 

examination category B-J for all pressure-retaining welds in piping. 

Examination category B-G- 1 for pressure-retaining bolting greater than 2 in. in diameter, 

and category B-G-2 for pressure-retaining bolting less than 2 in. in diameter in reactor 

vessels, pressurizers, steam generators, heat exchangers, piping, pumps, and valves: 

Category B-G-1 specifies volumetric examination of studs in place, from the top of the nut to 

the bottom of the flange hole; and surface and volumetric examination of studs when 

removed; volumetric examination of flange threads; and visual VT-1 examination of the 

surfaces of nuts, washers, and bushings. Category B-G-2 specifies visual VT-1 examination 

of the surfaces of nuts, washers, and bushings. For heat exchangers, piping, pumps, and 

valves, examinations are limited to components selected for examination under examination 

categories B-B, B-J, B-L-2, and B-M-2. 

Examination category B-H for integral attachments for vessels:. This category specifies volumetric or surface examination of essentially 100% of the length of the attachment weld 

at each attachment subject to examination. 

Examination category B-J for pressure-retaining welds in piping. This category specifies volumetric examination of the ID region and surface examination of the OD for 

circumferential and longitudinal welds in each pipe or branch run NPS 4 in. or larger. Surface examination is conducted for circumferential and longitudinal welds in each pipe or 

branch run less than NPS 4 in. and for all socket welds. The pipe welds selected during the 

first inspection interval are reexamined during each successive inspection interval. 

Examination category B-L-1, for pressure-retaining welds in pump casing, and 

category B-L-2, for pump casing:. Category B-L-1 specifies volumetric examination of all 

welds, and category B-L-2 specifies visual VT-3 examination of internal surfaces of the 

pump casing. All welds from at least one pump in each group of pumps performing similar 

functions in the system (such as recirculating coolant pumps) are inspected during each 

inspection interval. Visual examination is required only when the pump is disassembled for 

maintenance, repair, or volumetric examination, but one pump in a particular group of 

pumps is visually examined at least once during the inspection interval. 

Examination category B-M- 1, for pressure-retaining welds in valve bodies and 

category B-M-2, for valve bodies: Category B-M-1 specifies volumetric examination for all 

welds in valve bodies NPS 4 in. or larger, and surface examination of OD surfaces for all 

welds in valve bodies less than NPS 4 in. Category B-M-2 specifies visual VT-3 examination 

of internal surfaces of valve bodies. All welds from at least one valve in each group of 

valves that are of the same size, construction design (such as globe, gate, or check valves), and manufacturing method, and that perform similar functions in the system (such as the 

containment isolation valve) are inspected during each inspection interval. Visual 

examination is required only when the valve is disassembled for maintenance, repair, or 

volumetric examination, but one valve in a particular group of valves is visually examined at 

least once during the inspection interval.

April 2001 XI M-3 NUREG-1801
Examination category B-N-1, for the interior of reactor vessels: Category B-N-1 specifies 

visual VT-3 examination of interior surfaces that are made accessible for examination by 

removal of components during normal refueling outages. Examination category B-N-2, for 

integrally welded core support structures and interior attachments to reactor vessels: 

Category B-N-2 specifies visual VT-1 examination of all accessible welds in interior 

attachments within the beltline region; visual VT-3 examination of all accessible welds in 

interior attachments beyond the beltline region; and, for BWRs, visual VT-3 examination of 

all accessible surfaces in the core support structure. Examination category B-N-3, which is 

applicable to pressurized water reactors (PWRs), for removable core support structures: 

Category B-N-3 specifies visual VT-3 examination of all accessible surfaces of reactor core 

support structures that can be removed from the reactor vessel. 

Examination category B-0, for pressure-retaining welds in control rod housing. This 

category specifies volumetric or surface examination of the control rod drive (CRD) housing 

welds, including the weld buttering. 

Examination category B-P, for all pressure-retaining components- This category specifies 

visual VT-2 examination of all pressure-retaining boundary components during the system 

leakage test and hydrostatic test (IWA-5000 and IWB-5000). The pressure-retaining 

boundary during the system leakage test corresponds to the reactor coolant system 

boundary, with all valves in the normal position, which is required for normal reactor 

operation startup. However, VT-2 visual examination extends to and includes the second 

closed valve at the boundary extremity. The 1995 edition of the ASME Code eliminates the 

hydrostatic test because equivalent results are obtained from the leakage test. The 

pressure-retaining boundary for the hydrostatic test (1989 edition) and system leakage test 

(1995 edition) conducted at or near the end of each inspection interval extends to all 

Class 1 pressure-retaining components within the system boundary. 

Class 2 Components, Table IWC-2500-1 

Examination category C-A, for pressure-retaining welds in pressure vessels- This category 

specifies volumetric examination of circumferential welds at gross structural discontinuities, 

such as junctions between shells of different thickness or cylindrical shell-to-conical shell 

junctions, and head-to-shell, shell (or head)-to-flange, and tubesheet-to-shell welds. 

Examination category C-F- 1, for pressure-retaining welds in austenitic stainless steel or 

high-alloy piping. This category specifies, for circumferential and longitudinal welds in each 

pipe or branch run NPS 4 in. or larger, volumetric and surface examination of the ID region, 

and surface examination of the OD surface for piping welds Ž_3/8 in. nominal wall thickness 

for piping >NPS 4 in. or for piping welds >1/5 in. nominal wall thickness for piping >_NPS 

2 in. and --NPS 4 in. Surface examination is conducted for circumferential and longitudinal 

welds in pipe branch connections of branch piping Ž_NPS 2 in. and for socket welds. 

Examination category C-G, for all pressure-retaining welds in pumps and valves: This 

category specifies surface examination of either the inside or outside surface of all welds in 

the pump casing and valve body. In a group of multiple pumps or valves of similar design, 

size, function, and service in a system, examination of only one pump or one valve among 

each group of multiple pumps or valves is required to detect the loss of intended function of 

the pump or valve. 

Examination category C-H, for all pressure-retaining components: This category specifies 

visual VT-2 examination during system pressure tests (IWA-5000 and IWC-5000) of all 

NUREG-1 801 XI M-4 April 2001

I I
pressure-retaining boundary components. The pressure-retaining boundary includes only 

those portions of the system required to operate or support the safety function, up to and 

including the first normally closed valve (including a safety or relief valve) or valve capable 

of automatic closure when the safety function is required. The 1995 edition of the ASME 

Code eliminates the hydrostatic test because equivalent results are obtained from the 

leakage test. 

Class 3 Components, Table IWD-2500-1 

Examination category D-A (1989 edition), for systems in support of reactor shutdown 

function, and category D-B (1989 edition), for systems in support of emergency core 

cooling, containment heat removal, atmosphere cleanup, and reactor residual heat removat 

Categories D-A and D-B specify visual VT-2 examination during system pressure tests 

(IWA-5000 and IWD-5000) of all pressure-retaining boundary components. The pressure

retaining boundary extends up to and includes the first normally closed valve or valve 

capable of automatic closure as required to perform the safety-related system function. 

Examination categories D-A and D-B, from the 1989 edition of the ASME Code, have been 

combined into examination category D-B for all pressure-retaining components in the 1995 

edition of the ASME Code. 

5. Monitoring and Trending: For Class 1, 2, or 3 components, the inspection schedule of 

IWB-2400, IWC-2400, or IWD-2400, respectively, and the extent and frequency of IWB

2500-1, 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 indications or relevant conditions of degradation are evaluated in 

accordance with IWB-31 00 or IWC-31 00, 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-241 0 for Class 1 components 

and for the next inspection period of IWC-2410 for Class 2 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 

(1995 edition) for Class 1, 2, or, 3 components, respectively. 

6. Acceptance Criteria: Any indication or relevant conditions of degradation detected are 

evaluated in accordance with IWB-3000, IWC-3000, or IWD-3000, for Class 1, 2, or 3 

components, respectively. Examination results are evaluated in accordance with IWB-31 00 

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 2 and 3 components. Approved BWRVIP-14, BWRVIP-59, 

and BWRVIP-60 documents provide guidelines for evaluation of crack growth in stainless 

steels, nickel alloys, and low-alloy steels, respectively. 

7. Corrective Actions: For Class 1, 2, and 3, respectively, repair is in conformance with IWB

4000, IWC-4000, and IWD-4000, and replacement according to IWB-7000, IWC-7000, and 

IWD-7000. Approved BWRVIP-44 and BWRVIP-45 documents, respectively, provide 

guidelines for weld repair of nickel alloys and for weldability of irradiated structural 

components. As discussed in the appendix to this report, the staff finds the requirements of 

10 CFR Part 50, Appendix B, acceptable in addressing corrective actions.

April 2001 XI M-5 NUREG-1801
8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing 

the confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: Because the ASME Code is a consensus document that has been 

widely used over a long period, it has been shown to be generally effective in managing 

aging effects in Class 1, 2, and 3 components and their integral attachments in light-water 

cooled power plants (see Chapter I of the GALL report, Vol. 2). 

Some specific examples of operating experience of component degradation are as follows: 

BWR: Cracking due to intergranular stress corrosion cracking (IGSCC) has occurred in 

small- and large-diameter BWR piping made of austenitic stainless steels and nickel alloys. 

The IGSCC has also occurred in a number of vessel internal components, such as core 

shrouds, access hole covers, top guides, and core spray spargers (NRC IE Bulletin 80-13, 

NRC Information Notice [IN] 95-17, NRC General Letter [GL] 94-03, and NUREG-1544). 

Crack initiation and growth due to thermal and mechanical loading have occurred in high

pressure coolant injection (HPCI) piping (NRC IN 89-80) and instrument lines NRC 

Licensee Event Report [LER] 50-249/99-003-1). Jet pump BWRs are designed with access 

holes in the shroud support plate at the bottom of the annulus between the core shroud and 

the reactor vessel wall. These holes are used for access during construction and are 

subsequently closed by welding a plate over the hole. Both circumferential (NRC IN 88-03) 

and radial cracking (NRC IN 92-57) have been observed in access hole covers. Failure of 

the isolation condenser tube bundles due to thermal fatigue and transgranular stress 

corrosion cracking (TGSCC) due to leaky valves has also occurred (NRC LER 50-219/98

014). 

PWR Primary System: Although the primary pressure boundary piping of PWRs has 

generally not been found to be affected by SCC because of low dissolved oxygen levels and 

control of primary water chemistry, SCC has occurred in safety injection lines (NRC IN 

97-19 and 84-18), charging pump casing cladding (NRC IN 80-38 and 94-63), instrument 

nozzles in safety injection tanks (NRC IN 91-05), CRD seal housing (NRC Inspection 

Report 50-255/99012), and safety-related stainless steel (SS) piping systems that contain 

oxygenated, stagnant, or essentially stagnant borated coolant (NRC IN 97-19). Cracking 

has occurred in SS baffle former bolts in a number of foreign plants (NRC IN 98-11) and 

has now been observed in plants in the United States. Crack initiation and growth due to 

thermal and mechanical loading has occurred in high-pressure injection and safety injection 

piping (NRC IN 97-46 and NRC BL 88-08). 

PWR Secondary System: Steam generator tubes have experienced outside diameter stress 

corrosion cracking (ODSCC), intergranular attack (IGA), wastage, and pitting (NRC 

IN 97-88). Carbon steel support plates in steam generators have experienced general 

corrosion. Steam generator shells have experienced pitting and stress corrosion cracking 

(NRC INs 82-37, 85-65, and 90-04). 

NUREG-1801 XI M-6 April 2001

I I
References

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2000. 

ASME Section Xl, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 1989 edition, 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, 1995 edition through the 1996 Addenda, American 

Society of Mechanical Engineers, New York, NY. 

BWRVIP-03, BWR Vessel and Internals Project, Reactor Pressure Vessel and Internals 

Examination Guidelines, (EPRI TR-105696 R1, March 30, 1999), Final Safety Evaluation 

Report by the Office of Nuclear Reactor Regulation for BWRVIP-03, July 15, 1999. 

BWRVIP-1 4, Evaluation of Crack Growth in BWR Stainless Steel RPV Internals, 

(EPRI TR-105873, July 11, 2000), Final Safety Evaluation Report by the Office of Nuclear 

Reactor Regulation for BWRVIP-14, December 3, 1999. 

BWRVIP-44, Underwater Weld Repair of Nickel Alloy Reactor Vessel Internals, 

(EPRI TR-108708, April 3,2000), Final Safety Evaluation Report by the Office of Nuclear 

Reactor Regulation for BWRVIP-44, June 9, 1999. 

BWRVIP-45, Weldability of Irradiated L WR Structural Components, (EPRI TR-108707), 

BWRVIP and Electric Power Research Institute, Palo Alto, CA, June 14, 2000. 

BWRVIP-59, Evaluation of Crack Growth in BWR Nickel-Base Austenitic Alloys in RPV 

Internals, (EPRI TR-108710), BWRVIP and Electric Power Research Institute, Palo Alto, 

CA, March 24, 2000. 

BWRVIP-60, BWR Vessel and Internals Project, Evaluation of Crack Growth in BWR Low Alloy 

Steel RPV Internals, (EPRI TR-108709, April 14, 2000), Final Safety Evaluation Report by 

the Office of Nuclear Reactor Regulation for BWRVIP-60, July 8, 1999. 

BWRVIP-62, BWR Vessel and Internals Project, Technical Basis for Inspection Relief for BWR 

Internal Components with Hydrogen Injection, (EPRI TR-108705), BWRVIP and Electric 

Power Research Institute, Palo Alto, CA, March 7, 2000. 

NRC Bulletin 88-08, Thermal Stresses in Piping Connected to Reactor Coolant System, U.S. 

Nuclear Regulatory Commission, June 22, 1988; Supplement 1, June 24, 1988; Supplement 

2, September 4, 1988; Supplement 3, April 4, 1989. 

NRC Generic Letter 94-03, Intergranular Stress Corrosion Cracking of Core Shrouds in Boiling 

Water Reactors, U.S. Nuclear Regulatory Commission, July 25, 1994. 

NRC IE 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.

April 2001 Xl M-7 NUREG-1 801
NRC Information Notice 82-37, Cracking in the Upper Shell to Transition Cone Girth Weld of a 

Steam Generator at an Operating PWR, U.S. Nuclear Regulatory Commission, 

September 16, 1982. 

NRC Information Notice 84-18, Stress Corrosion Cracking in PWR Systems, U.S. Nuclear 

Regulatory Commission, March 7, 1984. 

NRC Information Notice 85-65, Crack Growth in Steam Generator Girth Welds, U.S. Nuclear 

Regulatory Commission, July 31, 1985. 

NRC Information Notice 88-03, Cracks in Shroud Support Access Hole Cover Welds, 

U.S. Nuclear Regulatory Commission, February 2, 1988. 

NRC Information Notice 89-80, Potential for Water Hammer, Thermal Stratification, and Steam 

Binding in High-Pressure Coolant Injection Piping, U.S. Nuclear Regulatory Commission, 

December 1, 1989. 

NRC Information Notice 90-04, Cracking of the Upper Shell-to-Transition Cone Girth Welds in 

Steam Generators, U.S. Nuclear Regulatory Commission, January 26, 1990. 

NRC Information Notice 91-05, Intergranular Stress Corrosion Cracking in Pressurized Water 

Reactor Safety Injection Accumulator Nozzles, U.S. Nuclear Regulatory Commission, 

January 30, 1991. 

NRC Information Notice 92-57, Radial Cracking of Shroud Support Access Hole Cover Welds, 

U.S. Nuclear Regulatory Commission, August 11, 1992. 

NRC Information Notice 94-63, Boric Acid Corrosion of Charging Pump Casing Caused by 

Cladding Cracks, U.S. Nuclear Regulatory Commission, August 30, 1994. 

NRC Information Notice 95-17, Reactor Vessel Top Guide and Core Plate Cracking, 

U.S. Nuclear Regulatory Commission, March 10, 1995. 

NRC Information Notice 97-19, Safety Injection System Weld Flaw at Sequoyah Nuclear Power 

Plant, Unit 2, U.S. Nuclear Regulatory Commission, April 18, 1997. 

NRC Information Notice 97-46, Unisolable Crack in High-Pressure Injection Piping, 

U.S. Nuclear 

Regulatory Commission, July 9, 1997. 

NRC Information Notice 97-88, Experiences During Recent Steam Generator Inspections, 

U.S. Nuclear Regulatory Commission, December 16, 1997. 

NRC Information Notice 98-11, Cracking of Reactor Vessel Internal Baffle Former Bolts in 

Foreign Plants, U.S. Nuclear Regulatory Commission, March 25, 1998. 

NRC Inspection Report 50-255/99012, Palisades Inspection Report, Item E8.2, Licensee Event 

Report 50-255/99-004, Control Rod Drive Seal Housing Leaks and Crack Indications, 

U.S. Nuclear Regulatory Commission, January 12, 2000. 

NUREG-1801 XI M-8 April 2001
NRC Licensee Event Report LER # 98-014-00, Failure of the Isolation Condenser Tube 

Bundles due to Thermal StressesfTransgranular Stress Corrosion Cracking Caused by 

Leaky Valve, U.S. Nuclear Regulatory Commission, October 29, 1998. 

NRC Licensee Event Report LER # 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.

April 2001 Xl M-9 NUREG-1801
XI.M2 WATER CHEMISTRY

Program Description 

The main objective of this program is to mitigate damage caused by corrosion and stress 

corrosion cracking (SCC). The water chemistry program for boiling water reactors (BWRs) 

relies on monitoring and control of reactor water chemistry based on guidelines in the boiling 

water reactor vessel and internals project (BWRVIP)-29 (Electric Power Research Institute 

[EPRI] TR-103515). The BWRVIP-29 has three sets of guidelines: one for primary water, one 

for condensate and feedwater, and one for control rod drive (CRD) mechanism cooling water. 

The water chemistry program for pressurized water reactors (PWRs) relies on monitoring and 

control of reactor water chemistry based on the EPRI guidelines in TR-1 05714 for primary water 

chemistry and TR-1 02134 for secondary water chemistry. 

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 intended function will be maintained 

during the extended period of operation. As discussed in the GALL report for these specific 

cases, an acceptable verification program is a one-time inspection of selected components at 

susceptible locations in the system. 

Evaluation and Technical Basis 

1. Scope of Program: The program includes periodic monitoring and control of known 

detrimental contaminants such as chlorides, fluorides (PWRs only), dissolved oxygen, and 

sulfate concentrations below the levels known to result in loss of material or crack initiation 

and growth. Water chemistry control is in accordance with the guidelines in BWRVIP-29 

(EPRI TR-1 03515) for water chemistry in BWRs; EPRI TR-1 05714, Rev. 3, for primary 

water chemistry in PWRs; EPRI TR-1 02134, Rev. 3, for secondary water chemistry in 

PWRs; or later revisions or updates of these reports as approved by the staff. 

2. Preventive Actions: The program includes specifications for chemical species, sampling 

and analysis frequencies, and corrective actions for control of reactor water chemistry. 

System water chemistry is controlled to minimize contaminant concentration and mitigate 

loss of material due to general, crevice and pitting corrosion and crack initiation and growth 

caused by SCC. For BWRs, maintaining high water purity reduces susceptibility to SCC. 

3. Parameters Monitored/Inspected: The concentration of corrosive impurities listed in the 

EPRI guidelines discussed above, which include chlorides, fluorides (PWRs only), sulfates, 

dissolved oxygen, and hydrogen peroxide, are monitored to mitigate degradation of 

structural materials. Water quality (pH and conductivity) is also maintained in accordance 

with the guidance. Chemical species and water quality are monitored by in process methods 

or through sampling. The chemistry integrity of the samples is maintained and verified to 

ensure that the method of sampling and storage will not cause a change in the 

concentration of the chemical species in the samples. 

BWR Water Chemistry: The guidelines in BWRVIP-29 (EPRI TR-1 03515) for BWR reactor 

water recommend that the concentration of chlorides, sulfates, and dissolved oxygen are 

NUREG-1 801 Xl M-10 April 2001
monitored and kept below the recommended levels to mitigate corrosion. The two 

impurities, chlorides and sulfates, determine the coolant conductivity; dissolved oxygen, 

hydrogen peroxide, and hydrogen determine electrochemical potential (ECP). The EPRI 

guidelines recommend that the coolant conductivity and ECP are also monitored and kept 

below the recommended levels to mitigate SCC and corrosion in BWR plants. The EPRI 

guidelines in BWRVIP-29 (TR-103515) for BWR feedwater, condensate, and control rod 

drive water recommends that conductivity, dissolved oxygen level, and concentrations of 

iron and copper (feedwater only) are monitored and kept below the recommended levels to 

mitigate SCC. The EPRI guidelines in BWRVIP-29 (TR-103515) also include 

recommendations for controlling water chemistry in auxiliary systems: torus/pressure 

suppression chamber, condensate storage tank, and spent fuel pool. 

PWR Primary Water Chemistry: The EPRI guidelines (EPRI TR-105714) for PWR primary 

water chemistry recommend that the concentration of chlorides, fluorides, sulfates, lithium, 

and dissolved oxygen and hydrogen are monitored and kept below the recommended levels 

to mitigate SCC of austenitic stainless steel, Alloy 600, and Alloy 690 components. 

TR-1 05714 provides guidelines for chemistry control in PWR auxiliary systems such as 

boric acid storage tank, refueling water storage tank, spent fuel pool, letdown purification 

systems, and volume control tank. 

PWR Secondary Water Chemistry: The EPRI guidelines (EPRI TR-1 02134) for PWR 

secondary water chemistry recommend monitoring and control of chemistry parameters 

(e.g., pH level, cation conductivity, sodium, chloride, sulfate, lead, dissolved oxygen, iron, 

copper, and hydrazine) to mitigate steam generator tube degradation caused by denting, 

intergranular attack (IGA), outer diameter stress corrosion cracking (ODSCC), or crevice 

and pitting corrosion. The monitoring and control of these parameters, especially the pH 

level, also mitigates general (carbon steel components), crevice, and pitting corrosion of the 

steam generator shell and the balance of plant materials of construction (e.g., carbon steel, 

stainless steel, and copper). 

4. Detection of Aging Effects: This is a mitigation program and does not provide for 

detection of any aging effects, such as loss of material and crack initiation and growth. 

In certain cases as identified in the GALL report, inspection of select components is to be 

undertaken to verify the effectiveness of the chemistry control program and to ensure that 

significant degradation is not occurring and the component intended function will be 

maintained during the extended period of operation. 

5. Monitoring and Trending: The frequency of sampling water chemistry varies (e.g., 

continuous, daily, weekly, or as needed) based on plant operating conditions and the EPRI 

water chemistry guidelines. Whenever corrective actions are taken to address an abnormal 

chemistry condition, increased sampling is utilized to verify the effectiveness of these 

actions. 

6. Acceptance Criteria: Maximum levels for various contaminants are maintained below the 

system specific limits as indicated by the limits specified in the corresponding EPRI water 

chemistry guidelines. Any-evidence of the presence of aging effects or unacceptable water 

chemistry results is evaluated, the root cause identified, and the condition corrected. 

7. Corrective Actions: When measured water chemistry parameters are outside the specified 

range, corrective actions are taken to bring the parameter back within the acceptable range 

and within the time period specified in the EPRI water chemistry guidelines. As discussed in

April 2001 XI M-1 1 NUREG-1801
the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable in addressing corrective actions. 

8. Confirmation Process: Following corrective actions, additional samples are taken and 

analyzed to verify that the corrective actions were effective in returning the concentrations 

of contaminants such as chlorides, fluorides, sulfates, dissolved oxygen, and hydrogen 

peroxide to within the acceptable ranges. As discussed in the appendix to this report, the 

staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing the 

confirmation process. 

9. Administrative Controls: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing 

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 large diameter BWR piping made of austenitic stainless steels and nickel-base alloys. Significant 

cracking has occurred in recirculation, core spray, residual heat removal (RHR) systems, 

and reactor water cleanup (RWCU) system piping welds. IGSCC has also occurred in a 

number of vessel internal components, including core shroud, access hole cover, top guide, 

and core spray spargers (Nuclear Regulatory Commission [NRC] Information Bulletin 80-13, 

NRC Information Notice [IN] 95-17, NRC General Letter [GL] 94-03, and NUREG-1544). No 

occurrence of SCC in piping and other components in standby liquid control systems 

exposed to sodium pentaborate solution has ever been reported (NUREG/CR-6001). 

PWR Primary System: The primary pressure boundary piping of PWRs has generally not 

been found to be affected by SCC because of low dissolved oxygen levels and control of 

primary water chemistry. However, the potential for SCC exists due to inadvertent 

introduction of contaminants into the primary coolant system from unacceptable levels of 

contaminants in the boric acid; introduction through the free surface of the spent fuel pool, 

which can be a natural collector of airborne contaminants; or introduction of oxygen during cooldown (NRC IN 84-18). Ingress of demineralizer resins into the primary system has 

caused IGSCC of Alloy 600 vessel head penetrations (NRC IN 96-11, NRC GL 97-01). 

Inadvertent introduction of sodium thiosulfate into the primary system has caused IGSCC of 

steam generator tubes. The SCC has occurred in safety injection lines (NRC INs 97-19 and 

84-18), charging pump casing cladding (NRC INs 80-38 and 94-63), instrument nozzles in 

safety injection tanks (NRC IN 91-05), and safety-related SS piping systems that contain 

oxygenated, stagnant, or essentially stagnant borated coolant (NRC IN 97-19). Steam 

generator tubes and plugs and Alloy 600 penetrations have experienced primary water 

stress corrosion cracking (PWSCC) (NRC INs 89-33, 94-87, 97-88, 90-10, and 96-11; NRC 

Bulletin 89-01 and its two supplements). 

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). 

NUREG-1801 XI M-12 April 2001

I I
Such operating experience has provided feedback to revisions of the EPRI water chemistry 

guideline documents. 

References 

BWRVIP-29 (EPRI TR-1 03515), BWR Water Chemistry Guidelines-1993 Revision, Normal and 

Hydrogen Water Chemistry, Electric Power Research Institute, Palo Alto, CA, February 

1994. 

EPRI TR-1 02134, PWR Secondary Water Chemistry Guideline-Revision 3, Electric Power 

Research Institute, Palo Alto, CA, May 1993. 

EPRI TR-1 05714, PWR Primary Water Chemistry Guidelines-Revision 3, Electric Power 

Research Institute, Palo Alto, CA, Nov. 1995. 

NRC IE Bulletin 80-13, Cracking in Core Spray Piping, U.S. Nuclear Regulatory Commission, 

May 12, 1980. 

NRC IE Bulletin 89-01, Failure of Westinghouse Steam Generator Tube Mechanical Plugs, 

U.S. Nuclear Regulatory Commission, May 15, 1989. 

NRC IE Bulletin 89-01, Supplement 1, Failure of Westinghouse Steam Generator Tube 

Mechanical Plugs, U.S. Nuclear Regulatory Commission, November 14, 1989. 

NRC IE 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.

April 2001 Xl M-13 NUREG-1801
NRC Information Notice 90-04, Cracking of the Upper Shell-to-Transition Cone Girth Welds in 

Steam Generators, U.S. Nuclear Regulatory Commission, January 26, 1990. 

NRC Information Notice 90-10, Primary Water Stress Corrosion Cracking (PWSCC) of 

Inconel 600, U.S. Nuclear Regulatory Commission, February 23, 1990. 

NRC Information Notice 91-05, Intergranular Stress Corrosion Cracking In Pressurized Water 

Reactor Safety Injection Accumulator Nozzles, U.S. Nuclear Regulatory Commission, 

January 30, 1991. 

NRC Information Notice 94-63, Boric Acid Corrosion of Charging Pump Casing Caused by 

Cladding Cracks, U.S. Nuclear Regulatory Commission, August 30, 1994. 

NRC Information Notice 94-87, Unanticipated Crack in a Particular Heat of Alloy 600 Used for 

Westinghouse Mechanical Plugs for Steam Generator Tubes, U.S. Nuclear Regulatory 

Commission, December 22, 1994. 

NRC Information Notice 95-17, Reactor Vessel Top Guide and Core Plate Cracking, 

U.S. Nuclear Regulatory Commission, March 10, 1995. 

NRC Information Notice 96-11, Ingress of Demineralizer Resins Increase Potential for Stress 

Corrosion Cracking of Control Rod Drive Mechanism Penetrations, U.S. Nuclear Regulatory 

Commission, February 14, 1996. 

NRC Information Notice 97-19, Safety Injection System Weld Flaw at Sequoyah Nuclear Power 

Plant, Unit 2, U.S. Nuclear Regulatory Commission, April 18, 1997. 

NRC Information Notice 97-88, Experiences during Recent Steam Generator Inspections, 

U.S. Nuclear Regulatory Commission, December 16, 1997. 

NUREG-1 544, Status Report. Intergranular Stress Corrosion Cracking of BWR Core Shrouds 

and Other Internal Components, U.S. Nuclear Regulatory Commission, March 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. 

NUREG-1 801 Xl M-14 April 2001

I I
XI.M3 Reactor Head Closure Studs

Program Description 

This program includes (a) inservice inspection (ISI) in conformance with the requirements of the 

American Society of Mechanical Engineers (ASME), Code, Section XI, Subsection IWB (1995 

edition through the 1996 addenda), Table IWB 2500-1, and (b) preventive measures to mitigate 

cracking. 

Evaluation and Technical Basis 

1. Scope of Program: The program includes (a) ISI to detect crack initiation and growth due 

to stress corrosion cracking (SCC) or intergranular stress corrosion cracking (IGSCC); loss 

of material due to wear; and coolant leakage from reactor vessel closure stud bolting for 

both boiling water reactors (BWRs) and pressurized water reactors (PWRs), and 

(b) preventive measures of NRC Regulatory Guide 1.65 to mitigate cracking. The program 

is applicable to closure studs and nuts constructed from materials with a maximum tensile 

strength limited to less than 1,172 MPa (170 ksi) (Nuclear Regulatory Commission [NRC] 

Regulatory Guide [RGJ 1.65). 

2. Preventive Actions: Preventive measures include avoiding the use of metal-plated stud 

bolting to prevent degradation due to corrosion or hydrogen embrittlement and to use 

manganese phosphate or other acceptable surface treatments and stable lubricants 

(RG 1.65). Implementation of these mitigation measures is an effective option for reducing 

SCC or IGSCC and for this program to be effective. 

3. Parameters Monitored/Inspected: The ASME Section Xl ISI program detects and sizes 

cracks, detects loss of material, and detects coolant leakage by following the examination 

and inspection requirements specified in Table IWB-2500-1. 

4. Detection of Aging Effects: The extent and schedule of the inspection and test techniques 

prescribed by the program are designed to maintain structural integrity and ensure that 

aging effects will be discovered and repaired before the loss of intended function of the 

component. Inspection can reveal crack initiation and growth, loss of material due to 

corrosion or wear, and leakage of coolant. 

The program uses visual, surface, and volumetric examinations in accordance with the 

general requirements of Subsection IWA-2000. Surface examination uses magnetic 

particle, liquid penetration, or eddy current examinations to indicate the presence of surface 

discontinuities and flaws. Volumetric examination uses radiographic, ultrasonic, or eddy 

current examinations to indicate the presence of discontinuities or flaws throughout the 

volume of material. Visual VT-2 examination detects evidence of leakage from pressure

retaining components, as required during the system pressure test. 

Components are examined and tested as specified in Table IWB-2500-1. Examination 

category B-G-1, for pressure-retaining bolting greater than 2 in. in diameter in reactor 

vessels specifies volumetric examination of studs in place, from the top of the nut to the 

bottom of the flange hole, and surface and volumetric examination of studs when removed. 

Also specified are volumetric examination of flange threads and visual VT-1 examination of 

surfaces of nuts, washers, and bushings. Examination category B-P for all pressure

retaining components, specifies visual VT-2 examination of all pressure-retaining boundary 

components during the system leakage test and the system hydrostatic test.

April 2001 Xl M-15 NUREG-1 801
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-31 00 by comparing ISI results with the 

acceptance standards of IWB-3400 and IWB-3500. 

7. Corrective Actions: Repair and replacement are in conformance with the requirements of 

IWB-400 and IWB-7000, respectively, and the material and inspection guidance of RG 1.65. 

As discussed in the appendix to this report, the staff finds the requirements of 

10 CFR Part 50, Appendix B, acceptable in addressing corrective actions. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing 

the confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: The SCC has occurred in BWR pressure vessel head studs (Stoller 

1991). The aging management program (AMP) has provisions regarding inspection techniques and evaluation, material specifications, corrosion prevention, and other aspects 

of reactor pressure vessel head stud cracking. Implementation of the program provides reasonable assurance that the effects of cracking due to SCC or IGSCC and loss of 

material due to wear will be adequately managed so that the intended functions of the 

reactor head closure studs and bolts will be maintained consistent with the current licensing 

basis (CLB) for the period of extended operation. 

References 

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2000. 

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 1995 edition through the 1996 addenda, American 

Society of Mechanical Engineers, New York, NY. 

NRC Regulatory Guide 1.65, Material and Inspection for Reactor Vessel Closure Studs, 

U.S. Nuclear Regulatory Commission, October 1973. 

Stoller, S. M., Reactor Head Closure Stud Cracking, Material Toughness Outside FSAR - SCC 

in Thread Roots, Nuclear Power Experience, BWR-2, III, 58, p. 30, 1991. 

NUREG-1801 XI M-16 April 2001
XI.M4 BWR VESSEL ID ATTACHMENT WELDS

Program Description 

The program includes (a) inspection and flaw evaluation in accordance with the guidelines of 

staff-approved boiling water reactor vessel and internals project (BWRVIP)-48 and 

(b) monitoring and control of reactor coolant water chemistry in accordance with the guidelines 

of BWRVIP-29 (Electric Power Research Institute [EPRI] TR-1 03515) to ensure the long-term 

integrity and safe operation of boiling water reactor (BWR) vessel inside diameter (ID) 

attachment welds. 

Evaluation and Technical Basis 

1. Scope of Program: The program is focused on managing the effects of crack initiation and 

growth due to stress corrosion cracking (SCC), including intergranular stress corrosion 

cracking (IGSCC). The program contains preventive measures to mitigate SCC; inservice 

inspection (ISI) to detect cracking and monitor the effects of cracking on the intended 

function of the components; and repair and/or replacement, as needed, to maintain the 

ability to perform the intended function. 

The guidelines of BWRVIP-48 include inspection recommendations and evaluation 

methodologies for the attachment welds between the vessel wall and vessel ID brackets 

that attach safety-related components to the vessel (e.g., jet pump riser braces and 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 guidelines include information on the 

geometry of the vessel ID attachments; evaluate susceptible locations and safety 

consequence of failure; provide recommendations regarding the method, extent, and 

frequency of inspection; and discuss acceptable methods for evaluating the structural 

integrity significance of flaws detected during these examinations. 

2. Preventive Actions: The BWRVIP-48 provides guidance on detection, but does not 

provide guidance on methods to mitigate cracking. Maintaining high water purity reduces 

susceptibility to SCC or IGSCC. Reactor coolant water chemistry is monitored and 

maintained in accordance with the guidelines in BWRVIP-29 (EPRI TR-103515). The 

program description and evaluation and technical basis of monitoring and maintaining 

reactor water chemistry are presented in Section XI.M2, "Water Chemistry." 

3. Parameters Monitored/Inspected: The program monitors the effects of SCC and IGSCC 

on the intended function of vessel attachment welds by detection and sizing of cracks by ISI 

in accordance with the guidelines of approved BWRVIP-48 and the requirements of the 

American Society of Mechanical Engineers (ASME) Code, Section XI, Table IWB 2500-1 

(1995 edition through the 1996 addenda). An applicant may use the guidelines of 

BWRVIP-62 for inspection relief for vessel internal components with hydrogen water 

chemistry. 

4. Detection of Aging Effects: The extent and schedule of the inspection and test techniques 

prescribed by BWRVIP-48 guidelines are designed to maintain structural integrity and 

ensure that aging effects will be discovered and repaired before the loss of intended 

function. Inspection can reveal crack initiation and growth. Vessel ID attachment welds are 

inspected in accordance with the requirements of ASME Section Xi, Subsection IWB, 

examination category B-N-2. The Section XI inspection specifies visual VT-1 examination to 

detect discontinuities and imperfections on the surfaces of components and visual VT-3

April 2001 Xl M-17 NUREG-1801
examination to determine the general mechanical and structural condition of the component 

supports. The inspection and evaluation guidelines of BWRVIP-48 recommend more 

stringent inspections for certain selected attachments. The guidelines recommend 

enhanced visual VT-1 examination of all safety-related attachments and those nonsafety

related attachments identified as being susceptible to IGSCC. Visual VT-1 examination is 

capable of achieving 1/32 in. resolution; the enhanced visual VT-i examination method is 

capable of achieving a 1-mil wire resolution. The nondestructive examination (NDE) 

techniques appropriate for inspection of BWR vessel internals and their implementation 

needs, including the uncertainties inherent in delivering and executing NDE techniques in a 

BWR, are included in BWRVIP-03. 

5. Monitoring and Trending: Inspections scheduled in accordance with IWB-2400 and 

approved BWRVIP-48 guidelines provide timely detection of cracks. If flaws are detected, 

the scope of examination is expanded. 

6. Acceptance Criteria: Any indication detected is evaluated in accordance with ASME 

Section XI or the staff-approved BWRVIP-48 guidelines. Applicable and approved 

BWRVIP-14, BWRVIP-59, and BWRVIP-60 documents provide guidelines for evaluation of 

crack growth in stainless steels (SSs), nickel alloys, and low-alloy steels, respectively. 

7. Corrective Actions: Repair and replacement procedures are equivalent to those 

requirements in the ASME Section XI. Repair is in conformance with IWB-4000 and 

replacement occurs according to IWB-7000. As discussed in the appendix to this report, the 

staff finds that licensee implementation of the guidelines in BWRVIP-48, as modified, will 

provide an acceptable level of quality for inspection and flaw evaluation of the safety-related 

components addressed in accordance with 10 CFR Part 50, Appendix B, corrective actions. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds that licensee implementation of the guidelines in BWRVIP-48, as modified, 

will provide an acceptable level of quality for inspection and flaw evaluation of the safety

related components addressed in accordance with the 10 CFR Part 50, Appendix B, 

confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: Cracking due to SCC/IGSCC has occurred in BWR components. 

The program guidelines are based on evaluation of available information, including BWR 

inspection data and information on the elements that cause IGSCC, to determine which 

attachment welds may be susceptible to cracking. Implementation of the program provides 

reasonable assurance that crack initiation and growth will be adequately managed and the 

intended functions of the vessel ID attachments will be maintained consistent with the 

current licensing basis (CLB) for the period of extended operation. 

References 

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2000.

NUREG-1801 XI M-18 April 2001
ASME Section Xl, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 1995 edition through the 1996 addenda, American 

Society of Mechanical Engineers, New York, NY. 

BWRVIP-03, BWR Vessel and Internals Project, Reactor Pressure Vessel and Internals 

Examination Guidelines, (EPRI TR-105696 R1, March 30, 1999), Final Safety Evaluation 

Report by the Office of Nuclear Reactor Regulation for BWRVI P-03, July 15, 1999. 

BWRVIP-1 4, Evaluation of Crack Growth in BWR Stainless Steel RPV Internals, 

(EPRI TR-105873, July 11, 2000), Final Safety Evaluation Report by the Office of Nuclear 

Reactor Regulation for BWRVIP-14, December 3, 1999. 

BWRVIP-29, BWR Vessel and Internals Project, BWR Water Chemistry Guidelines-1993 

Revision, Normal and Hydrogen Water Chemistry, (EPRI TR- 103515), Electric Power 

Research Institute, Palo Alto, CA, February 1994. 

BWRVIP-48, BWR Vessel and Internals Project, Vessel ID Attachment Weld Inspection and 

Flaw Evaluation Guidelines, (EPRI TR-108724, February 1998), Final License Renewal 

Safety Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-48 for 

Compliance with the License Renewal Rule (10 CFR Part 54), January 17, 2001. 

BWRVIP-59, Evaluation of Crack Growth in BWR Nickel-Base Austenitic Alloys in RPV 

Internals, (EPRI TR-108710), BWRVIP and Electric Power Research Institute, Palo Alto, 

CA, March 24, 2000. 

BWRVIP-60, BWR Vessel and Internals Project, Evaluation of Crack Growth in BWR Low Alloy 

Steel RPV Internals, (EPRI TR-108709, April 14, 2000), Final Safety Evaluation Report by 

the Office of Nuclear Reactor Regulation for BWRVIP-60, July 8, 1999. 

BWRVIP-62, BWR Vessel and Internals Project, Technical Basis for Inspection Relief for BWR 

Internal Components with Hydrogen Injection, (EPRI TR-108705), BWRVIP and Electric 

Power Research Institute, Palo Alto, CA, March 7, 2000.

April 2001 Xl M-1 9 NUREG-1801
XI.M5 BWR FEEDWATER NOZZLE

Program Description 

This program includes (a) enhanced inservice inspection (IS[) in accordance with the 

requirements of the American Society of Mechanical Engineers (ASME) Code, Section X1, 

Subsection IWB, Table IWB 2500-1 (1995 edition through the 1996 addenda) and the 

recommendation of General Electric (GE) NE-523-A71-0594, and (b) system modifications to 

mitigate cracking. The program specifies periodic ultrasonic inspection of critical regions of 

boiling water reactor (BWR) feedwater nozzle. 

Evaluation and Technical Basis 

1. Scope of Program: The program includes enhanced ISI to monitor the effects of crack 

initiation and growth on the intended function of the component and systems modifications 

to mitigate cracking. 

2. Preventive Actions: Mitigation occurs by systems modifications, such as removal of 

stainless steel cladding and installation of improved spargers. Mitigation is also 

accomplished by changes to plant-operating procedures, such as improved feedwater 

control and rerouting of the reactor water cleanup system, to decrease the magnitude and 

frequency of temperature fluctuations. 

3. Parameters Monitored/Inspected: The aging management program (AMP) monitors the 

effects of cracking on the intended function of the component by detection and sizing of 

cracks by ISI in accordance with ASME Section XI, Subsection IWB and the 

recommendation of GE NE-523-A71-0594, as described below. 

4. Detection of Aging Effects: The extent and schedule of the inspection prescribed by the 

program are designed to ensure that aging effects will be discovered and repaired before 

the loss of intended function of the component. Inspection can reveal crack initiation and 

growth. The GE NE-523-A71-0594 specifies UT of specific regions of the blend radius and 

bore. The UT examination techniques and personnel qualifications are in accordance with to 

the guidelines of GE NE-523-A71-0594. Based on the inspection method and techniques 

and plant-specific fracture mechanics assessments, the inspection schedule is in 

accordance with Table 6-1 of GE NE-523-A71-0594. Leakage monitoring may be used to 

modify the inspection interval. 

5. Monitoring and Trending: Inspections scheduled in accordance with GE NE-523-A71 

0594 provides timely detection of cracks. 

6. Acceptance Criteria: Any cracking is evaluated in accordance with IWB-3100 by 

comparing inspection results with the acceptance standards of IWB-3400 and IWB-3500. 

7. Corrective Actions: Repair is in conformance with IWB-4000 and replacement in 

accordance with IWB-7000. As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable in addressing corrective actions. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

NUREG-1 801 XI M-20 April 2001
the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing 

the confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: Cracking has occurred in several BWR plants (NUREG-0619, NRC 

Generic Letter 81-11). This AMP has been implemented for nearly 20 years and found to be 

effective in managing the effect of cracking on the intended function of feedwater nozzles. 

References 

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 1995 edition through the 1996 addenda, American 

Society of Mechanical Engineers, New York, NY. 

GE-NE-523-A71-0594, Rev. 1, Alternate BWR Feedwater Nozzle Inspection Requirements, 

BWR Owner's Group, August 1999. 

NRC Generic Letter 81-11, BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle 

Cracking (NUREG-0619), U.S. Nuclear Regulatory Commission, February 29, 1981. 

NUREG-0619, BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking, 

U.S. Nuclear Regulatory Commission, November 1980.

April 2001 XI M-21 NUREG-1 801
XI.M6 BWR CONTROL ROD DRIVE RETURN LINE NOZZLE

Program Description 

This program includes (a) enhanced inservice inspection (ISI) in conformance with the 

American Society of Mechanical Engineers (ASME) Code, Section Xl, Subsection IWB, Table 

IWB 2500-1 (1995 edition through the 1996 addenda) and the recommendations of NUREG

0619, and (b) system modifications and maintenance programs to mitigate cracking. The 

program specifies periodic liquid penetrant and ultrasonic inspection of critical regions of boiling 

water reactor (BWR) control rod drive return line (CRDRL) nozzle. 

Evaluation and Technical Basis 

1. Scope of Program: The program includes systems modifications, enhanced ISI, and 

maintenance programs to monitor the effects of crack initiation and growth on the intended 

function of CRDRL nozzles. 

2. Preventive Actions: Mitigation occurs by system modifications, such as rerouting the 

CRDRL to a system that connects to the reactor vessel. For some classes of BWRs, or 

those that can prove satisfactory system operation, mitigation also is accomplished by 

confirmation of proper return flow capability, two-pump operation and cutting and capping 

the CRDRL nozzle without rerouting. 

3. Parameters Monitored/Inspected: The aging management program (AMP) monitors the 

effects of cracking on the intended function of the component by detecting and sizing cracks 

by ISI in accordance with Table IWB 2500-1 and NUREG-0619. 

4. Detection of Aging Effects: The extent and schedule of inspection, as delineated in 

NUREG 0619, assures detection of cracks before the loss of intended function of the 

component. Inspection recommendations include liquid penetrant testing (PT) of the 

CRDRL nozzle blend radius and bore regions and the reactor vessel wall area beneath the 

nozzle, return-flow-capacity demonstration, CRD-system-performance testing and ultrasonic 

inspection of welded connections in the rerouted line. The inspection is to include base 

metal to a distance of one-pipe-wall thickness or 0.5 in., whichever is greater, on both sides 

of the weld. 

5. Monitoring and Trending: The inspection schedule of NUREG-0619 provides timely 

detection of cracks. 

6. Acceptance Criteria: Any cracking is evaluated in accordance with IWB-3100 by 

comparing inspection results with the acceptance standards of IWB-3400 and IWB-3500. All 

cracks found in the CRDRL nozzles are to be removed by grinding. 

7. Corrective Actions: Repair is in conformance with IWB-4000 and replacement in 

accordance with IWB-7000. As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable in addressing corrective actions. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing 

the confirmation process and administrative controls. 

NUREG-1801 XI M-22 April 2001

I I
9. Administrative Controls: See Item 8, above.

10. Operating Experience: Cracking has occurred in several BWR plants (NUREG-0619). The 

present AMP has been implemented for nearly 20 years and found to be effective in 

managing the effect of cracking on the intended function of CRDRL nozzles. 

References 

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2000. 

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 1995 edition through the 1996 addenda, American 

Society of Mechanical Engineers, New York, NY. 

NUREG-0619, BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking, 

U.S. Nuclear Regulatory Commission, November 1980.

April 2001 Xl M-23 NUREG-1801
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) is delineated in 

NUREG-0313, Rev. 2, and Nuclear Regulatory Commission (NRC) Generic Letter (GL) 88-01 

and its Supplement 1. The program includes (a) preventive measures to mitigate IGSCC, and 

(b) inspection and flaw evaluation to monitor IGSCC and its effects. The staff-approved boiling 

water reactor vessel and internals project (BWRVIP)-75 report allows for modifications of 

inspection scope in the GL 88-01 program. 

Evaluation and Technical Basis 

1. Scope of Program: The program focuses on (a) managing and implementing 

countermeasures to mitigate IGSCC and (b) performing inservice inspection (ISI) to monitor 

IGSCC and its effects on the intended function of BWR components. The program is 

applicable to all BWR piping made of austenitic SS that is 4 in. or larger in nominal diameter 

and contains reactor coolant at a temperature above 93 0C (2000 F) during power operation, 

regardless of code classification. The program also applies to pump casings, valve bodies 

and reactor vessel attachments and appurtenances, such as head spray and vent 

components. NUREG-0313 and NRC GL-88-01, respectively, describe the technical basis 

and staff guidance regarding mitigation of IGSCC in BWRs. Attachment A of NRC GL 88-01 

delineates the staff-approved positions regarding materials, processes, water chemistry, 

weld overlay reinforcement, partial replacement, stress improvement of cracked welds, 

clamping devices, crack characterization and repair criteria, inspection methods and 

personnel, inspection schedules, sample expansion, leakage detection, and reporting 

requirements. 

2. Preventive Actions: The comprehensive program outlined in NUREG-0313 and NRC 

GL 88-01 addresses improvements in all three elements that, in combination, cause IGSCC. 

These elements consist of a susceptible (sensitized) material, a significant tensile stress, 

and an aggressive environment. Sensitization of nonstabilized austenitic SSs containing 

greater than 0.03 wt.% carbon involves precipitation of chromium carbides at the grain 

boundaries during certain fabrication or welding processes. The formation of carbides 

creates an envelope of chromium depleted region that, in certain environments, is 

susceptible to stress corrosion cracking (SCC). Residual tensile stresses are introduced 

from fabrication processes, such as welding, surface grinding, or forming. High levels of 

dissolved oxygen or aggressive contaminants, such as sulfates or chlorides, accelerate the 

SCC processes. 

The program delineated in NUREG-0313 and NRC GL 88-01 and in the staff-approved 

BWRVIP-75 report includes recommendations regarding selection of materials that are 

resistant to sensitization, use of special processes that reduce residual tensile stresses, and 

monitoring and maintenance of coolant chemistry. The resistant materials are used for new 

and replacement components and include low-carbon grades of austenitic SS and weld 

metal, with a maximum carbon of 0.035 wt.% and a minimum ferrite of 7.5% in weld metal 

and cast austenitic stainless steel (CASS). Inconel 82 is the only commonly used nickel

base weld metal considered to be resistant to SCC; other nickel-alloys, such as Alloy 600 

are evaluated on an individual basis. Special processes are used for existing, new, and 

replacement components. These processes include solution heat treatment, heat sink 

welding, induction heating, and mechanical stress improvement. 

NUREG-1801 XI M-24 April 2001

I I
The program delineated in NUREG-0313 and NRC GL 88-01 does not provide specific 

guidelines for controlling reactor water chemistry to mitigate IGSCC. Maintaining high water 

purity reduces susceptibility to SCC or IGSCC. Reactor coolant water chemistry is 

monitored and maintained in accordance with the guidelines in BWRVIP-29 (Electric Power 

Research Institute [EPRI] TR-103515). The program description, and evaluation and 

technical basis of monitoring and maintaining reactor water chemistry are presented in 

Section XI.M2, 'Water Chemistry." 

3. Parameters Monitored/Inspected: The program detects and sizes cracks and detects 

leakage by using the examination and inspection guidelines delineated in NUREG 0313, 

Rev. 2, and NRC GL 88-01 or the referenced BWRVIP-75 guideline as approved by the 

NRC staff. 

4. Detection of Aging Effects: The extent, method, and schedule of the inspection and test 

techniques delineated in NRC GL 88-01 or BWRVIP-75 are designed to maintain structural 

integrity and ensure that aging effects will be discovered and repaired before the loss of 

intended function of the component. The program uses volumetric examinations to detect 

IGSCC. 

The NRC GL 88-01 recommends that the detailed inspection procedure, equipment, and 

examination personnel be qualified by a formal program approved by the NRC. These 

inspection guidelines, updated in the approved BWRVIP-75 document, provide the technical 

basis for revisions to NRC GL 88-01 inspection schedules. Inspection can reveal crack 

initiation and growth 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). The inspection guidance in approved BWRVIP-75 replaces 

the extent and schedule of inspection in NRC GL 88-01. 

5. Monitoring and Trending: The extent and schedule for inspection, in accordance with the 

recommendations of NRC GL 88-01 or approved BWRVIP-75 guidelines, provide timely 

detection of cracks and leakage of coolant. Based on inspection results, NRC GL 88-01 or 

approved BWRVIP-75 guidelines provide guidelines for additional samples of welds to be 

inspected when one or more cracked welds are found in a weld category. 

6. Acceptance Criteria: As recommended in NRC GL 88-01, any indication detected is 

evaluated in accordance with the ASME Section XI, Subsection IWB-3640 (1995 edition 

through the 1996 addenda) and the guidelines of NUREG-0313. 

Applicable and approved BWRVIP-14, BWRVIP-59, BWRVIP-60, and BWRVIP-62 

documents provide guidelines for evaluation of crack growth in SSs, nickel alloys, and low

alloy steels. An applicant may use BWRVIP-61 guidelines for BWR vessel and internals 

induction heating stress improvement effectiveness on crack growth in operating plants. 

7. Corrective Actions- The guidance for weld overlay repair and stress improvement or 

replacement is provided in NRC GL 88-01; ASME Section XI, Subsections IWB-4000 and 

IWB-7000, IWC-4000 and IWC-7000, or IWD-4000 and IWD-7000, respectively for Class 1, 

2, or 3 components; and ASME Code Case N 504-1. As discussed in the appendix to this 

report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in 

addressing corrective actions.

April 2001 XI M-25 NUREG-1801
8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing 

the confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: Intergranular stress corrosion cracking has occurred in small- and 

large-diameter BWR piping made of austenitic stainless steel and nickel-base alloys. 

Cracking has occurred in recirculation, core spray, residual heat removal (RHR), and 

reactor water cleanup (RWCU) system piping welds (NRC GL 88-01, NRC Information 

Notices [INs] 82-39 and 84-41). The comprehensive program outlined in NRC GL 88-01 and 

NUREG-0313 and in the staff-approved BWRVIP-75 report addresses mitigating measures 

for SCC or IGSCC (e.g., susceptible material, significant tensile stress, and an aggressive 

environment). The GL 88-01 program has been effective in managing IGSCC in BWR 

reactor coolant pressure-retaining components and the revision to the GL 88-01 program, 

according to the staff-approved BWRVIP-75 report, will adequately manage IGSCC 

degradation. 

References 

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2000. 

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, 1995 edition through the 1996 addenda, American 

Society of Mechanical Engineers, New York, NY. 

BWRVI P-1 4, Evaluation of Crack Growth in BWR Stainless Steel RPV Internals, 

(EPRI TR-105873, July 11, 2000), Final Safety Evaluation Report by the Office of Nuclear 

Reactor Regulation for BWRVIP-14, December 3, 1999. 

BWRVIP-29 (EPRI TR-1 03515), BWR Vessel and Internals Project, BWR Water Chemistry 

Guidelines-1993 Revision, Normal and Hydrogen Water Chemistry, Electric Power 

Research Institute, Palo Alto, CA, February 1994. 

BWRVIP-59, Evaluation of Crack Growth in BWR Nickel-Base Austenitic Alloys in RPV 

Internals, (EPRI TR-108710), BWRVIP and Electric Power Research Institute, Palo Alto, 

CA, March 24, 2000. 

BWRVIP-60, BWR Vessel and Internals Project, Evaluation of Crack Growth in BWR Low Alloy 

Steel RPV Internals, (EPRI TR-108709, April 14, 2000), Final Safety Evaluation Report by 

the Office of Nuclear Reactor Regulation for BWRVIP-60, July 8, 1999. 

NUREG-1 801 XI M-26 April 2001

I I
BWRVIP-61, BWR Vessel and Internals Induction Heating Stress Improvement Effectiveness 

on Crack Growth in Operating Reactors, (EPRI TR- 112076), BWRVIP and Electric Power 

Research Institute, Palo Alto, CA, January 29, 1999. 

BWRVIP-62, BWR Vessel and Internals Project, Technical Basis for Inspection Relief for BWR 

Internal Components with Hydrogen Injection, (EPRI TR-108705), BWRVIP and Electric 

Power Research Institute, Palo Alto, CA, March 7, 2000. 

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

(NUREG-0313), (EPRI TR- 113932, Feb. 29, 2000), Initial Safety Evaluation Report by the 

Office of Nuclear Reactor Regulation for BWRVIP-75, September 15, 2000. 

NRC Generic Letter 88-01, NRC Position on IGSCC in BWR Austenitic Stainless Steel Piping, 

U.S. Nuclear Regulatory Commission, January 25, 1988; Supplement 1, February 4, 1992. 

NRC Information Notice 82-39, Service Degradation of Thick Wall Stainless Steel Recirculation 

System Piping at a BWR Plant, U.S. Nuclear Regulatory Commission, September 21, 1982. 

NRC Information Notice 84-41, IGSCC in BWR Plants, U.S. Nuclear Regulatory Commission, 

June 1, 1984. 

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.

April 2001 Xl M-27 NUREG-1801
XI.M8 BWR PENETRATIONS

Program Description 

The program includes (a) inspection and flaw evaluation in conformance with the guidelines of 

staff-approved boiling water reactor vessel and internals project (BWRVIP)-49 and 

BWRVIP-27 documents and (b) monitoring and control of reactor coolant water chemistry in 

accordance with the guidelines of BWRVIP-29 (Electric Power Research Institute [EPRI] 

TR-103515) to ensure the long-term integrity and safe operation of boiling water reactor (BWR) 

vessel internal components. The BWRVIP-49 provides guidelines for instrument penetrations, 

and BWRVIP-27 addresses the standby liquid control (SLC) system nozzle or housing. 

Evaluation and Technical Basis 

1. Scope of Program: The program is focused on managing the effects of crack initiation and 

growth due to stress corrosion cracking (SCC) or intergranular stress corrosion cracking 

(IGSCC). The program contains preventive measures to mitigate SCC or IGSCC, inservice 

inspection (ISI) to monitor the effects of cracking on the intended function of the 

components, and repair and/or replacement as needed to maintain the ability to perform the 

intended function. 

The inspection and evaluation guidelines of BWRVIP-49 and BWRVIP-27 contain generic 

guidelines intended to present appropriate inspection recommendations to assure safety 

function integrity. The guidelines of BWRVIP-49 provide information on the type of 

instrument penetration, evaluate their susceptibility and consequences of failure, and define 

the inspection strategy to assure safe operation. The guidelines of BWRVIP-27 are 

applicable to plants in which the SLC system injects sodium pentaborate into the bottom 

head region of the vessel (in most plants, as a pipe within a pipe of the core plate 

AP monitoring system). The BWRVIP-27 guidelines address the region where the AP and 

SLC nozzle or housing penetrates the vessel bottom head and include the safe ends 

welded to the nozzle or housing. Guidelines for repair design criteria are provided in 

BWRVIP-57 for instrumentation penetrations and BWRVIP-53 for SLC line. 

2. Preventive Actions: Maintaining high water purity reduces susceptibility to SCC or IGSCC. 

Reactor coolant water chemistry is monitored and maintained in accordance with the 

guidelines in BWRVIP-29 (EPRI TR-103515). The program description and the evaluation 

and technical basis of monitoring and maintaining reactor water chemistry are presented in 

Chapter XI.M2, "Water Chemistry". 

3. Parameters Monitored/Inspected: The program monitors the effects of SCC/IGSCC on 

the intended function of the component by detection and sizing of cracks by IS in 

accordance with the guidelines of approved BWRVIP-49 or BWRVIP-27 and the 

requirements of the American Society of Mechanical Engineers (ASME) Code, Section XI, 

Table IWB 2500-1 (1995 edition through the 1996 addenda). An applicant may use the 

guidelines of BWRVIP-62 for inspection relief for vessel internal components with hydrogen 

water chemistry. 

4. Detection of Aging Effects: The evaluation guidelines of BWRVIP-49 and BWRVIP-27 

recommend that the inspection requirements currently in ASME Section XI continue to be 

followed. The extent and schedule of the inspection and test techniques prescribed by the 

ASME Section XI program are designed to maintain structural integrity and ensure that 

NUREG-1801 Xl M-28 April 2001

I I
aging effects will be discovered and repaired before the loss of intended function of the 

component. Inspection can reveal crack initiation and growth and leakage of coolant. The 

nondestructive examination (NDE) techniques appropriate for inspection of BWR vessel 

internals and their implementation needs, including the uncertainties inherent in delivering 

and executing NDE techniques in a BWR, are included in BWRVIP-03. 

Instrument penetrations and SLC system nozzles or housings are inspected in accordance 

with the requirements of ASME Section Xl, Subsection IWB. Components are examined 

and tested as specified in Table IWB-2500-1, examination categories B-E for pressure

retaining partial penetration welds in vessel penetrations, B-D for full penetration nozzle-to

vessel welds, B-F for pressure-retaining dissimilar metal nozzle-to-safe end welds, or B-J 

for similar metal nozzle-to-safe end welds. In addition, these components are part of 

examination category B-P for pressure-retaining boundary. Further details for examination 

are described in Chapter XI.M1, "ASME Section XI, Inservice Inspection, Subsections IWB, 

IWC, and IWD," of this report. 

5. Monitoring and Trending: Inspections scheduled in accordance with IWB-2400 and 

approved BWRVIP-48 or BWRVIP-27 provide timely detection of cracks. The scope of 

examination expansion and reinspection beyond the baseline inspection are required if 

flaws are detected. 

6. Acceptance Criteria: Any indication detected is evaluated in accordance with ASME 

Section Xl or other acceptable flaw evaluation criteria, such as the staff-approved 

BWRVIP-49 or BWRVIP-27 guidelines. Applicable and approved BWRVIP-14, BWRVIP-59, 

and BWRVIP-60 documents provide guidelines for evaluation of crack growth in stainless 

steels (SSs), nickel alloys, and low-alloy steels, respectively. 

7. Corrective Actions: Repair and replacement procedures in the staff-approved BWRVIP-57 

and BWRVIP-53 are equivalent to those requirements in the ASME Section XI. Guidelines 

for repair design criteria are provided in BWRVIP-57 for instrumentation penetrations and 

BWRVIP-53 for standby liquid control line. As discussed in the appendix to this report, the 

staff finds that licensee implementation of the guidelines in BWRVIP-48, as modified, will 

provide an acceptable level of quality for inspection and flaw evaluation of the safety-related 

components addressed in accordance with 10 CFR Part 50, Appendix B. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds that licensee implementation of the guidelines in BWRVIP-48, as modified, 

will provide an acceptable level of quality for inspection and flaw evaluation of the safety

related components addressed in accordance with the 10 CFR Part 50, Appendix B, 

confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: Cracking due to SCC or IGSCC has occurred in BWR components 

made of austenitic stainless steels and nickel alloys. The program guidelines are based on 

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 crack initiation 

and growth will be adequately managed so the intended functions of the instrument

April 2001 Xl M-29 NUREG-1 801
penetrations and SLC system nozzles or housings will be maintained consistent with the 

current licensing basis (CLB) for the period of extended operation. 

References 

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2000. 

ASME Section Xl, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 1995 edition through the 1996 addenda, American 

Society of Mechanical Engineers, New York, NY. 

BWRVIP-03, BWR Vessel and Internals Project, Reactor Pressure Vessel and Internals 

Examination Guidelines, (EPRI TR-105696 R1, March 30, 1999), Final Safety Evaluation 

Report by the Office of Nuclear Reactor Regulation for BWRVIP-03, July 15, 1999. 

BWRVI P-1 4, Evaluation of Crack Growth in BWR Stainless Steel RPV Internals, 

(EPRI TR-105873, July 11, 2000), Final Safety Evaluation Report by the Office of Nuclear 

Reactor Regulation for BWRVIP-14, December 3, 1999. 

BWRVIP-27, BWR Vessel and Internals Project, BWR Standby Liquid Control System/Core 

Plate P Inspection and Flaw Evaluation Guidelines, (EPRI TR-107286, April 1997), Final 

License Renewal Safety Evaluation Report by the Office of Nuclear Reactor Regulation for 

BWRVIP-27 for Compliance with the License Renewal Rule (10 CFR Part 54), 

December 20, 1999. 

BWRVIP-29 (EPRI TR-103515), BWR Vessel and Internals Project, BWR Water Chemistry 

Guidelines-1993 Revision, Normal and Hydrogen Water Chemistry, Electric Power 

Research Institute, Palo Alto, CA, February 1994. 

BWRVIP-48, BWR Vessel and Internals Project, Vessel ID Attachment Weld Inspection and 

Flaw Evaluation Guidelines, (EPRI TR-108724, February 1998), Final License Renewal 

Safety Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-48 for 

Compliance with the License Renewal Rule (10 CFR Part 54), January 17, 2001. 

BWRVIP-49, BWR Vessel and Internals Project, Instrument Penetration Inspection and Flaw 

Evaluation Guidelines, (EPRI TR-108695, March 1998), Final License Renewal Safety 

Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-49 for 

Compliance with the License Renewal Rule (10 CFR Part 54), September 1, 1999. 

BWRVIP-53, BWR Vessel and Internals Project, Standby Liquid Control Line Repair Design 

Criteria, (EPRI TR-108716, March 24, 2000), Initial Safety Evaluation Report by the Office 

of Nuclear Reactor Regulation for BWRVIP-53, October 26, 2000. 

BWRVIP-57, BWR Vessel and Internals Project, Instrument Penetration Repair Design Criteria, 

(EPRI TR-108721), BWRVIP and Electric Power Research Institute, Palo Alto, CA, 

March 24, 2000. 

BWRVIP-59, Evaluation of Crack Growth in BWR Nickel-Base Austenitic Alloys in RPV 

Internals, (EPRI TR-108710), BWRVIP and Electric Power Research Institute, Palo Alto, 

CA, March 24, 2000. 

NUREG-1 801 XI M-30 April 2001
BWRVIP-60, BWR Vessel and Internals Project, Evaluation of Crack Growth in BWR Low Alloy 

Steel RPV Internals, (EPRI TR-108709, April 14, 2000), Final Safety Evaluation Report by 

the Office of Nuclear Reactor Regulation for BWRVIP-60, July 8, 1999. 

BWRVIP-62, BWR Vessel and Internals Project, Technical Basis for Inspection Relief for BWR 

Internal Components with Hydrogen Injection, (EPRI TR-108705), BWRVIP and Electric 

Power Research Institute, Palo Alto, CA, March 7, 2000.

April 2001 Xl M-31 NUREG-1801
XI.M9 BWR VESSEL INTERNALS

Program Description 

The program includes (a) inspection and flaw evaluation in conformance with the guidelines of 

applicable and staff-approved boiling water reactor vessel and internals project (BWRVIP) 

documents and (b) monitoring and control of reactor coolant water chemistry in accordance with 

the guidelines of BWRVIP-29 (Electric Power Research Institute [EPRI] TR-103515) to ensure 

the long-term integrity and safe operation of boiling water reactor (BWR) vessel internal 

components. 

Evaluation and Technical Basis 

1. Scope of Program: The program is focused on managing the effects of crack initiation and 

growth due to stress corrosion cracking (SCC), intergranular stress corrosion cracking 

(IGSCC), or irradiation assisted stress corrosion cracking (IASCC). The program contains 

preventive measures to mitigate SCC, IGSCC, or IASCC; inservice inspection (ISI) to 

monitor the effects of cracking on the intended function of the components; and repair 

and/or replacement as needed to maintain the ability to perform the intended function. 

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 include information on 

component description and function; evaluate susceptible locations and safety 

consequences of failure; provide recommendations for methods, extent, and frequency of 

inspection; discuss acceptable methods for evaluating the structural integrity significance of 

flaws detected during these examinations; and recommend repair and replacement 

procedures. 

The various applicable BWRVIP guidelines are as follows: 

Core shroud: BWRVIPs-07, -63, and -76 provide guidelines for inspection and evaluation; 

BWRVIP-02, Rev. 2, provides guidelines for repair design criteria. 

Core plate: BWRVIP-25 provides guidelines for inspection and evaluation; BWRVIP-50 

provides guidelines for repair design criteria. 

Shroud support: BWRVIP-38, provides guidelines for inspection and evaluation; 

BWRVIP-52 provides guidelines for repair design criteria. 

Low-pressure coolant injection (LPCI) coupling: BWRVIP-42 provides guidelines for 

inspection and evaluation; BWRVIP-56 provides guidelines for repair design criteria. 

Top guide: BWRVIP-26 provides guidelines for inspection and evaluation; BWRVIP-50 

provides guidelines for repair design criteria. 

Core spray: BWRVIP-1 8 provides guidelines for inspection and evaluation; BWRVIP-1 6 and 

19 provides guidelines for replacement and repair design criteria, respectively. 

Jet pump assembly: BWRVIP-41 provides guidelines for inspection and evaluation; 

BWRVIP-51 provides guidelines for repair design criteria.

NUREG-1801 XI M-32 April 2001
Control rod drive (CRD) housing: BWRVIP-47 provides guidelines for inspection and 

evaluation; BWRVIP-58 provides guidelines for repair design criteria. 

Lower plenum: BWRVIP-47 provides guidelines for inspection and evaluation; BWRVIP-57 

provides guidelines for repair design criteria for instrument penetrations. 

In addition, BWRVIP-44 provides guidelines for weld repair of nickel alloys; BWRVIP-45 

provides guidelines for weldability of irradiated structural components. 

2. Preventive Actions: Maintaining high water purity reduces susceptibility to cracking due to 

SCC or IGSCC. Reactor coolant water chemistry is monitored and maintained in 

accordance with the guidelines in BWRVIP-29 (EPRI TR-1 03515). The program description 

and evaluation, and technical basis of monitoring and maintaining reactor water chemistry 

are presented in Chapter XI.M2, 'Water Chemistry." 

3. Parameters Monitored/Inspected: The program monitors the effects of cracking on the 

intended function of the component by detection and sizing of cracks by inspection in 

accordance with the guidelines of applicable and approved BWRVIP documents and the 

requirements of the American Society of Mechanical Engineers (ASME) Code, Section XI, 

Table IWB 2500-1 (1995 edition through the 1996 addenda). An applicant may use the 

guidelines of BWRVIP-62 for inspection relief for vessel internal components with hydrogen 

water chemistry. 

4. Detection of Aging Effects: The extent and schedule of the inspection and test techniques 

prescribed by the applicable and approved BWRVIP guidelines are designed to maintain 

structural integrity and ensure that aging effects will be discovered and repaired before the 

loss of intended function. Inspection can reveal crack initiation and growth. Vessel internal 

components are inspected in accordance with the requirements of ASME Section Xl, 

Subsection IWB, examination category B-N-2. The ASME Section XI inspection specifies 

visual VT-1 examination to detect discontinuities and imperfections, such as cracks, 

corrosion, wear, or erosion, on the surfaces of components. This inspection also specifies 

visual VT-3 examination to determine the general mechanical and structural condition of the 

component supports by (a) verifying parameters, such as clearances, settings, and physical 

displacements, and (b) detecting discontinuities and imperfections, such as loss of integrity 

at bolted or welded connections, loose or missing parts, debris, corrosion, wear, or erosion. 

The applicable and approved BWRVIP guidelines recommend more stringent inspections, 

such as enhanced visual VT-I 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 and their implementation 

needs, including the uncertainties inherent in delivering and executing NDE techniques in a 

BWR, are included in BWRVIP-03. 

5. Monitoring and Trending: Inspections scheduled in accordance with the applicable and 

approved BWRVIP guidelines provide timely detection of cracks. The scope of examination 

expansion and reinspection beyond the baseline inspection are required if flaws are 

detected. 

6. Acceptance Criteria: Any indication detected is evaluated in accordance with ASME 

Section XI or the applicable staff-approved BWRVIP guidelines. Approved BWRVIP-14, 

BWRVIP-59, and BWRVIP-60 documents provide guidelines for evaluation of crack growth 

in stainless steels (SSs), nickel alloys, and low-alloy steels, respectively.

April 2001 XI M-33 NUREG-1801
7. Corrective Actions: Repair and replacement procedures are equivalent to those 

requirements in ASME Section Xl. Repair and replacement is in conformance with the 

applicable and approved BWRVIP guidelines listed above. As discussed in the appendix to 

this report, the staff finds that licensee implementation of the guidelines in the staff

approved BWRVIP reports will provide an acceptable level of quality for inspection and flaw 

evaluation of the safety-related components addressed in accordance with 10 CFR Part 50, 

Appendix B. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds that licensee implementation of the guidelines in the staff-approved BWRVIP 

reports will provide an acceptable level of quality for inspection and flaw evaluation of the 

safety-related components addressed in accordance with the 10 CFR Part 50, Appendix B, 

confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: Extensive cracking has been observed in core shrouds at both 

horizontal (Nuclear Regulatory Commission [NRC] Generic Letter [GL] 94-03) and vertical 

(NRC Information Notice [IN] 97-17) welds. It has affected shrouds fabricated from Type 

304 and Type 304L SS, which is generally considered to be more resistant to SCC. Weld 

regions are most susceptible, although it is not clear whether this is due to sensitization 

and/or impurities associated with the welds or the high residual stresses in the weld regions. 

This experience is reviewed in NRC GL 94-03 and NUREG-1 544; some experiences with 

visual inspections are discussed in NRC IN 94-42. 

Both circumferential (NRC IN 88-03) and radial cracking (NRC IN 92-57) has been observed 

in the shroud support access hole cover made from Alloy 600. Instances of cracking in core 

spray spargers have been reviewed in NRC IE Bulletin 80-13. 

Cracking of the core plate has not been reported, but the creviced regions beneath the plate 

are difficult to inspect. The 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-1 544. Cracking has also been observed in the top guide of a 

Swedish BWR. 

Instances of cracking have occurred in the jet pump assembly (NRC IE Bulletin 80-07), 

hold-down beam (NRC IN 93-101), and jet pump riser pipe elbows (NRC IN 97-02). 

Cracking of dry tubes has been observed at 14 or more BWRs. The cracking is 

intergranular and has been observed in dry tubes without apparent sensitization, suggesting 

that IASCC may also play a role in the cracking. 

The program guidelines outlined in applicable and approved BWRVIP documents are based 

on 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 

crack initiation and growth 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. 

NUREG-1801 XI M-34 April 2001
References

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2000. 

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 1995 edition through the 1996 addenda, American 

Society of Mechanical Engineers, New York, NY. 

BWRVIP-02, BWR Vessel and Internals Project, BWR Core Shroud Repair Design Criteria, 

Rev. 2, BWRVIP and Electric Power Research Institute, Palo Alto, CA, March 7, 2000. 

BWRVIP-03, BWR Vessel and Internals Project, Reactor Pressure Vessel and Internals 

Examination Guidelines, (EPRI TR-105696 R1, March 30, 1999), Final Safety Evaluation 

Report by the Office of Nuclear Reactor Regulation for BWRVIP-03, July 15, 1999. 

BWRVIP-07, BWR Vessel and Internals Project, Guidelines for Reinspection of BWR Core 

Shrouds, (EPRI TR-105747, Feb. 29, 1996), Final Safety Evaluation Report by the Office of 

Nuclear Reactor Regulation for BWRVIP-07, April 27, 1998. 

BWRVIP-1 4, Evaluation of Crack Growth in BWR Stainless Steel RPV Internals, 

(EPRI TR-105873, July 11, 2000), Final Safety Evaluation Report by the Office of Nuclear 

Reactor Regulation for BWRVIP-14, December 3, 1999. 

BWRVIP-1 6, Internal Core Spray Piping and Sparger Replacement Design Criteria, 

(EPRI TR-106708), BWRVIP and Electric Power Research Institute, Palo Alto, CA, March 7, 

2000. 

BWRVIP-1 8, BWR Vessel and Internals Project, BWR Core Spray Internals Inspection and 

Flaw Evaluation Guidelines, (EPRI TR-106740, July 1996), Final License Renewal Safety 

Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVI P-1 8 for 

Compliance with the License Renewal Rule (10 CFR Part 54), December 7, 2000. 

BWRVI P-19, Internal Core Spray Piping and Sparger Repair Design Criteria, 

(EPRI TR 106893), BWRVIP and Electric Power Research Institute, Palo Alto, CA, March 7, 

2000. 

BWRVIP-25, BWR Vessel and Internals Project, BWR Core Plate Inspection and Flaw 

Evaluation Guidelines, (EPR! TR-107284, Dec. 1996), Final License Renewal Safety 

Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-25 for 

Compliance with the License Renewal Rule (10 CFR Part 54), December 7, 2000. 

BWRVIP-26, BWR Vessel and Internals Project, Top Guide Inspection and Flaw Evaluation 

Guidelines, (EPRI TR-107285, Dec. 1996), Final License Renewal Safety Evaluation Report 

by the Office of Nuclear Reactor Regulation for BWRVIP-26 for Compliance with the 

License Renewal Rule (10 CFR Part 54), December 7, 2000. 

BWRVIP-29, BWR Vessel and Internals Project, BWR Water Chemistry Guidelines-1993 

Revision, Normal and Hydrogen Water Chemistry, (EPRI TR- 103515), Electric Power 

Research Institute, Palo Alto, CA, February 1994.

April 2001 XI M-35 NUREG-1 801
BWRVIP-38, BWR Vessel and Internals Project, BWR Shroud Support Inspection and Flaw 

Evaluation Guidelines, (EPRI TR-108823, September 1997), Final License Renewal Safety Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-38 for 

Compliance with the License Renewal Rule (10 CFR Part 54), March 1, 2001. 

BWRVIP-41, BWR Vessel and Internals Project, BWR Jet Pump Assembly Inspection and Flaw 

Evaluation Guidelines, (EPRI TR-108728, October 1997), Final License Renewal Safety Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-41 for 

Compliance with the License Renewal Rule (10 CFR Part 54), June 15, 2001. 

BWRVIP-42, BWR Vessel and Internals Project, BWR LPCI Coupling Inspection and Flaw 

Evaluation Guidelines, (EPRI TR-108726, December 1997), Final License Renewal Safety Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-42 for 

Compliance with the License Renewal Rule (10 CFR Part 54), January 9, 2001. 

BW RVI P-44, Underwater Weld Repair of Nickel Alloy Reactor Vessel Internals, 

(EPRI TR-108708, April 3, 2000), Final Safety Evaluation Report by the Office of Nuclear 

Reactor Regulation for BWRVIP-44, June 9, 1999. 

BW RVI P-45, Weldability of Irradiated L WR Structural Components, (EPRI TR- 108707), BWRVIP and Electric Power Research Institute, Palo Alto, CA, June 14, 2000. 

BWRVIP-47, BWR Vessel and Internals Project, BWR Lower Plenum Inspection and Flaw 

Evaluation Guidelines, (EPRI TR-108727, December 1997), Final License Renewal Safety Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-47 for 

Compliance with the License Renewal Rule (10 CFR Part 54), December 7, 2000. 

BWRVIP-50, Top Guide/Core Plate Repair Design Criteria, (EPRI TR-108722), BWRVIP and 

Electric Power Research Institute, Palo Alto, CA, April 3, 2000. 

BWRVI P-51, Jet Pump Repair Design Criteria, (EPRI TR-108718, March 7, 2000), Initial Safety Evaluation Report by the Office of Nuclear Reactor Regulation for BWRVIP-51, 

October 28, 2000. 

BWRVIP-52, Shroud Support and Vessel Bracket Repair Design Criteria, (EPRI TR-108720, 

June 26, 1998), Initial Safety Evaluation Report by the Office of Nuclear Reactor Regulation 

for BWRVIP-52, November 2, 2000. 

BWRVIP-56, LPCI Coupling Repair Design Criteria, (EPRI TR-108717), BWRVIP and Electric 

Power Research Institute, Palo Alto, CA, March 24, 2000. 

BWRVIP-57, Instrument Penetration Repair Design Criteria, (EPRI TR-108721), BWRVIP and 

Electric Power Research Institute, Palo Alto, CA, March 24, 2000. 

BWRVIP-58, CRD InternalAccess Weld Repair, (EPRI TR-108703), BWRVIP and Electric 

Power Research Institute, Palo Alto, CA, March 7, 2000. 

BWRVIP-59, Evaluation of Crack Growth in BWR Nickel-Base Austenitic Alloys in RPV 

Internals, (EPRI TR-108710), BWRVIP and Electric Power Research Institute, Palo Alto, 

CA, March 24, 2000. 

NUREG-1801 XI M-36 April 2001

I I
BWRVIP-60, BWR Vessel and Internals Project, Evaluation of Crack Growth in BWR Low Alloy 

Steel RPV Internals, (EPRI TR-108709, April 14, 2000), Final Safety Evaluation Report by 

the Office of Nuclear Reactor Regulation for BWRVIP-60, July 8, 1999. 

BWRVIP-62, BWR Vessel and Internals Project, Technical Basis for Inspection Relief for BWR 

Internal Components with Hydrogen Injection, (EPRI TR-108705), BWRVIP and Electric 

Power Research Institute, Palo Alto, CA, March 7, 2000. 

BWRVIP-63, BWR Vessel and Internals Project, Shroud Vertical Weld Inspection and 

Evaluation Guidelines, (EPRI TR- 113117, Feb. 29, 2000), Initial Safety Evaluation Report by 

the Office of Nuclear Reactor Regulation for BWRVIP-63, April 18, 2000. 

BWRVIP-76, BWR Vessel and Internals Project, BWR Core Shroud Inspection and Flaw 

Evaluation Guidelines, (EPRI TR- 114232, November 1999). 

NRC Generic Letter 94-03, Intergranular Stress Corrosion Cracking of Core Shrouds in Boiling 

Water Reactors, U.S. Nuclear Regulatory Commission, July 25, 1994. 

NRC IE Bulletin No. 80-07, BWR Jet Pump Assembly Failure, U.S. Nuclear Regulatory 

Commission, April 4, 1980. 

NRC IE Bulletin No. 80-13, Cracking in Core Spray Spargers, U.S. Nuclear Regulatory 

Commission, May 12,1980. 

NRC IE Bulletin No. 80-07, Supplement 1, BWR Jet Pump Assembly Failure, U.S. Nuclear 

Regulatory Commission, May 13, 1980. 

NRC Information Notice 88-03, Cracks in Shroud Support Access Hole Cover Welds, 

U.S. Nuclear Regulatory Commission, February 2, 1988. 

NRC Information Notice 92-57, Radial Cracking of Shroud Support Access Hole Cover Welds, 

U.S. Nuclear Regulatory Commission, August 11, 1992. 

NRC Information Notice 93-101, Jet Pump Hold-Down Beam Failure, U.S. Nuclear Regulatory 

Commission, December 17, 1993. 

NRC Information Notice 94-42, Cracking in the Lower Region of the Core Shroud in Boiling 

Water Reactors, U.S. Nuclear Regulatory Commission, June 7, 1994. 

NRC Information Notice 95-17, Reactor Vessel Top Guide and Core Plate Cracking, 

U.S. Nuclear Regulatory Commission, March 10, 1995. 

NRC Information Notice 97-02, Cracks Found in Jet Pump Riser Assembly Elbows at Boiling 

Water Reactors, U.S. Nuclear Regulatory Commission, February 6, 1997. 

NRC Information Notice 97-17, Cracking of Vertical Welds in the Core Shroud and Degraded 

Repair, U.S. Nuclear Regulatory Commission, April 4,1997.

April 2001 XI M-37 NUREG-1 801
NUREG-1 544, Status Report: Intergranular Stress Corrosion Cracking of BWR Core Shrouds 

and Other Internal Components, U.S. Nuclear Regulatory Commission, March 1996.

NUREG-1801 XI M-38 April 2001
XI.M10 BORIC ACID CORROSION

Program Description 

The program relies on implementation of recommendations of 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. 

Evaluation and Technical Basis 

1. Scope of Program: The program covers any carbon steel and low-alloy steel structures or 

components, and electrical components, on which borated reactor water may leak. The 

program includes recommendations of NRC GL 88-05. The staff guidance of NRC 

GL 88-05 provides a program consisting of systematic measures to ensure that corrosion 

caused by leaking borated coolant does not lead to degradation of the leakage source or 

adjacent structures and components, and provides assurance that the reactor coolant 

pressure boundary will have an extremely low probability of abnormal leakage, rapidly 

propagating failure, or gross rupture. Such a program provides for (a) determination of the 

principal location of leakage, (b) examination requirements and procedures for locating 

small leaks, and (c) engineering evaluations and corrective actions to ensure that boric acid 

corrosion does not lead to degradation of the leakage source or adjacent structures or 

components, which could cause the loss of intended function of the structures or 

components. 

2. Preventive Actions: Minimizing reactor coolant leakage by frequent monitoring of the 

locations where potential leakage could occur, and timely repair if leakage is detected, 

prevents or mitigates boric acid corrosion. Preventive measures also include modifications 

in the design or operating procedures to reduce the probability of leaks at locations where 

they may cause corrosion damage and use of suitable corrosion resistant materials or the 

application of protective coatings. 

3. Parameters Monitored/inspected: The aging management program (AMP) monitors the 

effects of boric acid corrosion on the intended function of an affected structure and 

component by detection of coolant leakage. Coolant leakage results in deposits of white 

boric acid crystals and presence of moisture that can be observed by the naked eye. 

4. Detection of Aging Effects: Degradation of the component due to boric acid corrosion 

cannot occur without leakage of coolant that contains boric acid. Conditions leading to boric 

acid corrosion, such as crystal buildup and evidence of moisture, are readily detectable by visual inspection. The program delineated in NRC GL 88-05 includes guidelines for locating 

small leaks, conducting examinations, and performing engineering evaluations. Thus the 

use of the NRC GL 88-05 program will assure detection of leakage before the loss of the 

intended function of the component. 

5. Monitoring and Trending: The program delineated in NRC GL 88-05 provides for timely 

detection of leakage by observance of boric acid crystals during normal plant walkdowns 

and maintenance. 

6. Acceptance Criteria: Any detected leakage or crystal buildup requires corrective actions 

prior to continued service.

April 2001 XI M-39 NUREG-1 801
7. Corrective Actions: The leakage source and areas of general corrosion are located and 

corrective actions are implemented in conformance with the program proposed by NRC 

GL 88-05. The NRC GL 88-05 requires that corrective actions to prevent recurrences of 

degradation caused by boric acid leakage be included in the program implementation. 

These corrective actions include any modifications to be introduced in the present design or 

operating procedures of the plant that (a) reduce the probability of primary coolant leaks at 

locations where they may cause corrosion damage, and (b) entail the use of suitable 

corrosion resistant materials or the application of protective coatings or claddings. As 

discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, 

Appendix B, acceptable in addressing corrective actions. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing 

confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: Boric acid corrosion observed in nuclear power plants (NRC 

Information Notice [IN] 86-108 S3) may be classified into two types: (a) corrosion that 

increases the rate of leakage (e.g., corrosion of closure bolting or fasteners) and 

(b) corrosion that occurs some distance from the source of leakage. The guidance of NRC 

GL 88-05 is effective in managing the effects of boric acid corrosion on the intended 

function of reactor components. 

References 

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2000. 

NRC Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary 

Components in PWR Plants, U.S. Nuclear Regulatory Commission, March 17, 1988. 

NRC Information Notice 86-108 S3, Degradation of Reactor Coolant System Pressure 

Boundary Resulting from Boric Acid Corrosion, U.S. Nuclear Regulatory Commission, 

December 26, 1986; Supplement 1, April 20, 1987; Supplement 2, November 19, 1987; and 

Supplement 3, January 5, 1995. 

NUREG-1801 XI M-40 April 2001

I I
XI.M11 NICKEL-ALLOY NOZZLES AND PENETRATIONS

Program Description 

The program includes (a) primary water stress corrosion cracking (PWSCC) susceptibility 

assessment to identify susceptible components, (b) monitoring and control of reactor coolant 

water chemistry to mitigate PWSCC, and (c) inservice inspection (ISI) of reactor vessel head 

penetrations in accordance with the American Society of Mechanical Engineers (ASME) Code, 

Section Xl, Subsection IWB, Table IWB 2500-1 (1995 edition through the 1996 addenda) to 

monitor PWSCC and its effect on the intended function of the component. For susceptible penetrations and locations, the program includes an industry-wide, integrated, long-term inspection program based on the industry responses to NRC Generic Letter (GL) 97-01 

contained in the NEI letter dated December 11, 1998, from Dave Modeen to Gus Lainas, 

"Responses to NRC Requests for Additional Information (RAIs) on GL 97-01" and individual 

plant responses. Primary water chemistry is monitored and maintained in accordance with the 

Electric Power Research Institute (EPRI) guidelines in TR-1 05714 (Rev. 3, or later revisions or 

update) to minimize the potential of crack initiation and growth. 

Evaluation and Technical Basis 

1. Scope of Program: The program is focused on managing the effects of crack initiation and 

growth due to primary water stress corrosion cracking (PWSCC) of nickel-base alloys. The 

program includes ISI in accordance with ASME Subsection IWB, Table IWB 2500-1. For 

susceptible components and locations, the program includes an industry wide, integrated, long-term inspection program based on the industry responses to NRC GL 97-01 contained 

in the NEI letter dated December 11, 1998, from Dave Modeen to Gus Lainas, "Responses 

to NRC Requests for Additional Information (RAIs) on GL 97-01" and individual plant 

responses. Preventive measures are in accordance with EPRI guidelines in TR-1 05714 to 

mitigate PWSCC. An integrated cracking susceptibility assessment in accordance with 

industry susceptibility models and inspection results was performed in response to NRC GL 

97-01, to define the most susceptible plants and rank them in accordance with their 

susceptibility. The information is used by each plant to determine the proper timing of vessel 

head penetration examinations, either during the current license period or the period of 

license renewal, if necessary. The components and locations to be included in the long-term inspection program are those that currently have been identified as susceptible to PWSCC, and those that will become susceptible during the period of license renewal. Significant changes in the industry models, as future plants perform inspection, may require 

reassessment. 

2. Preventive Actions: Preventive measures to mitigate PWSCC are in accordance with 

EPRI guidelines in TR-105714. The program description and the evaluation and technical 

basis of monitoring and maintaining reactor water chemistry are presented in 

Chapter XI.M2, "Water Chemistry." 

3. Parameters MonitoredRnspected: The program monitors the effects of PWSCC on the 

intended function of the control rod drive (CRD) and other Alloy 600 head penetrations by detection and sizing of cracks and coolant leakage by ISI. In C-E-designed pressurized 

water reactors (PWRs), the CRD head penetration is called the control element drive (CED) 

head penetration.

April 2001 XI M-41 NUREG-1 801
4. Detection of Aging Effects: A review of the scope and schedule of the inspections, including the leakage detection system, based on NRC GL 97-01, assures detection of 

cracks before the loss of intended function of the components. 

The PWSCC susceptibility assessment was performed in response to NRC GL 97-01 

utilizing the most current industry susceptibility models that were based on material and 

operating parameters and inspection results to date, to rank plants in accordance with their 

susceptibility. This information is used to develop a plant-specific long-term inspection 

program, including schedule, scope and determination whether an augmented inspection 

program of nozzle penetration, including a combination of surface and volumetric 

examination, is necessary. Because the leakage through cracks in nozzles can be small, this aging management program (AMP), in accordance with NRC GL 97-01, recommends 

implementation of an enhanced leakage detection method for detecting small leaks during 

plant operation. 

5. Monitoring and Trending: An inspection schedule, in accordance with the integrated inspection program based on the NRC GL 97-01 susceptibility assessment, provides timely detection of cracks. Inspection results are used to update the susceptibility models. The 

frequency of subsequent inspections is based on the finding of the initial inspections and 

flaw evaluations performed with staff-approved crack growth rate models for nickel-alloys. 

6. Acceptance Criteria: Any indication detected is evaluated in accordance with ASME 

Section XI or other acceptable flaw evaluation criteria. To verify the adequacy of the long term inspection program and acceptance criteria, if there have been significant changes since the applicants response to NRC GL 97-01, the applicant either provides references to 

appropriate industry model revisions or provides updated information on crack initiation and 

crack growth data and models. 

7. Corrective Actions: Repair and replacement procedures are equivalent to those 

requirements in ASME Section XI. Repair is in conformance with IWB-4000 and 

replacement is in accordance with IWB-7000. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing corrective actions. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing the confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: Cracking of Alloy 600 has occurred in domestic and foreign PWRs 

(NRC Information Notice [IN] 90-10). Furthermore, ingress of demineralizer resins has also 

occurred in operating plants (NRC IN 96-11), the program relies upon monitoring and 

control of primary water chemistry to manage the effects of such excursions. An integrated susceptibility assessment and inspection program, based on the guidelines in NRC 

GL 97-01, is effective in managing the effect of PWSCC on the intended function of reactor 

vessel head penetrations. 

NUREG-1801 XI M-42 April 2001
References

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2000. 

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 1995 edition through the 1996 addenda, American 

Society of Mechanical Engineers, New York, NY. 

EPRI TR-1 05714, PWR Primary Water Chemistry Guidelines-Revision 3, Electric Power 

Research Institute, Palo Alto, CA, November 1995. 

Letter from David J. Modeen of Nuclear Energy Institute to Gus C. Lainais of Division of 

Engineering, Responses to NRC Requests for Additional Information on Generic Letter 

97-01, December 11, 1998. 

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 

Alloy 600, U.S. Nuclear Regulatory Commission, February 23, 1990. 

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.

April 2001 Xl M-43 NUREG-1801
XI.M12 THERMAL AGING EMBRIT'LEMENT OF CAST AUSTENITIC STAINLESS STEEL 

(CASS) 

Program Description 

The reactor coolant system components are inspected in accordance with the American Society 

of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section XI. This inspection 

is augmented to detect the effects of loss of fracture toughness due to thermal aging 

embrittlement of cast austenitic stainless steel (CASS) components. This aging management 

program (AMP) includes (a) determination of the susceptibility of CASS components to thermal 

aging embrittlement based on casting method, molybdenum content, and percent ferrite, and 

(b) for "potentially susceptible" components, as defined below, aging management is 

accomplished through either enhanced volumetric examination or plant- or component-specific 

flaw tolerance evaluation. Additional inspection or evaluations to demonstrate that the material 

has adequate fracture toughness are not required for components that are not susceptible to 

thermal aging embrittlement. 

For pump casings and valve bodies, based on the assessment documented in the letter dated 

May 19, 2000, from Christopher Grimes, Nuclear Regulatory Commission (NRC), to Douglas 

Waiters, Nuclear Energy Institute (NEI), screening for susceptibility to thermal aging is not 

required. The existing ASME Section Xl inspection requirements, including the alternative 

requirements of ASME Code Case N-481 for pump casings, are adequate for all pump casings 

and valve bodies. 

Evaluation and Technical Basis 

1. Scope of Program: The program includes screening criteria to determine which CASS 

components are potentially susceptible to thermal aging embrittlement and require 

augmented inspection. The screening criteria are applicable to all primary pressure 

boundary and reactor vessel internal components constructed from SA-351 Grades CF3, 

CF3A, CF8, CF8A, CF3M, CF3MA, CF8M, with service conditions above 2500C (4820F). 

The screening criteria for susceptibility to thermal aging embrittlement are not applicable to 

niobium-containing steels; such steels require evaluation on a case-by-case basis. For 

potentially susceptible components, aging management is accomplished either through 

volumetric examination or plant- or component-specific flaw tolerance evaluation. 

Based on the criteria set forth in the May 19, 2000, NRC letter, the susceptibility to thermal 

aging embrittlement of CASS components is determined in terms of casting method, 

molybdenum content, and ferrite content. For low-molybdenum content (0.5 wt.% max.) 

steels, only static-cast steels with >20% ferrite are potentially susceptible to thermal 

embrittlement. Static-cast low-molybdenum steels with •_20% ferrite and all centrifugal-cast 

low-molybdenum steels are not susceptible. For high-molybdenum content (2.0 to 3.0 wt.%) 

steels, static-cast steels with >14% ferrite and centrifugal-cast steels with >20% ferrite are 

potentially susceptible to thermal embrittlement. Static-cast high-molybdenum steels with 

•14% ferrite and centrifugal-cast high-molybdenum steels with •!20% ferrite are not 

susceptible. In the susceptibility screening method, ferrite content is calculated by using the 

Hull's equivalent factors (described in NUREG/CR-4513, Rev. 1) or a method producing an 

equivalent level of accuracy (±+6% deviation between measured and calculated values). A 

fracture toughness value of 255 kJ/m2 (1,450 in.-lb/in. 2) at a crack depth of 2.5 mm (0.1 in.) 

is used to differentiate between CASS materials that are nonsusceptible and potentially 

susceptible to thermal aging embrittlement. Extensive research data indicate that for 

NUREG-1 801 XI M-44 April 2001
nonsusceptible CASS materials, the saturated lower-bound fracture toughness is greater 

than 255 kJ/m2 (NUREG/CR-4513, Rev. 1). 

For pump casings and valve bodies, screening for susceptibility to thermal aging 

embrittlement is not required. The staff's conservative bounding integrity analysis shows 

that thermally aged CASS valve bodies and pump casings are resistant to failure. For all 

pump casings and valve bodies greater than nominal pipe size (NPS) 4 in., the existing 

ASME Section Xl inspection requirements, including the alternative requirements of ASME 

Code Case N-481 for pump casings, are adequate. The ASME Section XI, Subsection IWB, 

requires only surface examination of valve bodies less than NPS 4 in. For valve bodies less 

than NPS 4 in., the adequacy of inservice inspection (ISI) according to ASME Section XI 

has been demonstrated by a NRC-performed bounding integrity analysis (see letter from 

Christopher Grimes). 

2. Preventive Actions: The program consists of evaluation and inspection and provides no 

guidance on methods to mitigate thermal aging embrittlement. 

3. Parameters Monitored/Inspected: The AMP monitors the effects of loss of fracture 

toughness on the intended function of the component by identifying the CASS materials that 

are susceptible to thermal aging embrittlement. For potentially susceptible materials, the 

program consists of either enhanced volumetric examination to detect and size cracks or 

plant- or component-specific flaw tolerance evaluation. (Loss of fracture toughness is of 

consequence only if cracks exist.) 

4. Detection of Aging Effects: For pump casings and valve bodies and "not susceptible" 

piping, no additional inspection or evaluations are required to demonstrate that the material 

has adequate fracture toughness. For "potentially susceptible" piping, because the base 

metal does not receive periodic inspection per ASME Section Xl, the CASS AMP provides 

for volumetric examination of the base metal, with the scope of the inspection covering the 

portions determined to be limiting from the standpoint of applied stress, operating time, and 

environmental considerations. Examination methods that meet the criteria of the ASME 

Section Xl, Appendix VIII, are acceptable. Alternatively, a plant- or component-specific flaw 

tolerance evaluation, using specific geometry and stress information, can be used to 

demonstrate that the thermally-embrittled material has adequate toughness. 

5. Monitoring and Trending: Inspection schedules in accordance with IWB-2400 or IWC

2400 and reliable examination methods provide timely detection of cracks. 

6. Acceptance Criteria: Flaws detected in CASS components are evaluated in accordance 

with the applicable procedures of IWB-3500 or IWC-3500. Flaw tolerance evaluation for 

components with ferrite content up to 25% is performed according to the principles 

associated with IWB-3640 procedures for submerged arc welds (SAW), disregarding the 

Code restriction of 20% ferrite in IWB-3641 (b)(1). Extensive research data indicate that the 

lower-bound fracture toughness of thermally aged CASS materials with up to 25% ferrite is 

similar to that for SAWs with up to 20% ferrite (Lee et al., 1997). Flaw evaluation for piping 

with >25% ferrite is performed on a case-by-case basis by using fracture toughness data 

provided by the applicant. 

7. Corrective Actions: Repair is in conformance with IWA-4000 and IWB-4000 or IWC, and 

replacement is in accordance with IWA-7000 and IWB-7000 or IWC-7000. As discussed in 

the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable in addressing corrective actions.

April 2001 Xl M-45 NUREG-1801
8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing the confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: The proposed AMP was developed by using research data 

obtained on both laboratory-aged and service-aged materials. Based on this information, the effects of thermal aging embrittlement on the intended function of CASS components 

are effectively managed. 

References 

ASME Section Xl, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 1995 edition through the 1996 addenda, American 

Society of Mechanical Engineers, New York, NY. 

Lee, S., Kuo, P. T., Wichman, K., and Chopra, 0., Flaw Evaluation of Thermally Aged Cast 

Stainless Steel in Light-Water Reactor Applications, Int. J. Pres. Ves. and Piping, 72, 

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. 

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-1 801 X1 M-46 April 2001
XI.M13 THERMAL AGING AND NEUTRON IRRADIATION EMBRI'BLEMENT OF CAST 

AUSTENITIC STAINLESS STEEL (CASS) 

Program Description 

The reactor vessel internals receive a visual inspection in accordance with the American 

Society of Mechanical Engineers (ASME) Code Section XI, Subsection IWB, Category B-N-3. 

This inspection is augmented to detect the effects of loss of fracture toughness due to thermal 

aging, neutron irradiation embrittlement and void swelling of cast austenitic stainless steel 

(CASS) reactor vessel internals. This aging management program (AMP) includes (a) identification of susceptible components determined to be limiting from the standpoint of 

thermal aging susceptibility (i.e., ferrite and molybdenum contents, casting process, and 

operating temperature) and/or neutron irradiation embrittlement (neutron fluence), and (b) for 

each "potentially susceptible" component, aging management is accomplished through either a supplemental examination of the affected component based on the neutron fluence to which the 

component has been exposed as part of the applicant's 10-year inservice inspection (ISI) 

program during the license renewal term, or a component-specific evaluation to determine its 

susceptibility to loss of fracture toughness. 

Evaluation and Technical Basis 

1. Scope of Program: The program provides screening criteria to determine the susceptibility of CASS components to thermal aging on the basis of casting method, molybdenum 

content, and percent ferrite. The screening criteria are applicable to all primary pressure boundary and reactor vessel internal components constructed from SA-351 Grades CF3, CF3A, CF8, CFA, CF3M, CF3MA, CF8M, with service conditions above 2500C (482°F). The screening criteria for susceptibility to thermal aging embrittlement are not applicable to 

niobium-containing steels; such steels require evaluation on a case-by-case basis. For "potentially susceptible" components, the program provides for the consideration of the 

synergistic loss of fracture toughness due to neutron embrittlement and thermal aging embrittlement. For each such component, an applicant can implement either (a) a 

supplemental examination of the affected component as part of a 10-year ISI program during the license renewal term, or (b) a component-specific evaluation to determine the 

component's susceptibility to loss of fracture toughness. 

Based on the criteria set forth in the May 19, 2000, Nuclear Regulatory Commission (NRC) letter, the susceptibility to thermal aging embrittlement of CASS components is determined 

in terms of casting method, molybdenum content, and ferrite content. For low-molybdenum content (0.5 wt.% max.) steels, only static-cast steels with >20% ferrite are potentially susceptible to thermal embrittlement. Static-cast low-molybdenum steels with <20% ferrite 

and all centrifugal-cast low-molybdenum steels are not susceptible. For high-molybdenum 

content (2.0 to 3.0 wt.%) steels, static-cast steels with >14% ferrite and centrifugal-cast steels with >20% ferrite are potentially susceptible to thermal embrittlement. Static-cast 

high-molybdenum steels with _•14% ferrite and centrifugal-cast high-molybdenum steels with 

•_20% ferrite are not susceptible. In the susceptibility screening method, ferrite content is 

calculated by using the Hull's equivalent factors (described in NUREG/CR-4513, Rev. 1) or 

a method producing an equivalent level of accuracy (_+6% deviation between measured and 

calculated values). A fracture toughness value of 255 kJ/m 2 (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 

nonsusceptible and potentially susceptible to thermal aging embrittlement. Extensive

April 2001 Xl M-47 NUREG-1 801
research data indicate that for nonsusceptible CASS materials, the saturated lower-bound 

fracture toughness is greater than 255 kJ/m2 (NUREG/CR-4513, Rev. 1). 

2. Preventive Actions: The program consists of evaluation and inspection and provides no 

guidance on methods to mitigate thermal aging, neutron irradiation embrittlement or void 

swelling. 

3. Parameters Monitored/Inspected: The program specifics depend on the neutron fluence 

and thermal embrittlement susceptibility of the component. The AMP monitors the effects of 

loss of fracture toughness on the intended function of the component by identifying the 

CASS materials that either have a neutron fluence of greater than 1017 n/cm 2 (E>1 MeV) or 

are determined to be susceptible to thermal aging embrittlement. For such materials, the 

program consists of either supplemental examination of the affected component based on 

the neutron fluence to which the component has been exposed, or component-specific 

evaluation to determine the component's susceptibility to loss of fracture toughness. 

4. Detection of Aging Effects: For all CASS components that have a neutron fluence of 

greater than 1017 n/cm2 (E>1 MeV) or are determined to be susceptible to thermal 

embrittlement, the 10-year ISI program during the renewal period includes a supplemental 

inspection covering portions of the susceptible components determined to be limiting from 

the standpoint of thermal aging susceptibility (i.e., ferrite and molybdenum contents, casting 

process, and operating temperature), neutron fluence, and cracking susceptibility 

(i.e., applied stress, operating temperature, and environmental conditions). The inspection 

technique is capable of detecting the critical flaw size with adequate margin. The critical 

flaw size is determined based on the service loading condition and service-degraded 

material properties. One example of a supplemental examination is enhancement of the 

visual VT-1 examination of Section XI IWA-221 0. A description of such an enhanced visual 

VT-1 examination could include the ability to achieve a 0.0005-in. resolution, with the 

conditions (e.g., lighting and surface cleanliness) of the inservice examination bounded by 

those used to demonstrate the resolution of the inspection technique. Alternatively, the 

applicant may perform a component-specific evaluation, including a mechanical loading 

assessment to determine the maximum tensile loading on the component during ASME 

Code Level A, B, C, and D conditions. If the loading is compressive or low enough (<5 ksi) 

to preclude fracture, then supplemental inspection of the component is not required. Failure 

to meet this criterion requires continued use of the supplemental inspection program. For 

each CASS component that has been subjected to a neutron fluence of less than 

1017 n/cm2 (E>1 MeV) and is potentially susceptible to thermal aging, the supplement 

inspection program applies; otherwise, the existing ASME Section XI inspection 

requirements are adequate if the components are not susceptible to thermal aging 

embrittlement. 

5. Monitoring and Trending: Inspections scheduled in accordance with IWB-2400 and 

reliable examination methods provide timely detection of cracks. 

6. Acceptance Criteria: Flaws detected in CASS components are evaluated in accordance 

with the applicable procedures of IWB-3500. Flaw tolerance evaluation for components with 

ferrite content up to 25% is performed according to the principles associated with IWB-3640 

procedures for submerged arc welds (SAW), disregarding the Code restriction of 20% 

ferrite in IWB-3641 (b)(1). Extensive research data indicate that the lower-bound 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 

NUREG-1801 XI M-48 April 2001
>25% ferrite is performed on a case-by-case basis by using fracture toughness data 

provided by the applicant. 

7. Corrective Actions: Repair is in conformance with IWA-4000 and IWB-4000, and 

replacement is in accordance with IWA-7000 and IWB-7000. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in 

addressing corrective actions. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing the confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: The proposed AMP was developed by using research data 

obtained on both laboratory-aged and service-aged materials. Based on this information, the effects of thermal aging embrittlement on the intended function of CASS components 

are effectively managed. 

References 

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME Boiler and Pressure Vessel Code, 1995 edition through the 1996 addenda, American 

Society of Mechanical Engineers, New York, NY. 

Lee, S., Kuo, P. T., Wichman, K., and Chopra, 0., Flaw Evaluation of Thermally Aged Cast 

Stainless Steel in Light-Water Reactor Applications, Int. J. Pres. Ves. and Piping, 72, 

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. 

NUREG/CR-4513, Rev. 1, Estimation of Fracture Toughness of Cast Stainless Steels during ThermalAging in LWR Systems, U.S. Nuclear Regulatory Commission, August 1994.

April 2001 Xl M-49 NUREG-1801
XI.M14 LOOSE PART MONITORING

Program Description 

The program relies on an inservice monitoring program to detect and monitor loose parts in 

light-water reactor (LWR) power plants. This inservice loose part monitoring (LPM) program is 

based on the recommendations from the American Society of Mechanical Engineers operation and maintenance standards and guides (ASME OM-S/G)-1 997, Part 12, "Loose Part Monitoring 

in Light-Water Reactor Power Plants." 

Evaluation and Technical Basis 

1. Scope of Program: The program includes measures to monitor and detect metallic loose 

parts by using transient signals analysis on acoustic data generated due to loose parts impact. The program is applicable, but not necessarily limited to, the reactor vessel and 

primary coolant systems in pressurized water reactors (PWRs) and the reactor recirculation 

system in boiling water reactors (BWRs). The detection and monitoring system includes a 

set of accelerometers installed in the vicinity of regions where loose parts impact is likely to 

occur. The system incorporates the capability of automatic annunciation (audible and 

visual), audio monitoring, automatic and manual signal recording, and acoustic signal analysis/evaluation. Measures for personnel radiation exposure and safety are included as 

part of the requirements of the LPM system. The objective of the LPM program is to provide 

early indication of component degradation. 

2. Preventive Actions: The aging management program (AMP) is a monitoring/detection 

program that provides early indication and detection of the onset of aging degradation. It 

does not rely on preventive actions. 

3. Parameters Monitored/Inspected: The program relies on the use of transient acoustic 

signals to provide information on the occurrence of metallic loose part impact. Reactor 

coolant system (RCS) background noise may mask the noise generated due to loose part impact. These background noises may arise from sources such as coolant flow and 

mechanically and hydraulically generated vibrations. To differentiate loose part impact noise 

from background noise, ASME OM-S/G-1 997, Part 12, recommends that the monitoring 

system sensitivity be set on the basis of the background noise and that maximum sensitivity be accomplished that is consistent with an acceptable false alarm rate arising from the 

background noise. 

4. Detection of Aging Effects: Impact signals contain significant information on the size of 

the impacting object, the impact force and energy, and the composition and shape of both 

the component struck and the impacting object. In general, the magnitude of the impact signal increases with the impact mass and impact velocity. However, the frequency 

response increases with increasing velocity and decreasing mass. These data may be used 

to extract information on possible loose part impact and differentiation from background 

noise. 

5. Monitoring and Trending: The impact signals, collected data, frequency, and 

characteristics are recorded, monitored, and evaluated to locate and identify the source and 

cause of the acoustic signals for the purpose of determining the need and urgency for a 

detailed inspection and examination of the suspected reactor vessel internals components. 

These activities are performed and associated personnel are qualified in accordance with 

NUREG-1 801 XI M-50 April 2001

I I
site controlled procedures and processes, as indicated by vendor, industry, or regulatory 

guidance documents. 

6. Acceptance Criteria: The LPM alarms that suggest metallic impacts are further evaluated 

to verify LPM operability and to determine the location of the impact, the impact energy, and 

mass. Plant process data are reviewed for anomalous behavior, and diagnostic results are 

assessed by plant personnel. 

7. Corrective Actions: If LPM diagnostics indicate the presence of loose parts, then 

corrective actions are taken. In some cases, the results of the diagnostic may indicate the 

signal is due to a change in the plant background characteristics and not due to the 

presence of loose parts. In such cases, the LPM alarm rates may in time become so high as 

to be unacceptable in practice. Adjustment of the alarm threshold (setpoints) is allowed. 

However, the reason for the change in background is to be investigated and understood, 

and the change is to be documented. As discussed in the appendix to this report, the staff 

finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing corrective 

actions. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing 

the confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: The loose part monitoring program is extensively and effectively 

used by the industry. The program has been developed and published as a standard in the 

ASME "Standards and Guides for Operation and Maintenance of Nuclear Power Plants," 

Part 12, an American National Standard. Part 12 was developed on the basis of knowledge gained from operating experience and research conducted since the Nuclear Regulatory 

Commission (NRC) issued Regulatory Guide (RG) 1.133 in May 1981. 

References 

ANSI S2.11-1969, American National Standard for the Selection of Calibrations and Tests for 

Electrical Transducers Used for Monitoring Shock and Vibrations, American National 

Standards Institute, Washington, DC, 1969. 

ASME OM-S/G-1 997, Part 12, Loose Part Monitoring in Light-Water Reactor Power Plants, 

American Society of Mechanical Engineers, New York, NY, 1997. 

NRC Regulatory Guide 1.133, Rev. 1, Loose Part Detection Program for the Primary System of Light Water Cooled Reactors, U.S. Nuclear Regulatory Commission, 1981.

April 2001 XI M-51 NUREG-1 801
XI.M15 NEUTRON NOISE MONITORING

Program Description 

The program relies on monitoring the excore neutron detector signals due to core motion to 

detect and monitor significant loss of axial preload at the core support barrel's upper support flange in pressurized water reactors (PWRs). This inservice monitoring program is based on the 

recommendations from the American Society of Mechanical Engineers operation and 

maintenance standards and guides (ASME OM-S/G)-1 997, Part 5, "Inservice Monitoring of 

Core Support Barrel Axial Preload in Pressurized Water Reactors Power Plants." 

Evaluation and Technical Basis 

1. Scope of Program: The program includes measures to monitor and detect loss of axial 

preload (loss of axial restraint) at the core support barrel's upper support flange in PWRs. 

The loss of axial restraint may arise from long-term changes resulting from abnormal wear 

at the reactor vessel core barrel mating surface or short-term changes due to improper installation of the reactor internals. The program also includes guidelines for further data 

acquisition that may be needed to define future plant operation and/or program plans in 

order to maintain the capability of the structure/components to perform the intended 

function. 

2. Preventive Actions: The aging management program (AMP) is a monitoring/detection 

program that provides early indication and detection of the onset of aging degradation of the 

core support barrel holddown mechanism prior to a scheduled shutdown, thus reducing 

outage time and avoiding potential damage to the core support barrel and fuel assemblies. 

The AMP does not rely on preventive actions. 

3. Parameters Monitored/Inspected: The program relies on the use of excore neutron 

detector signals to provide information on the conditions of the axial preload. The excore 

neutron flux signal is composed of a steady state, direct current (DC), component that 

arises from the neutron flux produced by the power operation of the reactor, as well as a 

fluctuating (noise-like) component. This fluctuating signal arises from the core reactivity changes due to lateral core motion from the loss of axial preload. This core motion is mainly the result of beam mode vibration of the core support barrel. Despite the fact that this beam 

mode vibration provides only a very weak neutron noise source, it may be reliably detected 

and identified through Fourier Analysis of the fluctuating signal component of the excore 

neutron flux signal. This signal component has the characteristics of having 180-degree shifts and a high degree of coherence between signals obtained from pairs of excore 

neutron detectors that are positioned on diametrically opposite sides of the core. The 

neutron noise signals are characterized by parameters, which include the auto correlation, 

cross correlation, coherence, and phase. These parameters are to be monitored and 

evaluated. 

4. Detection of Aging Effects: Flow-induced vibration of the core support barrel will change the thickness of the downcomer annulus (water gap). This variation in the thickness will give rise to fluctuating changes in the neutron flux, as monitored by the excore neutron 

detectors. The natural frequencies and the amplitudes of the vibratory motion of the core 

barrel are related to the effective axial preload at the upper support flange of the core 

support barrel. Monitoring of the neutron noise signal obtained with the neutron flux 

detectors located around the external periphery of the reactor vessel provides detection of 

anomalous vibrational motion of the core support barrel, and hence significant loss of the 

NUREG-1 801 XI M-52 April 2001

I I
axial preload. Decrease in the axial preload leads to decreases in the core support barrel beam mode frequency and an increase in the magnitude of the noise signal. The overall effect of a decrease in the axial preload is to shift the neutron noise power spectrum toward 

larger amplitudes for the lower frequency region. 

5. Monitoring and Trending: The neutron noise random fluctuation in the signals from the 

excore detectors are monitored, recorded, and analyzed to identify changes in the beam mode natural frequency of the core support barrel and its direction of motion for the purpose of a timely determination of the need and urgency for a detailed inspection and examination of the reactor vessel internals hold-down mechanism and mating component surfaces. These activities and analytical methodology are performed and associated personnel are qualified in accordance with site-controlled procedures and processes as indicated by vendor, industry, or regulatory guidance documents. 

The neutron noise monitoring program has three separate phases: a baseline phase, a surveillance phase, and a diagnostic phase. The baseline phase establishes the database 

to be used as a reference for developing limits and trends in the surveillance phase and to support data evaluation and interpretation in the diagnostic phase. During the baseline phase, data on the time history and DC level of each neutron flux detector and each cross

core detector pair are obtained. From this database, the characteristic amplitudes and frequencies of the core barrel motion are extracted. The wide and narrow frequency bands with their associated normalized root mean square (NRMS) values are established. The ASME-OMS/G-1 997, Part 5, recommends collecting the baseline data during the first fuel cycle that the neutron noise monitoring program is applied to an already operating plant. Whenever significant changes takes place for the core, reactor internals, or operating conditions, then additional baseline data is obtained. 

In the surveillance phase, routine neutron noise monitoring of normal plant operations is performed over the life of the plant. The DC level and data for frequency analysis of each detector and two pair of cross-core detectors, may be collected. Comparisons of the measured amplitude and frequency data, with limits established from the baseline data, are made. In using neutron noise monitoring, accounts are taken of the effect of core burn-up, decreasing boron concentration, changes in fuel management, and in-core contact with the reactor vessel mechanical snubbers, which may affect the neutron noise signatures. Proper allowances for these factors during the baseline and surveillance phases will help toward detecting loss of axial preload before the core barrel becomes sufficiently free to wear against the reactor vessel and will also reduce the need to invoke the diagnostic phase. 

If the diagnostic phase becomes necessary, then evaluations are carried out to establish whether any deviations from the baseline data detected during the surveillance phase arises from core barrel motion due to loss of axial preload. The need and frequency of additional 

data collection on the time history and DC level of each neutron flux detector and each 

cross-core detector pair collection are guided by the results of these evaluations. 

6. Acceptance Criteria: If evaluation of the baseline data indicates normal operation for the applicable structure/component then the surveillance phase may commence. If evaluation indicates anomalous behavior, then the monitoring program enters the diagnostic phase. During the surveillance phase, if deviations from the baseline fall within predetermined acceptable limits, then the surveillance will continue. Otherwise, the diagnostic phase will 

commence.

April 2001 Xl M-53 NUREG-1 801
7. Corrective Actions: Initial results from the diagnostic phase of the program may be used 

to determine whether there is a need to increase the minimum frequency with which the 

surveillance data are acquired. In addition, if necessary, corrective actions may be taken to 

change the type of data acquisition and analysis from that previously recommended for the 

surveillance part of the program. The data trends may be established to guide further data 

acquisition that may be needed to define future plant operation and/or program plans. As 

discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, 

Appendix B, acceptable in addressing corrective actions. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing 

the confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: The neutron noise monitoring program and procedures were 

developed by the industry and published as a guide in ASME OM-S/G-1 997, Part 5, an 

American National Standard. This monitoring program and procedures have been effective 

in limited industry use for monitoring and detecting loss of core support barrel axial preload 

in PWR power plants. 

References 

ASME OM-S/G-1997, Part 5, Inservice Monitoring of Core Support Barrel Axial Preload in 

Pressurized Water Reactor Power Plants, American Society of Mechanical Engineers, 

New York, NY, 1997.

NUREG-1801 Xl M-54 April 2001

I I
XI.M16 PWR VESSEL INTERNALS

Program Description 

The program includes (a) augmentation of the inservice inspection (ISI) in accordance with the 

American Society of Mechanical Engineers (ASME) Code, Section Xl, Subsection IWB, 

Table IWB 2500-1 (1995 edition through the 1996 addenda) for certain susceptible or limiting 

components or locations, and (b) monitoring and control of reactor coolant water chemistry in 

accordance with the Electric Power Research Institute (EPRI) guidelines in TR-1 05714 to 

ensure the long-term integrity and safe operation of pressurized water reactor (PWR) vessel 

internal components. The ASME Section Xl ISI is augmented with enhancing the VT-1 

examinations for non-bolted components for example, to include the ability to achieve a 0.0005

inch resolution. The inspection methods for bolted components are to be demonstrated for 

detecting cracks between the bolt head and the shank. 

Evaluation and Technical Basis 

1. Scope of Program: The program is focused on managing the effects of crack initiation and 

growth due to stress corrosion cracking (SCC) or irradiation assisted stress corrosion 

cracking (IASCC), and loss of fracture toughness due to neutron irradiation embrittlement or 

void swelling. The program contains preventive measures to mitigate SCC or IASCC; ISI to 

monitor the effects of cracking on the intended function of the components; and repair and/or replacement as needed to maintain the ability to perform the intended function. Loss 

of fracture toughness is of consequence only if cracks exist. Cracking is expected to initiate 

at the surface and is detectable by augmented inspection. 

The program provides guidelines to assure safety function integrity of the subject safety related reactor pressure vessel internal components, both non-bolted and bolted 

components. The program consists of the following elements: (a) identify the most 

susceptible or limiting items, (b) develop appropriate inspection techniques to permit detection and characterizing of the feature (cracks) of interest and demonstrate the 

effectiveness of the proposed technique, and (c) implement the inspection during the 

license renewal term. For example, appropriate inspection techniques may include 

enhancing visual VT-1 examinations for non-bolted components and demonstrated 

acceptable inspection methods for bolted components. 

2. Preventive Actions: The requirements of ASME Section XI, Subsection IWB, provide guidance on detection, but do not provide guidance on methods to mitigate cracking. Maintaining high water purity reduces susceptibility to cracking due to SCC. Reactor coolant 

water chemistry is monitored and maintained in accordance with the EPRI guidelines in 

TR-1 05714. The program description and evaluation and technical basis of monitoring and 

maintaining reactor water chemistry are presented in Chapter XI.M2, 'Water Chemistry." 

3. Parameters Monitored/Inspected: The program monitors the effects of cracking on the 

intended function of the component by detection and sizing of cracks by augmentation of ISI 

in accordance with the requirements of the ASME Code, Section XI, Table IWB 2500-1. 

4. Detection of Aging Effects: The extent and schedule of the inspection and test techniques prescribed by the aging management program are designed to maintain structural integrity and ensure that aging effects will be discovered and repaired before the loss of intended 

function. Inspection can reveal crack initiation and growth. Vessel internal components are 

inspected in accordance with the requirements of ASME Section XI, Subsection IWB,

April 2001 Xl M-55 NUREG-1801
examination category B-N-3 for all accessible surfaces of reactor core support structure that 

can be removed from the vessel. The ASME Section Xl inspection 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. 

However, visual VT-3 examination is to be augmented to detect tight or fine cracks. Also, 

historically the VT-3 examinations have not identified bolt cracking because cracking occurs 

at the juncture of the bolt head and shank, which is not accessible for visual inspection. Creviced and other inaccessible regions are difficult to inspect visually. This AMP 

recommends more stringent inspections such as enhanced visual VT-1 examinations or 

ultrasonic methods of volumetric inspection, for certain selected components and locations. 

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. For non-bolted components, augmented ISI may include 

enhancement of the visual VT-1 examination of Section Xl IWA-221 0. A description of such 

an enhanced visual VT-1 examination should include the ability to achieve a 0.0005-in. 

resolution, with the conditions (e.g., lighting and surface cleanliness) of the inservice 

examination bounded by those used to demonstrate the resolution of the inspection technique. For bolted components, augmented ISI is to include other demonstrated 

acceptable inspection methods to detect cracks between the bolt head and the shank. 

Alternatively, the applicant may perform a component-specific evaluation, including a 

mechanical loading assessment to determine the maximum tensile loading on the 

component during ASME Code Level A, B, C, and D conditions. If the loading is 

compressive or low enough (<5 ksi) to preclude fracture, then supplemental inspection of 

the component is not required. Failure to meet this criterion requires continued use of the 

augmented inspection methods. 

5. Monitoring and Trending: Inspection schedules in accordance with IWB-2400, 

assessment of susceptible or limiting components or locations, and reliable examination 

methods provide timely detection of cracks. The scope of examination expansion and re

inspection beyond the baseline inspection are required if flaws are detected. 

6. Acceptance Criteria: Any indication or relevant condition of degradation is evaluated in 

accordance with IWB-31 00 by comparing ISI results with the acceptance standards of IWB

3400 and IWB-3500. 

7. Corrective Actions: Repair and replacement procedures are equivalent to those 

requirements in ASME Section Xi. Repair is in conformance with IWB-4000 and 

replacement occurs according to IWB-7000. As discussed in the appendix to this report, the 

staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing 

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 50, Appendix B. As discussed in the appendix to this report, the 

staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing the 

confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

NUREG-1801 XI M-56 April 2001

I I
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, or 3 components and their integral attachments in light-water 

cooled power plants. 

In PWRs, stainless steel components have generally not been found to be affected by SCC 

because of low dissolved oxygen levels and control of primary water chemistry. However, 

the potential for SCC exists due to inadvertent introduction of contaminants into the primary 

coolant system from unacceptable levels of contaminants in the boric acid; introduction 

through the free surface of the spent fuel pool, which can be a natural collector of airborne 

contaminants (NRC IN 84-18); introduction of relatively high levels of oxygen during shutdown, or from aggressive chemistries that may develop in creviced regions. Cracking 

has occurred in SS baffle former bolts in a number of foreign plants (NRC IN 98-11) and 

has now been observed in plants in the United States. 

References 

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 1995 edition through the 1996 addenda, American 

Society of Mechanical Engineers, New York, NY. 

EPRI TR-1 05714, PWR primaty Water Chemistry Guidelines-Revision 3, Electric Power 

Research Institute, Palo Alto, CA, November 1995. 

NRC Information Notice 84-18, Stress Corrosion Cracking in PWR Systems, March 7, 1984. 

NRC Information Notice 98-11, Cracking of Reactor Vessel Internal Baffle Former Bolts in 

Foreign Plants, March 25, 1998.

April 2001 XI M-57 NUREG-1801
XI.M17 FLOW-ACCELERATED CORROSION

Program Description 

The program relies on implementation of the Electric Power Research Institute (EPRI) guidelines in the Nuclear Safety Analysis Center (NSAC)-202L-R2 for an effective 

flow-accelerated corrosion (FAC) program. The program includes performing (a) an analysis to 

determine critical locations, (b) limited baseline inspections to determine the extent of thinning at these locations, and (c) follow-up inspections to confirm the predictions, or repairing or 

replacing components as necessary. 

Evaluation and Technical Basis 

1. Scope of Program: The FAC program, described by the EPRI guidelines in 

NSAC-202L-R2, includes procedures or administrative controls to assure that the structural 

integrity of all carbon steel lines containing high-energy fluids (two phase as well as single phase) is maintained. Valve bodies retaining pressure in these high-energy systems are 

also covered by the program. The FAC program was originally outlined in NUREG-1344 and 

was further described through the Nuclear Regulatory Commission (NRC) Generic Letter 

(GL) 89-08. A program implemented in accordance with the EPRI guidelines predicts, detects, and monitors FAC in plant piping and other components, such as valve bodies, elbows and expanders. Such a program includes the following recommendations: 

(a) conducting an analysis to determine critical locations; (b) performing limited baseline 

inspections to determine the extent of thinning at these locations; and (cý performing follow

up inspections to confirm the predictions, or repairing or replacing components as 

necessary. The NSAC-202L-R2 (April 1999) provides general guidelines for the FAC 

program. To ensure that all the aging effects caused by FAC are properly managed, the 

program includes the use of a predictive code, such as CHECWORKS, that uses the 

implementation guidance of NSAC-202L-R2 to satisfy the criteria specified in 10 CFR Part 

50, Appendix B, criteria for development of procedures and control of special processes. 

2. Preventive Actions: The FAC program is an analysis, inspection, and verification program; thus, there is no preventive action. However, it is noted that monitoring of water chemistry to 

control pH and dissolved oxygen content, and selection of appropriate piping material, 

geometry, and hydrodynamic conditions, are effective in reducing FAC. 

3. Parameters Monitored/Inspected: The aging management program (AMP) monitors the 

effects of FAC on the intended function of piping and components by measuring wall 

thickness. 

4. Detection of Aging Effects: Degradation of piping and components occurs by wall 

thinning. The inspection program delineated in NSAC-202L consists of identification of 

susceptible locations as indicated by operating conditions or special considerations. 

Ultrasonic and radiographic testing is used to detect wall thinning. The extent and schedule 

of the inspections assure detection of wall thinning before the loss of intended function. 

5. Monitoring and Trending: CHECWORKS or a similar predictive code is used to predict component degradation in the systems conducive to FAC, as indicated by specific plant data, including material, hydrodynamic, and operating conditions. CHECWORKS is 

acceptable because it provides a bounding analysis for FAC. CHECWORKS was developed and benchmarked by using data obtained from many plants. The inspection schedule 

developed by the licensee on the basis of the results of such a predictive code provides

NUREG-1801 XI M-58 April 2001
reasonable assurance that structural integrity will be maintained between inspections. If 

degradation is detected such that the wall thickness is less than the minimum predicted 

thickness, additional examinations are performed in adjacent areas to bound the thinning. 

6. Acceptance Criteria: Inspection results are used as input to 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 thickness before the next scheduled 

outage, the component is to be repaired, replaced, or reevaluated. 

7. Corrective Actions: Prior to service, reevaluate, repair, or replace components for which 

the acceptance criteria are not satisfied. Longer term corrective actions could consist of 

adjustment of operating parameters or selection of materials resistant to FAC. As discussed 

in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, 

Appendix B, acceptable in addressing corrective actions. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing 

the confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: Wall-thinning problems in single-phase systems have occurred in 

feedwater and condensate systems (NRC IE Bulletin No. 87-01; NRC Information Notices 

[INs] 81-28, 92-35, 95-11) and in two-phase piping in extraction steam lines (NRC 

INs 89-53, 97-84) and moisture separation reheater and feedwater heater drains (NRC 

INs 89-53, 91-18, 93-21, 97-84). Operating experience shows that the present program, 

when properly implemented, is effective in managing FAC in high-energy carbon steel 

piping and components. 

References 

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 81-28, Failure of Rockwell-Edward Main Steam Isolation Valves, 

U.S. Nuclear Regulatory Commission, September 3, 1981. 

NRC Information Notice 89-53, Rupture of Extraction Steam Line on High Pressure Turbine, 

U.S. Nuclear Regulatory Commission, June 13, 1989. 

NRC Information Notice 91-18, High-Energy Piping Failures Caused by Wall Thinning, 

U.S. Nuclear Regulatory Commission, March 12, 1991. 

NRC Information Notice 91-18, Supplement 1, High-Energy Piping Failures Caused by Wall 

Thinning, U.S. Nuclear Regulatory Commission, December 18, 1991.

April 2001 XI M-59 NUREG-1 801
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 Flow

Accelerated Corrosion, U.S. Nuclear Regulatory Commission, December 11, 1997. 

NSAC-202L-R2, Recommendations for an Effective Flow Accelerated Corrosion Program, 

Electric Power Research Institute, Palo Alto, CA, April 8, 1999. 

NUREG-1 344, Erosion/Corrosion-Induced Pipe Wall Thinning in U.S. Nuclear Power Plants, 

P. C. Wu, U.S. Nuclear Regulatory Commission, April 1989.

NUREG-1801 Xl M-60 April 2001
XI.M18 BOLTING INTEGRITY

Program Description 

The program relies on recommendations for a comprehensive bolting integrity program, as 

delineated in NUREG-1339, and industry recommendations, as delineated in the Electric Power 

Research Institute (EPRI) NP-5769, with the exceptions noted in NUREG-1339 for safety related bolting. The program relies on industry recommendations for a comprehensive bolting 

maintenance, as delineated in the EPRI TR-1 04213 for pressure retaining bolting and structural 

bolting. The program generally includes periodic inspection of closure bolting for indication of 

loss of preload, cracking, and loss of material due to corrosion, rust, etc. 

Evaluation and Technical Basis 

1. Scope of Program: The program covers all bolting within the scope of license renewal 

including safety-related bolting, bolting for NSSS component supports, bolting for other 

pressure retaining components, and structural bolting. The program covers both greater than and smaller than 2-in. diameter bolting. The Nuclear Regulatory Commission (NRC) 

staff recommendations and guidelines for comprehensive bolting integrity programs that 

encompass all safety-related bolting are delineated in NUREG-1 339. The industry's 

technical basis for the program for safety related bolting and guidelines for material 

selection and testing, bolting preload control, inservice inspection (ISI), plant operation and 

maintenance, and evaluation of the structural integrity of bolted joints, are outlined in EPRI 

NP-5769, with the exceptions noted in NUREG 1339. For other bolting, this information is 

set forth in EPRI TR-104213. 

2. Preventive Actions: Selection of bolting material and the use of lubricants and sealants is 

in accordance with the guidelines of EPRI NP-5769 and the additional recommendations of 

NUREG-1 339 to prevent or mitigate degradation and failure of safety-related bolting (see 

item 10, below). (NUREG-1 339 takes exception to certain items in EPRI NP-5769, and 

recommends additional measures with regard to them.) Initial ISI of bolting for pressure 

retaining components includes a check of the bolt torque and uniformity of the gasket 

compression after assembly. It is noted that hot torquing of bolting is a leak preventive 

measure once the joint is brought to operating temperature and before or after it is 

pressurized. Hot torquing thus reestablishes preload before leak starts, but is ineffective in 

sealing a leak once it has begun. 

3. Parameters Monitored/Inspected: The aging management program (AMP) monitors the 

effects of aging on the intended function of closure bolting, including loss of material, 

cracking, and loss of preload. High strength bolts (actual yield strength > 150 ksi) used in 

NSSS component supports are monitored for cracking. Bolting for pressure retaining 

components is inspected for signs of leakage. Structural bolting is inspected for indication of 

potential problems including loss of coating integrity and obvious signs of corrosion, rust, 

etc. 

4. Detection of Aging Effects: Inspection requirements are in accordance with the American 

Society of Mechanical Engineers (ASME) Section XI, Table IWB 2500-1 or IWC 2500-1 

(1995 edition through the 1996 addenda) and the recommendations of EPRI NP-5769. For 

Class 1 components, Table IWB 2500-1, examination category B-G-1, for bolting greater than 2 in. in diameter, specifies volumetric examination of studs and bolts and visual VT-1 

examination of surfaces of nuts, washers, bushings, and flanges. All high strength bolting 

used in NSSS component supports are to be inspected also to the requirements for Class 1

April 2001 X1 M-61 NUREG-1801
components, examination category B-G-1. Examination category B-G-2, for bolting 2 in. or 

smaller requires only visual VT-1 examination of surfaces of bolts, studs, and nuts. For 

Class 2 components, Table IWC 2500-1, examination category B-D, for bolting greater than 

2 in. in diameter, requires volumetric examination of studs and bolts. Examination 

categories B-P or C-H require visual examination (IWA-5240) during system leakage testing of all pressure-retaining Class 1 and 2 components, according to Tables IWB 2500-1 and 

IWC 2500-1, respectively. In addition, degradation of the closure bolting due to crack 

initiation, loss of prestress, or loss of material due to corrosion of the closure bolting would 

result in leakage. The extent and schedule of inspections, in accordance with IWB 2500-1 

or IWC 2500-1, assure detection of aging degradation before the loss of the intended 

function of the closure bolting. Structural bolting both inside and outside containment is 

inspected by visual inspection. Degradation of this bolting may be detected and measured 

either by removing the bolt, proof test by tension or torquing, by in situ ultrasonic tests, or 

hammer test. If this bolting is found corroded, a closer inspection is performed to assess 

extent of corrosion. 

5. Monitoring and Trending: The inspection schedules of ASME Section XI are effective and 

ensure timely detection of cracks and leakage. If bolting for pressure retaining components (not covered by ASME Section XI) is reported to be leaking, then it may be inspected daily. If the leak rate does not increase, the inspection frequency may be decreased to weekly or 

biweekly. 

6. Acceptance Criteria: Any indications in closure bolting are evaluated in accordance with 

IWB-31 00 and acceptance standards of IWB-3400 and IWB-3500, or IWC-31 00 and 

acceptance standards of IWC-3400 and IWC-3500. Indications of cracking in component 

support bolting warrant immediate replacement of the cracked bolt. For other pressure retaining components, a leak from a joint is immediately repaired if it is a major leak and 

causes adverse effect such as corrosion or contamination. 

7. Corrective Actions: Repair and replacement is in conformance with IWB-4000 and 

guidelines and recommendations of EPRI NP-5769. As discussed in the appendix to this 

report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in 

addressing corrective actions. Repair and replacement of other bolting including structural 

bolting is in conformance with the guidelines and recommendations of EPRI TR-1 04213. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing the confirmation process and administrative controls. 

9. Administrative Controls: See item 8, above. 

10. Operating Experience: Degradation of threaded fasteners in closures for the reactor 

coolant pressure boundary has occurred from boric acid corrosion, stress corrosion 

cracking, and fatigue loading (NRC IE Bulletin 82-02, NRC Generic Letter [GL] 91-17). 

Stress corrosion cracking has occurred in high strength bolts used for NSSS component 

supports. The bolting integrity programs developed and implemented in accordance with 

commitments made in response to NRC communications on bolting events have provided 

an effective means of ensuring bolting reliability. These programs are documented in EPRI 

NP-5769 and TR-1 04213 and represent industry consensus.

NUREG-1 801 X1 M-62 April 2001
References

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2000. 

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 1995 edition through the 1996 addenda, American 

Society of Mechanical Engineers, New York, NY. 

EPRI NP-5769, Degradation and Failure of Bolting in Nuclear Power Plants, Volumes 1 and 2, 

Electric Power Research Institute, Palo Alto, CA, April 1988. 

EPRI TR-1 04213, Bolted Joint Maintenance & Application Guide, Electric Power Research 

Institute, Palo Alto, CA, 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 IE Bulletin No. 82-02, Degradation of Threaded Fasteners in the Reactor Coolant 

Pressure Boundary of PWR Plants, U.S. Nuclear Regulatory Commission, June 2, 1982. 

NUREG-1 339, Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear 

Power Plants, Richard E. Johnson, U.S. Nuclear Regulatory Commission, June 1990.

April 2001 Xl M-63 NUREG-1801
XI.M19 STEAM GENERATOR TUBE INTEGRITY

Program Description 

Steam generator (SG) tubes have experienced tube degradation related to corrosion 

phenomena, such as primary water stress corrosion cracking (PWSCC), outside diameter 

stress corrosion cracking (ODSCC), intergranular attack (IGA), pitting, and wastage, along with 

other mechanically induced phenomena, such as denting, wear, impingement damage, and 

fatigue. Nondestructive examination (NDE) techniques are used to identify tubes that are 

defective and need to be removed from service or repaired in accordance with the guidelines of 

the plant technical specifications. In addition, operational leakage limits are included to ensure 

that, should substantial tube leakage develop, prompt action is taken to avoid rupture of the 

leaking tubes. These limits are included in plant technical specifications, such as standard 

technical specifications of NUREG-1430, Rev. 1, for Babcock & Wilcox pressurized water 

reactors (PWRs); NUREG-1431, Rev. 1, for Westinghouse PWRs; and NUREG-1432, Rev. 1, 

for Combustion Engineering PWRs. 

The technical specifications specify SG inspection scope and frequency, and acceptance 

criteria for the plugging and repair of flawed tubes. The Nuclear Regulatory Commission (NRC) 

Regulatory Guide (RG) 1.121, "Bases for Plugging Degraded Steam Generator Tubes," 

provides guidelines for determining the tube repair criteria and operational leakage limits. 

Acceptance criteria for the plugging and repair of flawed tubes are incorporated in the plant 

technical specifications. 

However, plants may apply for changes in their technical specifications to provide an alternate 

regulatory basis for SG degradation management. The NRC has approved changes in the 

technical specification tube repair criteria at certain plants. Examples include the alternate 

voltage-based repair criteria of NRC Generic Letter (GL) 95-05 and certain sleeving process. In 

addition, all PWR licensees have committed voluntarily to a SG degradation management 

program described in the Nuclear Energy Institute (NEI 97-06, "Steam Generator Program 

Guidelines." This program references a number of industry guidelines and incorporates a 

balance of prevention, inspection, evaluation, repair, and leakage monitoring measures. These 

guidelines are currently under NRC review. 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. The NEI 97-06 program includes an assessment of 

degradation mechanisms that considers operating experience from similar SGs to identify 

degradation mechanisms and, for each mechanism, defines the inspection techniques, 

measurement uncertainty, as well as the sampling strategy. The industry guidelines provide 

criteria for the qualification of personnel, specific techniques, and the associated acquisition 

and analysis of data, including procedures, probe selection, analysis protocols, and reporting 

criteria. The performance criteria pertain to structural integrity, accident-induced leakage, and 

operational leakage. The SG monitoring program includes guidance on assessment of 

degradation mechanisms, inspection, tube integrity assessment, maintenance, plugging, repair, 

and leakage monitoring, as well as procedures for monitoring and controlling secondary-side 

and primary-side water chemistry. The water chemistry program for PWRs relies on monitoring 

and control of reactor water chemistry and secondary water chemistry. 

As evaluated below, the plant technical specifications, incorporating NEI 97-06 as approved by 

the staff and any other alternate regulatory bases for SG degradation management that have 

been previously approved by the staff for that plant, are adequate to manage the effects of

NUREG-1801 XI M-64 April 2001
aging on the SG tubes. However, because NEI 97-06 is still under staff review, until the staff 

has approved NEI 97-06, the applicant's program should be reviewed on a plant-specific basis. 

Evaluation and Technical Basis 

1. Scope of Program: The scope of the program is specific to SG tubes. The program includes preventive measures to mitigate degradation related to corrosion phenomena; assessment of degradation mechanisms; inservice inspection (ISI) of steam generator tubes to detect degradation; evaluation and plugging or repair, as needed; and leakage monitoring to maintain the structural and leakage integrity of the pressure boundary. Tube 

inspection scope and frequency, plugging or repair, and leakage monitoring are in 

accordance with the plant technical specifications. 

2. Preventive Actions: The program includes preventive measures to mitigate degradation related to corrosion phenomena. The guidelines in NEI 97-06 include foreign material 

exclusion as a means to inhibit fretting and wear degradation. The water chemistry program for PWRs relies on monitoring and control of reactor water chemistry based on the EPRI 

guidelines in TR-1 05714 for primary water chemistry and TR-1 02134 for secondary water 

chemistry. The program description and the evaluation and technical basis of monitoring and maintaining reactor water chemistry are presented in Chapter XI.M2, 'Water 

Chemistry," of this report. 

3. Parameters Monitored/Inspected: The inspection activities in the program detect flaws in 

tubing or degradation of secondary side internals needed to maintain tubing integrity. Flaws 

are removed based on technical specification repair criteria. Degradation of steam 

generator internals is evaluated for corrective actions. 

4. Detection of Aging Effects: The inspection requirements in the technical specifications are 

intended to detect tube degradation (i.e., aging effects), if it should occur. The NEI 97-06 

document, which is currently under NRC staff review, provides additional guidance on 

inspection programs to detect degradation. The intent of the inspection and repair criteria is 

to provide assurance of continued tube integrity between inspections. 

5. Monitoring and Trending: Condition monitoring assessments are performed to determine 

whether structural and accident leakage criteria have been satisfied. Operational assessments are performed after inspections to verify that structural and leakage integrity 

are maintained during the operating interval until the next required inspection, which is 

selected in accordance with the technical specifications and staff approved NEI 97-06 

guidelines. Comparison of the results of the condition monitoring assessment with the predictions of the previous operational assessment provides feedback for evaluation of the 

adequacy of the operational assessment and additional insights that can be incorporated 

into the next operational assessment. 

6. Acceptance Criteria: Assessment of tube integrity and plugging or repair criteria of flawed tubes is in accordance with the plant technical specifications. The criteria for plugging or 

repairing SG tubes are based on NRC RG 1.121 or other criteria previously reviewed and 

approved by the staff and incorporated into the plant technical specifications. Some 

examples that are applicable under certain circumstances include P*, F*, L*, or NRC 

GL 95-05. 

For general and pitting corrosion, the acceptance criteria are in accordance with staff 

approved NEI 97-06 guidelines. Also, loose parts or foreign objects that are found are

April 2001 XI M-65 NUREG-1 801
removed from the SGs unless it can be shown by evaluation that these objects do not cause 

unacceptable tube damage. The evaluation is to define an acceptable operating interval. 

For Westinghouse steam generator tube plugs, limits for the life of the plug and correlations 

for estimating their life are contained in WCAP-1 2244 and WCAP-12245. 

7. Corrective Actions: Tubes containing flaws that do not meet the acceptance criteria are 

plugged or repaired. As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable in addressing corrective actions. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing the confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: Failures to detect some flaws, uncertainties in flaw sizing, inaccuracies in flaw locations, and the inability to detect some cracks at locations with dents 

have been reviewed in NRC Information Notice (IN) 97-88. Recent experience indicates the importance of performing a complete inspection by using appropriate techniques and 

equipment for the reliable detection of tube degradation and to provide assurance that new 

forms of degradation are detected. Implementation of the program provides reasonable 

assurance that SG tube integrity is maintained consistent with the plant's licensing basis for 

the period of extended operation. Experience with the condition and operational 

assessments required for plants that have implemented the alternate repair criteria in NRC 

GL 95-05 has shown that the predictions of the operational assessments have generally been consistent with the results of the subsequent condition monitoring assessments. In 

cases where discrepancies have been noted, adjustments have been made in the 

operational assessment models to improve agreement in subsequent assessments. In 

addition, NEI has prepared NEI 97-06 to incorporate lessons learned from plant operation experience and SG inspections and is under staff review. 

References 

EPRI TR-1 02134, PWR Secondary Water Chemistry Guidelines: Revision 3, Electric Power 

Research Institute, Palo Alto, CA, May 1993. 

EPRI TR-1 05714, PWR Primary Water Chemistry Guidelines: Revision 3, Electric Power 

Research Institute, Palo Alto, CA, November 1995. 

EPRI TR-1 07569, PWR Steam Generator Examination Guidelines: Revision 5, Electric Power 

Research Institute, Palo Alto, CA, September 1997. 

NEI 97-06, Rev. 1, Steam Generator Program Guidelines, Nuclear Energy Institute, January 

2000. 

NRC Generic Letter 95-05, Voltage-Based Repair Criteria for Westinghouse Steam Generator 

Tubes Affected by Outside-Diameter Stress-Corrosion Cracking, U.S. Nuclear Regulatory 

Commission, August 3, 1995.

NUREG-1801 Xl M-66 April 2001
NRC Information Notice, 97-88, Experiences during Recent Steam Generator Inspections, 

U.S. Nuclear Regulatory Commission, December 12, 1997. 

NRC Regulatory Guide, 1.83, Rev. 1, Inservice Inspection of Pressurized Water Reactor Steam 

Generator Tubes, U.S. Nuclear Regulatory Commission, July 1975. 

NRC Regulatory Guide, 1.121, Bases for Plugging Degraded PWR Steam Generator Tubes, 

U.S. Nuclear Regulatory Commission, August 1976. 

NUREG-1 430, Rev. 1, Standard Technical Specifications for Babcock and Wilcox Pressurized 

Water Reactors, U.S. Nuclear Regulatory Commission, April 1995. 

NUREG-1 431, Rev. 1, Standard Technical Specifications for Westinghouse Pressurized Water 

Reactors, U.S. Nuclear Regulatory Commission, April 1995. 

NUREG-1 432, Rev. 1, Standard Technical Specifications for Combustion Engineering Pressurized Water Reactors, U.S. Nuclear Regulatory Commission, April 1995. 

WCAP-1 2244 and WCAP-1 2245, Steam Generator Tube Plug Integrity Summary Report, Addendum 2 to Revision 3, Westinghouse Electric Corporation, PA, May 1991.

April 2001 XI M-67 NUREG-1 801
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 open

cycle cooling water (OCCW) (or service water) system will be managed for the extended period 

of operation. The program includes surveillance and control techniques to manage aging 

effects caused by biofouling, corrosion, erosion, protective coating failures, and silting in the 

OCCW system or structures and components serviced by the OCCW system. 

Evaluation and Technical Basis 

1. Scope of Program: The program addresses the aging effects of material loss and fouling 

due to micro- or macro-organisms and various corrosion mechanisms. Because the 

characteristics of the service water system may be specific to each facility, the OCCW 

system is defined as a system or systems that transfer heat from safety-related systems, 

structures, and components (SSC) to the ultimate heat sink (UHS). If an intermediate 

system is used between the safety-related SSCs and the system rejecting heat to the UHS, 

that intermediate system performs the function of a service water system and is thus 

included in the scope of recommendations of NRC GL 89-13. The guidelines of NRC 

GL 89-13 include (a) surveillance and control of biofouling; (b) a test program to verify heat 

transfer capabilities; (c) routine inspection and a maintenance program to ensure that 

corrosion, erosion, protective coating failure, silting, and biofouling cannot degrade the 

performance of safety-related systems serviced by OCCW; (d) a system walkdown 

inspection to ensure compliance with the licensing basis; and (e) a review of maintenance, 

operating, and training practices and procedures. 

2. Preventive Actions: The system components are constructed of appropriate materials and 

lined or coated to protect the underlying metal surfaces from being exposed to aggressive 

cooling water environments. Implementation of NRC GL 89-13 includes a condition and 

performance monitoring program; control or preventive measures, such as chemical 

treatment, whenever the potential for biological fouling species exists; or flushing of 

infrequently used systems. Treatment with chemicals mitigates microbiologically influenced 

corrosion (MIC) and buildup of macroscopic biological fouling species, such as blue 

mussels, oysters, or clams. Periodic flushing of the system removes accumulations of 

biofouling agents, corrosion products, and silt. 

3. Parameters Monitored/Inspected: Adverse effects on system or component performance 

are caused by accumulations of biofouling agents, corrosion products, and silt. Cleanliness 

and material integrity of piping, components, heat exchangers, and their internal linings or 

coatings (when applicable) that are part of the OCCW system or that are cooled by the 

OCCW system are periodically inspected, monitored, or tested to ensure heat transfer 

capabilities. The program ensures (a) removal of accumulations of biofouling agents, 

corrosion products, and silt, and (b) detection of defective protective coatings and corroded 

OCCW system piping and components that could adversely affect performance of their 

intended safety functions. 

4. Detection of Aging Effects: Inspections for biofouling, damaged coatings, and degraded 

material condition are conducted. Visual inspections are typically performed; however, 

nondestructive testing, such as ultrasonic testing, eddy current testing, and heat transfer 

capability testing, are effective methods to measure surface condition and the extent of wall 

NUREG-1 801 XI M-68 April 2001
thinning associated with the service water system piping and components, when determined 

necessary. 

5. Monitoring and Trending: Inspection scope, method (e.g., visual or nondestructive 

examination [NDE]), and testing frequencies are in accordance with the utility commitments 

under NRC GL 89-13. Testing and inspections are done annually and during refueling 

outages. Inspections or nondestructive testing will determine the extent of biofouling, the 

condition of the surface coating, the magnitude of localized pitting, and the amount of MIC, 

if applicable. Heat transfer testing results are documented in plant test procedures and are 

trended and reviewed by the appropriate group. 

6. Acceptance Criteria: Biofouling is removed or reduced as part of the surveillance and 

control process. The program for managing biofouling and aggressive cooling water 

environments for OCCW systems is preventive. Acceptance criteria are based on effective 

cleaning of biological fouling organisms and maintenance of protective coatings or linings 

are emphasized. 

7. Corrective Actions: Evaluations are performed for test or inspection results that do not 

satisfy established acceptance criteria and a problem or condition report is initiated to 

document the concern in accordance with plant administrative procedures. The corrective 

actions program ensures that the conditions adverse to quality are promptly corrected. If the 

deficiency is assessed to be significantly adverse to quality, the cause of the condition is 

determined, and an action plan is developed to preclude repetition. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable in addressing corrective actions. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing 

the confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: Significant microbiologically influenced corrosion (NRC Information 

Notice [IN] 85-30), failure of protective coatings (NRC IN 85-24), and fouling (NRC IN 81-21, 

IN 86-96) have been observed in a number of heat exchangers. The guidance of NRC 

GL 89-13 has been implemented for approximately 10 years and has been effective in 

managing aging effects due to biofouling, corrosion, erosion, protective coating failures, and 

silting in structures and components serviced by OCCW systems. 

References 

NRC Generic Letter 89-13, Service Water System Problems Affecting Safety-Related 

Equipment, U.S. Nuclear Regulatory Commission, July 18, 1989. 

NRC Generic Letter 89-13, Supplement 1, Service Water System Problems Affecting Safety

Related Equipment, 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.

April 2001 Xl M-69 NUREG-1801
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.

NUREG-1801 XI M-70 April 2001
XI.M21 CLOSED-CYCLE COOLING WATER SYSTEM

Program Description 

The program includes (a) preventive measures to minimize corrosion and (b) surveillance 

testing and inspection to monitor the effects of corrosion on the intended function of the 

component. The program relies on maintenance of system corrosion inhibitor concentrations 

within specified limits of Electric Power Research Institute [EPRI] TR-107396 to minimize 

corrosion. Surveillance testing and inspection in accordance with standards in EPRI TR-1 07396 

for closed-cycle cooling water (CCCW) systems is performed to evaluate system and 

component performance. These measures will ensure that the CCCW system and components 

serviced by the CCCW system are performing their functions acceptably. 

Evaluation and Technical Basis 

1. Scope of Program: A CCCW system is defined as part of the service water system that is 

not subject to significant sources of contamination, in which water chemistry is controlled 

and in which heat is not directly rejected to a heat sink. The program described in this 

section applies only to such a system. If one or more of these conditions are not satisfied, 

the system is to be considered an open-cycle cooling water system. The staff notes that if 

the adequacy of cooling water chemistry control can not be confirmed, the system is treated 

as an open-cycle system as indicated in Action III of Generic Letter (GL) 89-13. 

2. Preventive Actions: The program relies on the use of appropriate materials, lining, or 

coating to protect the underlying metal surfaces and maintenance of system corrosion 

inhibitor concentrations within specified limits of EPRI TR-1 07396 to minimize corrosion. 

The program includes monitoring and control of cooling water chemistry to minimize 

exposure to aggressive environments and application of corrosion inhibitor in the CCCW 

system to mitigate general, crevice, and pitting corrosion. 

3. Parameters Monitored/Inspected: The aging management program (AMP) monitors the 

effects of corrosion by surveillance testing and inspection in accordance with standards in 

EPRI TR-1 07396 to evaluate system and component performance. For pumps, the 

parameters monitored include flow and discharge and suction pressures. For heat 

exchangers, the parameters monitored include flow, inlet and outlet temperatures, and 

differential pressure. 

4. Detection of Aging Effects: Control of water chemistry does not preclude corrosion at 

locations of stagnant flow conditions or crevices. Degradation of a component due to 

corrosion would result in degradation of system or component performance. The extent and 

schedule of inspections and testing in accordance with EPRI TR-1 07396, assure detection 

of corrosion before the loss of intended function of the component. Performance and 

functional testing in accordance with EPRI TR-107396, ensures acceptable functioning of 

the CCCW system or components serviced by the CCCW system. For systems and 

components in continuous operation, performance adequacy is determined by monitoring 

data trends for evaluation of heat transfer fouling, pump wear characteristics, and branch 

flow changes. Components not in operation are periodically tested to ensure operability. 

5. Monitoring and Trending: The frequency of sampling water chemistry varies and can 

occur on a continuous, daily, weekly, or as needed basis, as indicated by plant operating conditions. Per EPRI TR-1 07396, performance and functional tests are performed at least 

every 18 months to demonstrate system operability, and tests to evaluate heat removal

April 2001 X! M-71 NUREG-1 801
capability of the system and degradation of system components are performed every five 

years. The testing intervals may be adjusted on the basis of the results of the reliability 

analysis, type of service, frequency of operation, or age of components and systems. 

6. Acceptance Criteria: Corrosion inhibitor concentrations are maintained within the limits 

specified in the EPRI water chemistry guidelines for CCCW. System and component 

performance test results are evaluated in accordance with the guidelines of EPRI TR

107396. Acceptance criteria and tolerances are also based on system design parameters 

and functions. 

7. Corrective Actions: Corrosion inhibitor concentrations outside the allowable limits are 

returned to the acceptable range within the time period specified in the EPRI water 

chemistry guidelines for CCCW. If the system or component fails to perform adequately, 

corrective actions are taken in accordance with EPRI TR-1 07396. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable in addressing corrective actions. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing the confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: Degradation of closed-cycle cooling water systems due to 

corrosion product buildup (NRC Licensee Event Report [LER] 93-029-00) or through-wall 

cracks in supply lines (NRC LER 91-019-00) has been observed in operating plants. 

Accordingly, operating experience demonstrates the need for this program. 

References 

EPRI TR-1 07396, Closed Cooling Water Chemistry Guidelines, Electric Power Research 

Institute, Palo Alto, CA, November 1997. 

NRC Generic Letter 89-13, Service Water System Problems Affecting Safety-Related 

Equipment, U.S. Nuclear Regulatory Commission, July 18, 1989. 

NRC Generic Letter 89-13, Supplement 1, Service Water System Problems Affecting Safety

Related Equipment, U.S. Nuclear Regulatory Commission, April 4, 1990. 

NRC Licensee Event Report LER #91-019-00, Loss of Containment Integrity due to Crack in 

Component Cooling Water Piping, October 26, 1991. 

NRC Licensee Event Report LER #93-029-00, Inoperable Check Valve in the Component 

Cooling System as a Result of a Build-Up of Corrosion Products between Valve 

Components, December 13, 1993. 

NUREG-1801 Xl M-72 April 2001
XI.M22 BORAFLEX MONITORING

Program Description 

A Boraflex monitoring program for the actual Boraflex panels is implemented in the spent fuel 

racks to assure that no unexpected degradation of the Boraflex material would compromise the 

criticality analysis in support of the design of spent fuel storage racks. The applicable aging management program (AMP), based on manufacturer's recommendations, relies on periodic inspection, testing, monitoring, and analysis of the criticality design to assure that the required 5% subcriticality margin is maintained. The frequency of the inspection and testing depends on 

the condition of the Boraflex, with a maximum of five years. Certain accelerated samples are 

tested every two years. Results based on test coupons have been found to be unreliable in 

determining the degree to which the actual Boraflex panels have been degraded. Therefore, this AMP includes: (1) performing neutron attenuation testing, called blackness testing, to 

determine gap formation in Boraflex panels; (2) completing sampling and analysis for silica 

levels in the spent fuel pool water and trending the results by using the EPRI RACKLIFE 

predictive code or its equivalent on a monthly, quarterly, or annual basis (depending on 

Boraflex panel condition); and (3) measuring boron areal density by techniques such as the 

BADGER device. Corrective actions are initiated if the test results find that the 5% subcriticality margin cannot be maintained because of current or projected future Boraflex degradation. 

Evaluation and Technical Basis 

1. Scope of Program: The AMP manages the effects of aging on sheets of neutron-absorbing materials affixed to spent fuel racks. For Boraflex panels, gamma irradiation and long-term 

exposure to the wet pool environment cause shrinkage resulting in gap formation, gradual degradation of the polymer matrix, and the release of silica to the spent fuel storage pool 

water. This results in the loss of boron carbide in the neutron absorber sheets. 

2. Preventive Actions: For Boraflex panels, monitoring silica levels in the storage pool water, measuring gap formation by blackness testing, periodically measuring boron areal density, and applying predictive codes, are performed. These actions ensure that degradation of the 

neutron-absorbing material is identified and corrected so the spent fuel storage racks will be 

capable of performing their intended functions during the period of extended operation, consistent with current licensing basis (CLB) design conditions. 

3. Parameters Monitored/Inspected: The parameters monitored include physical conditions 

of the Boraflex panels, such as gap formation and decreased boron areal density, and the 

concentration of the silica in the spent fuel pool. These are conditions directly related to 

degradation of the Boraflex material. When Boraflex is subjected to gamma radiation and 

long-term exposure to the spent fuel pool environment, the silicon polymer matrix becomes 

degraded and silica filler and boron carbide are released into the spent fuel pool water. As 

indicated in the Nuclear Regulatory Commission (NRC) Information Notice (IN) 95-38 and 

NRC Generic Letter (GL) 96-04, the loss of boron carbide (washout) from Boraflex is 

characterized by slow dissolution of silica from the surface of the Boraflex and a gradual thinning of the material. Because Boraflex contains about 25% silica, 25% polydimethyl siloxane polymer, and 50% boron carbide, sampling and analysis of the presence of silica in 

the spent fuel pool provide an indication of depletion of boron carbide from Boraflex; however, the degree to which Boraflex has degraded is ascertained through measurement 

of the boron areal density.

April 2001 XI M-73 NUREG-1801
4. Detection of Aging Effects: The amount of boron carbide released from the Boraflex panel 

is determined through direct measurement of boron areal density and correlated with the 

levels of silica present through the use of a predictive code. This is supplemented with 

detection of gaps through blackness testing and periodic verification of boron loss through 

areal density measurement techniques such as the BADGER device. 

5. Monitoring and Trending: The periodic inspection measurements and analysis are to be 

compared to values of previous measurements and analysis to provide a continuing level of 

data for trend analysis. 

6. Acceptance Criteria: The 5% subcriticality margin of the spent fuel racks is to be 

maintained for the period of extended operation. 

7. Corrective Actions: Corrective actions are initiated if the test results find that the 5% 

subcriticality margin cannot be maintained because of the current or projected future 

degradation. Corrective actions consist of providing additional neutron-absorbing capacity 

by Boral or boron steel inserts, or other options which are available to maintain a 

subcriticality margin of 5%. As discussed in the appendix of this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable in addressing 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 of this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing 

the confirmation process and administrative controls. 

9. Administrative Controls: See item 8, above. 

10. Operating Experience: The NRC IN 87-43 addresses the problems of development of 

tears and gaps (average 1-2 in., with the largest 4 in.) in Boraflex sheets due to gamma 

radiation-induced shrinkage of the material. The NRC IN 93-70 and 95-38 and NRC 

GL 96-04 address several cases of significant degradation of Boraflex test coupons due to 

accelerated dissolution of Boraflex caused by pool water flow through panel enclosures and 

high accumulated gamma dose. Two spent fuel rack cells with about 12 years of service 

have only 40% of the Boraflex remaining. In such cases, the Boraflex may be replaced by 

boron steel inserts or by a completely new rack system using Boral. Experience with boron 

steel is limited; however, the application of Boral for use in the spent fuel storage racks 

predates the manufacturing and use of Boraflex. The experience with Boraflex panels 

indicates that coupon surveillance programs are not reliable, therefore, measurement of 

boron areal density correlated, through a predictive code, with silica levels in the pool water 

and verified periodically, is performed during the period of extended operation. These 

monitoring programs provide assurance that degradation of Boraflex sheets is monitored, 

so that appropriate actions can be taken in a timely manner if significant loss of neutron

absorbing capability is occurring. These monitoring programs ensure that the Boraflex 

sheets will maintain their integrity and will be effective in performing its intended function. 

References 

BNL-NUREG-25582, Corrosion Considerations in the Use of Boral in Spent Fuel Storage Pool 

Racks, January 1979.

NUREG-1801 XI M-74 April 2001
EPRI NP-6159, An Assessment of Boraflex Performance in Spent Nuclear Fuel Storage Racks, 

Electric Power Research Institute, Palo Alto, CA, December 14, 1988. 

EPRI TR-1 01986, Boraflex Test Results and Evaluation, Electric Power Research Institute, 

Palo Alto, CA, March 1, 1993. 

EPRI TR-1 03300, 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.

April 2001 Xl M-75 NUREG-1 801
XI.M23 INSPECTION OF OVERHEAD HEAVY LOAD AND LIGHT LOAD (RELATED TO 

REFUELING) HANDLING SYSTEMS 

Program Description 

Most commercial nuclear facilities have between 50 and 100 cranes. Many are industrial grade 

cranes which meet the requirements of 29 CFR Volume XVII, Part 1910, and Section 1910.179. 

Most are not within the scope of 10 CFR 54.4, and therefore are not required to be part of the 

integrated plant assessment (IPA). 

Normally, fewer than 10 cranes fall within the scope of 10 CFR 54.4. These cranes comply with 

the Maintenance Rule requirements provided in 10 CFR 50.65. The Nuclear Regulatory 

Commission Regulatory Guide (RG) 1.160 provides guidance for monitoring the effectiveness 

of maintenance at nuclear power plants. 

The program demonstrates that testing and monitoring programs have been implemented and 

have ensured that the structures, systems, and components of these cranes are capable of 

sustaining their rated loads. This is their intended function during the period of extended 

operation. It is noted that many of the systems and components of these cranes perform an 

intended function with moving parts or with a change in configuration, or subject to replacement 

based on qualified life. In these instances, these types of crane systems and components are 

not within the scope of this aging management program (AMP). This program is primarily 

concerned with structural components that make up the bridge and trolley. NUREG-0612, 

"Control of Heavy Loads at Nuclear Power Plants," provides specific guidance on the control of 

overhead heavy load cranes. 

Evaluation and Technical Basis 

1. Scope of Program: The program manages the effects of general corrosion on the crane 

and trolley structural components for those cranes that are within the scope of 10 CFR 54.4, 

and the effects of wear on the rails in the rail system. 

2. Preventive Actions: No preventive actions are identified. The crane program is an 

inspection program. 

3. Parameters MonitoredfInspected: The program evaluates the effectiveness of the 

maintenance monitoring program and the effects of past and future usage on the structural 

reliability of cranes. The number and magnitude of lifts made by the crane are also 

reviewed. 

4. Detection of Aging Effect: Crane rails and structural components are visually inspected on 

a routine basis for degradation. Functional tests are also performed to assure their integrity. 

5. Monitoring and Trending: Monitoring and trending are not required as part of the crane 

inspection program. 

6. Acceptance Criteria: Any significant visual indication of loss of material due to corrosion or 

wear are evaluated according to applicable industry standards and good industry practice. 

The crane may also have been designed to a specific Service Class as defined in the EOCI 

Specification #61 (or later revisions), or CMAA Specification #70 (or later revisions), or 

CMAA Specification #74 (or later revisions). The specification that was applicable at the 

time the crane was manufactured is used. 

NUREG-1801 XI M-76 April 2001
7. Corrective Actions: Site corrective actions program, quality assurance (QA) procedures, site review and approval process, and administrative controls are implemented in 

accordance with the requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing the corrective actions, confirmation process, and administrative 

controls. 

8. Confirmation Process: See Item 7, above. 

9. Administrative Controls: See Item 7, above. 

10. Operating Experience: Because of the requirements for monitoring the effectiveness of maintenance at nuclear power plants provided in 10 CFR 50.65, there has been no history of corrosion-related degradation that has impaired cranes. Likewise, because cranes have 

not been operated beyond their design lifetime, there have been no significant fatigue related structural failures. 

References 

10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Office of the Federal Register, National Archives and Records Administration, 

January 1997. 

Crane Manufactures Association of America, Inc., CMAA Specification No. 70, Specifications for Electric Overhead Traveling Cranes, 1970 (or later revisions). 

Crane Manufactures Association of America, Inc., CMAA Specification No. 74, Specifications for Top Running and Under Running Single Girder Electric Overhead Traveling Cranes, 

1974 (or later revisions>. 

Electric Overhead Crane Institute, Inc., EOCI Specification No. 61, Specifications for Electric 

Overhead Traveling Cranes, 1961 (or later revisions). 

NUREG-0612, Control of Heavy Loads at Nuclear Power Plants, U.S. Nuclear Regulatory Commission, 1980. 

NRC Regulatory Guide 1.160, Rev. 2, Monitoring the Effectiveness of Maintenance at Nuclear 

Power Plants, U.S. Nuclear Regulatory Commission, March 1997.

April 2001 XI M-77 NUREG-1801
XI.M24 COMPRESSED AIR MONITORING

Program Description 

The program consists of inspection, monitoring, and testing of the entire system, including 

(a) frequent leak testing of valves, piping, and other system components, especially those 

made of carbon steel; and (b) preventive monitoring that checks air quality at various locations 

in the system to ensure that oil, water, rust, dirt, and other contaminants are kept within the 

specified limits. The aging management program (AMP) provides for timely corrective actions to 

ensure that the system is operating within specified limits. 

The AMP is based on results of the plant owners response to the Nuclear Regulatory 

Commission (NRC) Generic Letter (GL) 88-14, augmented by previous NRC Information 

Notices IN 81-38, IN 87-28, and IN 87-28 S1, and by the Institute of Nuclear Power Operations 

Significant Operating Experience Report (INPO SOER) 88-01. The NRC GL 88-14, issued after 

several years of study of problems and failures of instrument air systems, recommends each 

holder of an operating license to perform an extensive design and operations review and 

verification of its instrument air system. The GL 88-14 also recommends the licensees to 

describe their program for maintaining proper instrument air quality. The AMP also incorporates 

provisions conforming to the guidance of the Electric Power Research Institute (EPRI) NP

7079, issued in 1990, to assist utilities in identifying and correcting system problems in the 

instrument air system and to enable them to maintain required industry safety standards. 

Subsequent to these initial actions by all plant licensees to implement an improved AMP, some 

utilities decided to replace their instrument air system with newer models and types of 

equipment. The EPRI then issued TR-108147, which addresses maintenance of the latest 

compressors and other instrument air system equipment currently in use at those plants. The 

American Society of Mechanical Engineers operations and maintenance standards and guides 

(ASME OM-S/G-1 998, Part 17) provides additional guidance to the maintenance of the 

instrument air system by offering recommended test methods, test intervals, parameters to be 

measured and evaluated, acceptance criteria, corrective actions, and records requirements. 

Evaluation and Technical Basis 

1. Scope of Program: The program manages the effects of corrosion and the presence of 

unacceptable levels of contaminants on the intended function of the compressed air system. 

The AMP includes frequent leak testing of valves, piping, and other system components, 

especially those made of carbon steel, and a preventive maintenance program to check air 

quality at several locations in the system. 

2. Preventive Actions: The system air quality is monitored and maintained in accordance with 

the plant owner's testing and inspection plans, which are designed to ensure that the 

system and equipment meet specified operability requirements. These requirements are 

prepared from consideration of manufacturer's recommendations for individual components 

and guidelines based on ASME OM-S/G-1 998, Part 17; ISA-$7.0.01-1996; EPRI NP-7079; 

and EPRI TR-1 08147. The preventive maintenance program addresses various aspects of 

the inoperability of air-operated components due to corrosion and the presence of oil, water, 

rust, and other contaminants. 

3. Parameters Monitored/Inspected: Inservice inspection (ISI) and testing is performed to 

verify proper air quality and confirm that maintenance practices, emergency procedures, 

and training are adequate to ensure that the intended function of the air system is 

maintained. 

NUREG-1801 Xl M-78 April 2001
4. Detection of Aging Effects: Guidelines in EPRI NP-7079, EPRI TR-1 08147, and ASME 

OM-S/G-1 998, Part 17, ensure timely detection of degradation of the compressed air 

system function. Degradation of the piping and any equipment would become evident by 

observation of excessive corrosion, by the discovery of unacceptable leakage rates, and by 

failure of the system or any item of equipment to meet specified performance limits. 

5. Monitoring and Trending: Effects of corrosion and the presence of contaminants are 

monitored by visual inspection and periodic system and component tests, including leak rate 

tests on the system and on individual items of equipment. These tests verify proper 

operation by comparing measured values of performance with specified performance limits. 

Test data are analyzed and compared to data from previous tests to provide for timely 

detection of aging effects. 

6. Acceptance Criteria: Acceptance criteria is established for the system and for individual 

equipment that contain specific limits or acceptance ranges based on design basis 

conditions and/or equipment vendor specifications. The testing results are analyzed to verify 

that the design and performance of the system is in accordance with its intended function. 

7. Corrective Actions: Corrective actions are taken if any parameters are out of acceptable 

ranges, such as moisture content in the system air. As discussed in the appendix to this 

report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in 

addressing corrective actions. 

8. Confirmation Process: The site corrective actions program, quality assurance (QA) 

procedures, site review and approval process, and administrative controls are implemented 

in accordance with the requirements of 10 CFR Part 50, Appendix B. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable in addressing the confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: Potentially significant safety-related problems pertaining to air 

systems have been documented in NRC IN 81-38, IN 87-28, IN 87-28 S1 and license event 

report (LER) 50-237/94-005-3. Some of the systems that have been significantly degraded 

or have failed due to the problems in the air system include the decay heat removal, 

auxiliary feedwater, main steam isolation, containment isolation, and fuel pool seal system. 

As a result of NRC GL 88-14 and consideration of INPO SOER 88-01, EPRI NP-7079, and 

EPRI TR-1 08147, performance of air systems has improved significantly. 

References 

ASME OM-S/G-1 998, Part 17, Performance Testing of Instrument Air Systems Information 

Notice Light-Water Reactor Power Plants, 1 ISA-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-1 08147, Compressor and Instrument Air System Maintenance Guide: Revision 

to NP-7079, Electric Power Research Institute, Palo Alto, CA., March 1998. 

INPO SOER 88-01, Instrument Air System Failures, May 18, 1988.

April 2001 X1 M-79 NUREG-1 801
NRC Generic Letter 88-14, Instrument Air Supply Problems Affecting Safety-Related Equipment, U.S. Nuclear Regulatory Commission, August 8, 1988. 

NRC Information Notice 81-38, Potentially Significant Equipment Failures Resulting from Contamination of Air-Operated Systems, U.S. Nuclear Regulatory Commission, 

December 17, 1981. 

NRC Information Notice 87-28, Air Systems Problems at U.S. Light Water Reactors, U.S. Nuclear Regulatory Commission, June 22, 1987. 

NRC Information Notice 87-28, Supplement 1, Air Systems Problems at U.S. Light Water 

Reactors, U.S. Nuclear Regulatory Commission, December 28, 1987. 

NRC Licensee Event Report LER 50-237/94-005-3, Manual Reactor Scram due to Loss of Instrument Air Resulting from Air Receiver Pipe Failure Caused by Improper Installation of Threaded Pipe during Initial Construction, U.S. Nuclear Regulatory Commission, April 23, 

1997.

NUREG-1801 April 2001 Xl M-80
XI.M25 BWR REACTOR WATER CLEANUP SYSTEM

Program Description 

The program includes inservice inspection (ISI) and monitoring and control of reactor coolant 

water chemistry to manage the effects of stress corrosion cracking (SCC) or intergranular 

stress corrosion cracking (IGSCC) on the intended function of austenitic stainless steel (SS) 

piping in the reactor water cleanup (RWCU) system. Based on the Nuclear Regulatory 

Commission (NRC) criteria related to inspection guidelines for RWCU piping welds outboard of 

the second isolation valve, the program includes the measures delineated in NUREG-0313, 

Rev. 2, and NRC Generic Letter (GL) 88-01. Coolant water chemistry is monitored and 

maintained in accordance with the Electric Power Research Institute (EPRI) guidelines in boiling 

water reactor vessel and internals project (BWRVIP)-29 (TR-1 03515) to minimize the potential 

of crack initiation and growth due to SCC or IGSCC. 

Evaluation and Technical Basis 

1. Scope of Program: Based on the NRC letter (September 15, 1995) on the screening 

criteria related to inspection guidelines for RWCU piping welds outboard of the second 

isolation valve, the program includes the measures delineated in NUREG-0313, Rev. 2, and 

NRC GL 88-01 to monitor SCC or IGSCC and its effects on the intended function of 

austenitic SS piping. The screening criteria include: 

a. Satisfactory completion of all actions requested in NRC GL 89-10, 

b. No detection of IGSCC in RWCU welds inboard of the second isolation valves (ongoing 

inspection in accordance with the guidance in NRC GL 88-01), and 

c. No detection of IGSCC in RWCU welds outboard of the second isolation valves after 

inspecting a minimum of 10% of the susceptible piping. 

No IGSCC inspection is recommended for plants that meet all three criteria or that meet 

criterion (a) and piping is made of material that is resistant to IGSCC. 

2. Preventive Actions: The comprehensive program outlined in NUREG-0313 and 

NRC GL 88-01 addresses improvements in all three elements that, in combination, cause 

SCC or IGSCC. These elements are a susceptible (sensitized) material, a significant tensile 

stress, and an aggressive environment. The program delineated in NUREG-0313 and NRC 

GL 88-01 includes recommendations regarding selection of materials that are resistant to 

sensitization, use of special processes that reduce residual tensile stresses, and monitoring 

and maintenance of coolant chemistry. The resistant materials are used for new and 

replacement components and include low-carbon grades of austenitic SS and weld metal, 

with a maximum carbon of 0.035 wt.% and a minimum ferrite of 7.5% in weld metal and cast 

austenitic stainless steel (CASS). Inconel 82 is the only commonly used nickel-base weld 

metal considered to be resistant to SCC; other nickel-alloys, such as Alloy 600, are 

evaluated on an individual basis. Special processes are used for existing as well as new 

and replacement components. These processes include solution heat treatment, heat sink 

welding, induction heating, and mechanical stress improvement. 

The program delineated in NUREG-0313 and NRC GL 88-01 varies depending on the plant

specific reactor water chemistry to mitigate SCC or IGSCC.

April 2001 Xl M-81 NUREG-1801
3. Parameters Monitored/Inspected: The aging management program (AMP) monitors SCC 

or IGSCC of austenitic SS piping by detection and sizing of cracks by implementing the inspection guidelines delineated in the NRC screening criteria for the RWCU piping outboard of isolation valves. The following schedules are followed: 

Schedule A: No inspection is required for plants that meet all three criteria set forth above, 

or if they meet only criterion (a). Piping is made of material that is resistant to IGSCC, as 

described above in preventive actions. 

Schedule B: For plants that meet only criterion (a): Inspect at least 2% of the welds or two welds every refueling outage, whichever sample is larger. 

Schedule 0. For plants that do not meet criterion (a): Inspect at least 10% of the welds 

every refueling outage. 

4. Detection of Aging Effects: The extent, method, and schedule of the inspection and test techniques delineated in the NRC inspection criteria for RWCU piping and NRC GL 88-01 

are designed to maintain structural integrity and to detect aging effects before the loss of intended function of austenitic SS piping and fittings. Guidelines for the inspection schedule, methods, personnel, sample expansion, and leak detection guidelines are based on the 

guidelines of NRC GL 88-01. 

The NRC GL 88-01 recommends that the detailed inspection procedure, equipment, and 

examination personnel be qualified by a formal program approved by the NRC. Inspection 

can reveal crack initiation and growth and leakage of coolant. The extent and frequency of inspections recommended by the program are based on the condition of each weld (e.g., whether the weldments were made from IGSCC-resistant material, whether a stress 

improvement process was applied to a weldment to reduce the residual stresses, and how 

the weld was repaired if it had been cracked). 

5. Monitoring and Trending: The extent and schedule for inspection in accordance with the recommendations of NRC GL 88-01 provide timely detection of cracks and leakage of 

coolant. Based on inspection results, NRC GL 88-01 provides guidelines for additional 

samples of welds to be inspected when one or more cracked welds are found in a weld 

category. 

6. Acceptance Criteria: The NRC GL 88-01 recommends that any indication detected be 

evaluated in accordance with the requirements of ASME Section Xl, Subsection IWB-3640 

(1995 edition through the 1996 addenda). 

7. Corrective Actions- The guidance for weld overlay repair, stress improvement, or replacement is provided in NRC GL 88-01. As discussed in the appendix to this report, the 

staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing corrective actions. 

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 to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing the confirmation 

process and administrative controls. 

9. Administrative Controls: See Item 8, above.

NUREG-1801 XI M-82 April 2001
10. Operating Experience: The IGSCC has occurred in small- and large-diameter boiling water 

reactor (BWR) piping made of austenitic SSs or nickel alloys. The comprehensive program 

outlined in NRC GL 88-01 and NUREG-0313 addresses improvements in all elements that 

cause SCC or IGSCC (e.g., susceptible material, significant tensile stress, and an 

aggressive environment) and is effective in managing IGSCC in austenitic SS piping in the 

RWCU system. 

References 

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 1995 edition through the 1996 addenda, American 

Society of Mechanical Engineers, New York, NY. 

BWRVIP-29 (EPRI TR-1 03515), BWR Vessel and Internals Project, BWR Water Chemistry 

Guidelines-1993 Revision, Normal and Hydrogen Water Chemistry, Electric Power 

Research Institute, Palo Alto, CA, February 1994. 

Letter from Joseph W. Shea, U.S. Nuclear Regulatory Commission, to George A. Hunter, Jr., 

PECO Energy Company, Reactor Water Cleanup (RWCU) System Weld Inspections at 

Peach Bottom Atomic Power Station, Units 2 and 3 (TAC Nos. M92442 and M92443), 

September 15, 1995. 

NRC Generic Letter 88-01, NRC Position on IGSCC in BWR Austenitic Stainless Steel Piping, 

U.S. Nuclear Regulatory Commission, January 25, 1988. 

NUREG-0313, Rev. 2, Technical Report on Material Selection and Processing Guidelines for 

BWR Coolant Pressure Boundary Piping, W. S. Hazelton and W. H. Koo, U.S. Nuclear 

Regulatory Commission, 1988.

April 2001 XI M-83 NUREG-1801
XI.M26 FIRE PROTECTION

Program Description 

For operating plants, the fire protection aging management program (AMP) includes a fire 

barrier inspection program and a diesel-driven fire pump inspection program. The fire barrier 

inspection program requires periodic visual inspection of fire barrier penetration seals, fire 

barrier walls, ceilings, and floors, and periodic visual inspection and functional tests of fire rated 

doors to ensure that their operability is maintained. The diesel-driven fire pump inspection 

program requires that the pump be periodically tested to ensure that the fuel supply line can 

perform the intended function. The AMP also includes periodic inspection and test of 

halon/carbon dioxide fire suppression system. 

Evaluation and Technical Basis 

1. Scope of Program: For operating plants, the AMP manages the aging effects on the 

intended function of the penetration seals, fire barrier walls, ceilings, and floors, and all fire 

rated doors (automatic or manual) that perform a fire barrier function. It also manages the 

aging effects on the intended function of the fuel supply line. The AMP also includes 

management of the aging effects on the intended function of the halon/carbon dioxide fire 

suppression system. 

2. Preventive Actions: For operating plants, the fire hazard analysis assesses the fire 

potential and fire hazard in all plant areas. It also specifies measures for fire prevention, fire 

detection, fire suppression, and fire containment and alternative shutdown capability for 

each fire area containing structures, systems, and components important to safety. 

3. Parameters Monitored/Inspected: Visual inspection of 10% of each type of penetration 

seal is performed during walkdowns carried out at least once every refueling outage. These 

inspections examine any sign of degradation such as cracking, seal separation from walls 

and components, separation of layers of material, rupture and puncture of seals which are 

directly caused by increased hardness and shrinkage of seal material due to weathering. Visual inspection of the fire barrier walls, ceilings, and floors examines any sign of 

degradation such as cracking, spalling, and loss of material caused by freeze-thaw, 

chemical attack, and reaction with aggregates. Hollow metal fire doors are visually inspected at least once bi-monthly for holes in the skin of the door. Fire door clearances are 

also checked at least once bi-monthly as part of an inspection program. Function tests of 

fire doors are performed daily, weekly, or monthly (which maybe plant specific) to verify the 

operability of automatic hold-open, release, closing mechanisms, and latches. 

The diesel-driven fire pump is under observation during performance tests such as flow and 

discharge tests, sequential starting capability tests, and controller function tests for 

detecting any degradation of the fuel supply line. 

Periodic visual inspection and function test at least once every six months examines the 

signs of degradation of the halon/carbon dioxide fire suppression system. The suppression 

agent charge pressure is monitored in the test. Material conditions that may affect the 

performance of the system, such as corrosion, mechanical damage, or damage to dampers, 

are observed during these tests. Inspections performed at least once every month verify 

that the extinguishing agent supply valves are open and the system is in automatic mode. 

NUREG-1801 Xl M-84 April 2001
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 

(VT-1 or equivalent) of 10% of each type of seal in walkdowns is performed at least once 

every refueling outage. If any sign of degradation is detected within that 10%, the scope of 

the inspection and frequency is expanded to ensure timely detection of increased hardness 

and shrinkage of the penetration seal before the loss of the component intended function. 

Visual inspection (VT-1 or equivalent) of the fire barrier walls, ceilings, and floors performed 

in walkdown at least once every refueling outage ensures timely detection for concrete 

cracking, spalling, and loss of material. Visual inspection (VT-3 or equivalent) detects any 

sign of degradation of the fire door such as wear and missing parts. Function tests promptly 

detect deficiencies in operational conditions. Periodic visual inspection and function tests 

detect degradation of the fire doors before there is a loss of intended function. 

Periodic tests performed at least once every refueling outage, such as flow and discharge 

tests, sequential starting capability tests, and controller function tests performed on diesel

driven fire pump ensure fuel supply line performance. The performance tests detect 

degradation of the fuel supply lines before the loss of the component intended function. 

In the test of the halon/carbon dioxide fire suppression system, the suppression agent 

charge pressure is verified to be within in the normal band. Visual inspection detects any 

sign of degradation, such as corrosion, mechanical damage, or damage to dampers. The 

periodic function test and inspection performed at least once every six months detects 

degradation of the halon/carbon dioxide fire suppression system before the loss of the 

component intended function. The monthly inspection ensures that the extinguishing agent 

supply valves are open and the system is in automatic mode. 

5. Monitoring and Trending: The aging effects of weathering on fire barrier penetration seals 

are detectable by visual inspection and, based on operating experience, visual inspections 

performed at least once every refueling outage to detect any sign of degradation of fire 

barrier penetration seals prior to loss of the intended function. 

Concrete cracking, spalling, and loss of material are detectable by visual inspection and, 

based on operating experience, visual inspection performed at least once every refueling 

outage detects any sign of degradation of the fire barrier walls, ceilings, and floors before 

there is a loss of the intended function. Wear, missing parts, or holes in the fire door are 

detectable by visual inspection and, based on operating experience, the visual inspection 

and function test performed bi-monthly which detects degradation of the fire doors prior to 

loss of the intended function. 

The performance of the fire pump is monitored during the periodic test to detect any 

degradation in the fuel supply lines. Periodic testing provides data (e.g., pressure) for 

trending necessary. 

The performance of the halon/carbon dioxide fire suppression system is monitored during 

the periodic test to detect any degradation in the system. These periodic tests provide data 

necessary for trending. 

6. Acceptance Criteria: Inspection results are acceptable if there are no visual indications of 

cracking, separation of seals from walls and components, separation of layers of material, 

or ruptures or punctures of seals, no visual indications of concrete cracking, spalling and 

loss of material of fire barrier walls, ceilings, and floors, no visual indications of missing 

parts, holes, and wear and no deficiencies in the functional tests of fire doors. No corrosion

April 2001 XI M-85 NUREG-1801
is acceptable in the fuel supply line for the diesel-driven fire pump. Also, any signs of 

corrosion and mechanical damage of the halon/carbon dioxide fire suppression system are 

not acceptable. 

7. Corrective Actions: For fire protection structures and components identified within scope that are subject to an aging management review for license renewal, the applicant is to 

expand the scope of the 10 CFR Part 50, Appendix B, program to include these in-scope 

structures and components to address corrective actions, confirmation process, and 

administrative controls for aging management during the period of extended operation. This 

commitment is documented in the final safety analysis report (FSAR) supplement in 

accordance with 10 CFR 54.21(d). As discussed in the appendix to this report, the staff 

finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address corrective 

actions, confirmation process, and administrative controls. 

8. Confirmation Process: See Item 7, above. 

9. Administrative Controls: See Item 7, above. 

10. Operating Experience: Silicone foam fire barrier penetration seals have experienced splits, 

shrinkage, voids, lack of fill, and other failure modes (IN 88-56, IN 94-28, and IN 97-70). 

Degradation of electrical racing way fire barrier such as small holes, cracking, and unfilled 

seals are found on routine walkdown (IN 91-47 and GL 92-08). Fire doors have experienced 

wear of the hinges and handles. Operating experience with the use of this AMP has shown 

that no corrosion-related problem has been reported for the fuel supply line, pump casing of 

the diesel-driven fire pump, and the halon/carbon dioxide suppression system. No 

significant aging related problems have been reported of fire protection systems, 

emergency breathing and auxiliary equipment, and communication equipment. 

References 

NRC Generic Letter 92-08, Thermo-Lag 330-1 Fire Barrier, December 17, 1992. 

NRC Information Notice 88-56, Potential Problems with Silicone Foam Fire Barrier Penetration 

Seals, August 14, 1988. 

NRC Information Notice 91-47, Failure of Thermo-Lag Fire Barrier Material to Pass Fire 

Endurance Test, August 6, 1991. 

NRC Information Notice 94-28, Potential problems with Fire-Barrier Penetration Seals, April 5, 

1994. 

NRC Information Notice 97-70, Potential problems with Fire Barrier Penetration Seals, 

September 19, 1997.

NUREG-1 801 Xl M-86 April 2001
XI.M27 FIRE WATER SYSTEM

Program Description 

This aging management program applies to water-based fire protection systems that consist of 

sprinklers, nozzles, fittings, valves, hydrants, hose stations, standpipes, water storage tanks, 

and aboveground and underground piping and components that are tested in accordance with 

the applicable National Fire Protection Association (NFPA) codes and standards. Such testing 

assures the minimum functionality of the systems. Also, these systems are normally maintained 

at required operating pressure and monitored such that loss of system pressure is immediately 

detected and corrective actions initiated. In addition to NFPA codes and standards, which do 

not currently contain programs to manage aging, portions of the fire protection sprinkler system, which are not routinely subjected to flow, are to be subjected to full flow tests at the maximum 

design flow and pressure before the period of extended operation (and at not more than 5-year intervals thereafter). In addition, a sample of sprinkler heads is to be inspected by using the 

guidance of NFPA 25, Section 2.3.3.1. This NFPA section states that "where sprinklers have 

been in place for 50 years, they shall be replaced or representative samples from one or more 

sample areas shall be submitted to a recognized testing laboratory for field service testing." It 

also contains guidance to perform this sampling every 10 years after the initial field service 

testing. Finally, portions of fire protection suppression piping located aboveground and exposed 

to water are disassembled and visually inspected internally once every refueling outage. The 

purpose of the full flow testing and internal visual inspections is to ensure that corrosion, 

microbiological influenced corrosion (MIC), or biofouling aging effects are managed such that 

the system function is maintained. 

Evaluation and Technical Basis 

1. Scope of Program: The aging management program focuses on managing loss of material 

due to corrosion, MIC, or biofouling of carbon steel and cast-iron components in fire 

protection systems exposed to water. Hose station and standpipe are considered as piping 

in the AMP. 

2. Preventive Actions: To ensure no significant corrosion, MIC, or biofouling has occurred in 

water-based fire protection systems, periodic flushing, system performance testing, and 

inspections are conducted. 

3. Parameters Monitored/nspected: Loss of material due to corrosion and biofouling could 

reduce wall thickness of the fire protection piping system and result in system failure. 

Therefore, the parameters monitored are the system's ability to maintain pressure and 

internal system corrosion conditions. The NRC GL 89-13 recommends periodic flow testing of infrequently used loops of the fire water system at the maximum design flow to ensure 

that the system maintains its intended function. 

4. Detection of Aging Effects: Fire protection system testing is performed to assure required 

pressures. Internal inspections of aboveground fire protection piping and the smaller 

diameter fire suppression piping are performed on system components (when they are 

disassembled) to identify evidence of loss of material due to corrosion. Repair and 

replacement actions are initiated as necessary. Continuous system pressure monitoring, periodic system flow testing performed, and internal inspections of aboveground piping are 

effective means to ensure that corrosion and biofouling are not occurring and the system's intended function is maintained. In addition, general requirements of existing fire protection 

programs include testing and maintenance of fire detection and suppression systems and

April 2001 XI M-87 NUREG-1801
surveillance procedures to ensure that fire detectors, as well as fire suppression systems 

and components, are operable. 

Visual inspection of yard fire hydrants performed once every six months ensures timely 

detection of signs of degradation, such as corrosion. Fire hydrant hose hydrostatic tests, 

gasket inspections, and fire hydrant flow tests, performed annually, ensure that fire hydrants 

can perform their intended function and provide opportunities for degradation to be detected 

before a loss of intended function can occur. 

Sprinkler systems are inspected once every refueling outage 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 NFPA codes 

and standards. Degradation identified by internal inspection is evaluated. 

6. Acceptance Criteria: The acceptance criteria are (a) the ability of a fire protection system 

to maintain required pressure, (b) no unacceptable signs of degradation observed during 

visual assessment of internal system conditions, and (c) that no biofouling exists in the 

sprinkler systems that could cause corrosion in the sprinkler heads. 

7. Corrective Actions: For fire water systems and components identified within scope that are 

subject to an aging management review for license renewal, the applicant is to expand the 

scope of the 10 CFR Part 50, Appendix B, program to include these in-scope systems and 

components to address corrective actions, confirmation process, and administrative controls 

for aging management during the period of extended operation. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address corrective actions, confirmation process, and administrative controls. 

8. Confirmation Process: See Item 7, above. 

9. Administrative Controls: See Item 7, above. 

10. Operating Experience: Water-based fire protection systems designed, inspected, tested 

and maintained in accordance with the NFPA minimum standards have demonstrated 

reliable performance. 

References 

NFPA 25: Inspection, Testing and Maintenance of Water-Based Fire Protection Systems, 1998 

Edition. 

NRC Generic Letter 89-13, Service Water System Problems Affecting Safety-Related 

Equipment, July 18, 1989. 

NUREG-1801 XI M-88 April 2001
XI.M28 BURIED PIPING AND TANKS SURVEILLANCE

Program Description 

The program includes surveillance and preventive measures to mitigate corrosion by protecting the external surface of buried carbon steel piping and tanks. Surveillance and preventive 

measures are in accordance with standard industry practice, based on NACE Standards 

RP-0285-95 and RP-01 69-96, and include external coatings, wrappings, and cathodic 

protection systems. 

Evaluation and Technical Basis 

1. Scope of Program: The program relies on preventive measures, such as coating, 

wrapping, and cathodic protection, and surveillance, based on NACE Standard RP-0285-95 

and NACE Standard RP-01 69-96, to manage the effects of corrosion on the intended 

function of buried tanks and piping, respectively. 

2. Preventive Actions: In accordance with industry practice, underground piping and tanks 

are coated during installation with a protective coating system, such as coal tar enamel with 

a fiberglass wrap and a kraft paper outer wrap, a polyolif in tape coating, or a fusion bonded 

epoxy coating to protect the piping from contacting the aggressive soil environment. A 

cathodic protection system is used to mitigate corrosion where pinholes in the coating allow 

the piping or components to be in contact with the aggressive soil environment. The 

cathodic protection imposes a current from an anode onto the pipe or tank to stop corrosion 

from occurring at defects in the coating. 

3. Parameters Monitored/Inspected: The effectiveness of the coatings and cathodic 

protection system, per standard industry practice, is determined by measuring coating 

conductance, by surveying pipe-to-soil potential, and by conducting bell hole examinations 

to visually examine the condition of the coating. 

4. Detection of Aging Effects: Coatings and wrapping can be damaged during installation or 

while in service and the cathodic protection system is relied upon to avoid any corrosion at 

the damaged locations. Degradation of the coatings and wrapping during service will result 

in the requirement for more current from the cathodic protection rectifier in order to maintain 

the proper cathodic protect potentials. Any increase in current requirements is an indication 

of coating and wrapping degradation. A close interval pipe-to-soil potential survey can be 

used to locate the locations where degradation has occurred. 

5. Monitoring and Trending: Monitoring the coating conductance versus time or the current 

requirement versus time provide an indication of the condition of the coating and cathodic 

protection system when compared to predetermined values. 

6. Acceptance Criteria: In accordance with accepted industry practice, per NACE Standard 

RP-0285-95 and NACE Standard RP-01 69-96, the assessment of the condition of the 

coating and cathodic protection system is to be conducted on an annual basis and 

compared to predetermined values. 

7. Corrective Actions: The site corrective actions program, quality assurance (QA) 

procedures, site review and approval process, and administrative controls are implemented 

in accordance with the requirements of 10 CFR Part 50, Appendix B. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B,

April 2001 Xl M-89 NUREG-1801
acceptable in addressing the corrective actions, confirmation process, and administrative 

controls. 

8. Confirmation Process: See Item 7, above. 

9. Administrative Controls: See Item 7, above. 

10. Operating Experience: Corrosion pits from the outside diameter have been discovered in 

buried piping with far less than 60 years of operation. Buried pipe that is coated and 

cathodically protected is unaffected after 60 years of service. Accordingly, operating 

experience from application of the NACE standards on non-nuclear systems demonstrates 

the effectiveness of this program. 

References 

NACE Standard RP-01 69-96, Control of External Corrosion on Underground or Submerged 

Metallic Piping Systems, 1996. 

NACE Standard RP-0285-95, Corrosion Control of Underground Storage Tank Systems by 

Cathodic Protection, Approved March 1985, revised February 1995.

NUREG-1801 XI M-90 April 2001
XI.M29 ABOVEGROUND CARBON STEEL TANKS

Program Description 

The program includes preventive measures to mitigate corrosion by protecting the external 

surface of carbon steel tanks with paint or coatings in accordance with standard industry 

practice. The program also relies on periodic system walkdowns to monitor degradation of the 

protective paint or coating. However, for storage tanks supported on earthen or concrete 

foundations, corrosion may occur at inaccessible locations, such as the tank bottom. 

Accordingly, verification of the effectiveness of the program is to be performed to ensure that 

significant degradation in inaccessible locations is not occurring and the component intended 

function will be maintained during the extended period of operation. For reasons set forth 

below, an acceptable verification program consists of thickness measurement of the tank 

bottom surface. 

Evaluation and Technical Basis 

1. Scope of Program: The program consists of (a) preventive measures to mitigate corrosion 

by protecting the external surfaces of carbon steel tanks protected with paint or coatings 

and (b) periodic system walkdowns to manage the effects of corrosion on the intended 

function of these tanks. Plant walkdowns cover the entire outer surface of the tank up to its 

surface in contact with soil or concrete. 

2. Preventive Actions: In accordance with industry practice, tanks are coated with protective 

paint or coating to mitigate corrosion by protecting the external surface of the tank from 

environmental exposure. Sealant or caulking at the interface edge between the tank and 

concrete or earthen foundation mitigates corrosion of the bottom surface of the tank by 

preventing water and moisture from penetrating the interface, which would lead to corrosion 

of the bottom surface. 

3. Parameters Monitored/Inspected: The aging management program (AMP) utilizes 

periodic plant system walkdowns to monitor degradation of coatings, sealants, and caulking 

because it is a condition directly related to the potential loss of materials. 

4. Detection of Aging Effects: Degradation of exterior carbon steel surfaces cannot occur 

without degradation of paint or coatings on the outer surface and of sealant and caulking at 

the interface between the component and concrete. Periodic system walkdowns to confirm 

that the paint, coating, sealant, and caulking are intact is an effective method to manage the 

effects of corrosion on the external surface of the component. However, corrosion may 

occur at inaccessible locations, such as the tank bottom surface, and thickness 

measurement of the tank bottom is to be taken to ensure that significant degradation is not 

occurring and the component intended function will be maintained during the extended 

period of operation. 

5. Monitoring and Trending: The effects of corrosion of the aboveground external surface 

are detectable by visual techniques. Based on operating experience, plant system 

walkdowns during each outage provide for timely detection of aging effects. The effects of 

corrosion of the underground external surface are detectable by thickness measurement of 

the tank bottom and are monitored and trended if significant material loss is detected. 

6. Acceptance Criteria: Any degradation of paint, coating, sealant, and caulking is reported 

and will require further evaluation. Degradation consists of cracking, flaking, or peeling of

April 2001 Xi M-91 NUREG-1 801
paint or coatings, and drying, cracking or missing sealant and caulking. Thickness 

measurements of the tank bottom are evaluated against the design thickness and corrosion 

allowance. 

7. Corrective Actions: The site corrective actions program, quality assurance (QA) 

procedures, site review and approval process, and administrative controls are implemented 

in accordance with 10 CFR Part 50, Appendix B. As discussed in the appendix to this 

report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in 

addressing the corrective actions, confirmation process, and administrative controls. 

8. Confirmation Process: See Item 7, above. 

9. Administrative Controls: See Item 7, above. 

10. Operating Experience: Coating degradation, such as flaking and peeling, has occurred in 

safety-related systems and structures (Nuclear Regulatory Commission [NRCI Generic 

Letter [GL] 98-04). Corrosion damage near the concrete-metal interface and sand-metal 

interface has been reported in metal containments (NRC Information Notice [IN] 89-79, 

Supplement 1, and NRC IN 86-99, Supplement 1). 

References 

NRC Generic Letter 98-04, Potential for Degradation of the Emergency Core Cooling System 

and the Containment Spray System after a Loss-of-Coolant Accident Because of 

Construction and Protective Coating Deficiencies and Foreign Material in Containment, 

U.S. Nuclear Regulatory Commission, July 14, 1998. 

NRC Information Notice 86-99, Degradation of Steel Containments, U.S. Nuclear Regulatory 

Commission, December 8, 1986. 

NRC Information Notice 86-99, Supplement 1, Degradation of Steel Containments, 

U.S. Nuclear Regulatory Commission, February 14, 1991. 

NRC Information Notice 89-79, Degraded Coatings and Corrosion of Steel Containment Vessel, 

U.S. Nuclear Regulatory Commission, December 1, 1989. 

NRC Information Notice 89-79, Supplement 1, Degraded Coatings and Corrosion of Steel 

Containment Vessel, U.S. Nuclear Regulatory Commission, June 29, 1990.

NUREG-1 801 Xl M-92 April 2001
XI.M30 FUEL OIL CHEMISTRY

Program Description 

The program includes (a) surveillance and maintenance procedures to mitigate corrosion and 

(b) measures to verify the effectiveness of an aging management program (AMP) and confirm 

the absence of an aging effect. Fuel oil quality is maintained by monitoring and controlling fuel 

oil contamination in accordance with the guidelines of the American Society for Testing 

Materials (ASTM) Standards D 1796, D 2276, D 2709, and D 4057. Exposure to fuel oil 

contaminants, such as water and microbiological organisms, is minimized by periodic draining 

or cleaning of tanks and by verifying the quality of new oil before its introduction into the storage 

tanks. However, corrosion may occur at locations in which contaminants may accumulate, such 

as tank bottoms. Accordingly, the effectiveness of the program is verified to ensure that 

significant degradation is not occurring and the component intended function will be maintained 

during the extended period of operation. Thickness measurement of tank bottom surfaces is an 

acceptable verification program. 

Evaluation and Technical Basis 

1. Scope of Program: The program is focused on managing the conditions that cause 

general, pitting, and microbiologically influenced corrosion (MIC) of the diesel fuel tank 

internal surfaces. The program serves to reduce the potential of exposure of the tank 

internal surface to fuel oil contaminated with water and microbiological organisms. 

2. Preventive Actions: The quality of fuel oil is maintained by additions of biocides to 

minimize biological activity, stabilizers to prevent biological breakdown of the diesel fuel, 

and corrosion inhibitors to mitigate corrosion. Periodic cleaning of a tank allows removal of 

sediments, and periodic draining of water collected at the bottom of a tank minimizes the 

amount of water and the length of contact time. Accordingly, these measures are effective 

in mitigating corrosion inside diesel fuel oil tanks. Coatings, if used, prevent or mitigate 

corrosion by protecting the internal surfaces of the tank from contact with water and 

microbiological organisms. 

3. Parameters Monitored/Inspected: The AMP monitors fuel oil quality and the levels of 

water and microbiological organisms in the fuel oil, which cause the loss of material of the 

tank internal surfaces. The ASTM Standard D 4057 is used for guidance on oil sampling. 

The ASTM Standards D 1796 and D 2709 are used for determination of water and sediment 

contamination in diesel fuel. For determination of particulates, modified ASTM D 2276, 

Method A, is used. The modification consists of using a filter with a pore size of 3.0 Aim, 

instead of 0.8 jim. These are the principal parameters relevant to tank structural integrity. 

4. Detection of Aging Effects: Degradation of the diesel fuel oil tank cannot occur without 

exposure of the tank internal surfaces to contaminants in the fuel oil, such as water and 

microbiological organisms. Compliance with diesel fuel oil standards in item 3, above, and 

periodic multilevel sampling provide assurance that fuel oil contaminants are below 

acceptable levels. Internal surfaces of tanks that are drained for cleaning are visually 

inspected to detect potential degradation. However, corrosion may occur at locations in 

which contaminants may accumulate, such as a tank bottom, and an ultrasonic thickness 

measurement of the tank bottom surface ensures that significant degradation is not 

occurring.

April 2001 XI M-93 NUREG-1801
5. Monitoring and Trending: Water and biological activity or particulate contamination 

concentrations are monitored and trended at least quarterly. Based on industry operating 

experience, quarterly sampling and analysis of fuel oil provide for timely detection of 

conditions conducive to corrosion of the internal surface of the diesel fuel oil tank before the 

potential loss of its intended function. 

6. Acceptance Criteria: The ASTM Standard D 4057 is used for guidance on oil sampling. 

The ASTM Standards D 1796 and D 2709 are used for guidance on the determination of 

water and sediment contamiination in diesel fuel. Modified ASTM D 2276, Method A is used 

for determination of particulates. The modification consists of using_ a filter with a pore size 

of 3.0 gm, instead of 0.8 gim. 

7. Corrective Actions: Specific corrective actions are implemented in accordance with the 

plant quality assurance (QA) program. For example, corrective actions are taken to prevent 

recurrence when the specified limits for fuel oil standards are exceeded or when water is 

drained during periodic surveillance. Also, when the presence of biological activity is 

confirmed, a biocide is added to fuel oil. As discussed in the appendix to this report, the 

staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing 

corrective actions. 

8. Confirmation Process: Site QA procedures, review and approval processes, and 

administrative controls are implemented in accordance with the requirements of 10 CFR 

Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable in addressing the confirmation 

process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: The operating experience at some plants has included 

identification of water in the fuel, particulate contamination, and biological fouling. However, 

no instances of fuel oil system component failures attributed to contamination have been 

identified. 

References 

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. 

ASTM D 2276-00, Standard Test Method for Particulate Contaminant in Aviation Fuel by Line 

Sampling, American Society for Testing Materials, West Conshohocken, PA. 

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. 

ASTM D 4057-95(2000), Standard Practice for Manual Sampling of Petroleum and Petroleum 

Products, American Society for Testing Materials, West Conshohocken, PA.

NUREG-1 801 XI M-94 April 2001
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 10 7 n/cm2 (E >1 MeV), or that 

reactor vessel beltline materials be monitored by a surveillance program to meet the American 

Society for Testing and Materials (ASTM) E 185 Standard. However, the surveillance program 

in ASTM E 185 is based on plant operation during the current license term, and additional 

surveillance capsules may be needed for the period of extended operation. Alternatively, an 

integrated surveillance program for the period of extended operation may be considered for a 

set of reactors that have similar design and operating features in accordance with 10 CFR 

Part 50, Appendix H, Paragraph II.C. Additional surveillance capsules may also be needed for 

the period of extended operation for this alternative. 

The existing reactor vessel material surveillance program provides sufficient material data and 

dosimetry to monitor irradiation embrittlement at the end of the period of extended operation, 

and to determine the need for operating restrictions on the inlet temperature, neutron spectrum, 

and neutron flux. If surveillance capsules are not withdrawn during the period of extended 

operation, operating restrictions are to be established to ensure that the plant is operated under 

the conditions to which the surveillance capsules were exposed. 

An acceptable reactor vessel surveillance program consists of the following: 

1. The extent of reactor vessel embrittlement for upper-shelf energy and pressure-temperature 

limits for 60 years is projected in accordance with the Nuclear Regulatory Commission 

(NRC) Regulatory Guide (RG) 1.99, Rev. 2, "Radiation Embrittlement of Reactor Vessel 

Materials." When using NRC RG 1.99, Rev. 2, an applicant has a choice of the following: 

a. Neutron Embrittlement Using Chemistry Tables 

An applicant may use the tables in NRC RG 1.99, Rev. 2, to project the extent of reactor 

vessel neutron embrittlement for the period of extended operation based on material 

chemistry and neutron fluence. This is described as Regulatory Position 1 in the RG. 

b. Neutron Embrittlement Using Surveillance Data 

When credible surveillance data 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 operating term. The applicant may have a plant-specific program or an integrated surveillance program during the period of 

extended operation to collect additional data. 

2. An applicant that determines embrittlement by using the NRC RG 1.99, Rev. 2, tables (see 

item 1 [a], above) uses the applicable limitations in Regulatory Position 1.3 of the RG. The 

limits are based on material properties, temperature, material chemistry, and fluence. 

3. An applicant that determines embrittlement by using surveillance data (see item 1 [b], above) 

defines the applicable bounds of the data, such as cold leg operating temperature and 

neutron fluence. These bounds are specific for the referenced surveillance data. For

April 2001 XI M-95 NUREG-1801
example, the plant-specific data could be collected within a smaller temperature range than 

that in the RG. 

4. All pulled and tested capsules, unless discarded before August 31, 2000, are placed in 

storage. (Note: These specimens are saved for future reconstitution use, in case the 

surveillance program is reestablished.) 

5. If an applicant has a surveillance program that consists of capsules with a projected fluence 

of less than the 60-year fluence at the end of 40 years, at least one capsule is to remain in 

the reactor vessel and is tested during the period of extended operation. The applicant may 

either delay withdrawal of the last capsule or withdraw a standby capsule during the period 

of extended operation to monitor the effects of long-term exposure to neutron irradiation. 

6. If an applicant has a surveillance program that consists of capsules with a projected fluence 

exceeding the 60-year fluence at the end of 40 years, the applicant withdraws one capsule 

at an outage in which the capsule receives a neutron fluence equivalent to the 60-year fluence and tests the capsule in accordance with the requirements of ASTM E 185. Any 

capsules that are left in the reactor vessel provide meaningful metallurgical data (i.e., the 

capsule fluence does not significantly exceed the vessel fluence at an equivalent of 

60 years). For example, in a reactor with a lead factor of three, after 20 years the capsule 

test specimens would have received a neutron exposure equivalent to what the reactor 

vessel would see in 60 years; thus, the capsule is to be removed since further exposure 

would not provide meaningful metallurgical data. Other standby capsules are removed and 

placed in storage. These standby capsules (and archived test specimens available for 

reconstitution) would be available for reinsertion into the reactor if additional license 

renewals are sought (e.g., 80 years of operation). If all surveillance capsules have been 

removed, operating restrictions are to be established to ensure that the plant is operated 

under conditions to which the surveillance capsules were exposed and the exposure 

conditions of the reactor vessel are monitored to ensure that they continue to be consistent 

with those used to project the effects of embrittlement to the end of license. If the reactor 

vessel exposure conditions (neutron flux, spectrum, irradiation temperature, etc.) are 

altered, then the basis for the projection to 60 years is reviewed; and, if deemed 

appropriate, an active surveillance program is re-instituted. Any changes to the reactor 

vessel exposure conditions and the potential need to re-institute a vessel surveillance 

program is discussed with the NRC staff prior to changing the plant's licensing basis. 

7. Applicants without in-vessel capsules use alternative dosimetry to monitor neutron fluence 

during the period of extended operation, as part of the aging management program (AMP) 

for reactor vessel neutron embrittlement. 

8. The applicant may choose to demonstrate that the materials in the inlet, outlet, and safety injection nozzles are not controlling, so that such materials need not be added to the 

material surveillance program for the license renewal term. 

The reactor vessel monitoring program provides that, if future plant operations exceed the 

limitations or bounds specified in item 2 or 3, above (as applicable), such as operating at a 

lower cold leg temperature or higher fluence, the impact of plant operation changes on the 

extent of reactor vessel embrittlement will be evaluated and the NRC will be notified. An 

applicant without capsules in its reactor vessel is to propose reestablishing the reactor vessel 

surveillance program to assess the extent of embrittlement. This program will consist of 

(1) capsules from item 6, above; (2) reconstitution of specimens from item 4, above; and/or 

(3) capsules made from any available archival materials; or (4) some combination of the three

NUREG-1801 XI M-96 April 2001
previous options. This program could be a plant-specific program or an integrated surveillance 

program. 

Evaluation and Technical Basis 

Reactor vessel surveillance programs are plant specific, depending on matters such as the 

composition of limiting materials, availability of surveillance capsules, and projected fluence 

levels. In accordance with 10 CFR Part 50, Appendix H, an applicant submits its proposed 

withdrawal schedule for approval prior to implementation. Thus, further staff evaluation is 

required for license renewal. 

References 

10 CFR Part 50, Appendix H, Reactor Vessel Material Surveillance Program Requirements, 

Office of the Federal Register, National Archives and Records Administration, 2000. 

ASTM E-1 85, Standard Recommended Practice for Surveillance Tests for Nuclear Reactor 

Vessels, American Society for Testing Materials, Philadelphia, PA. 

NRC Regulatory Guide 1.99, Rev. 2, Radiation Embrittlement of Reactor Vessel Materials, 

U.S. Nuclear Regulatory Commission.

April 2001 XI M-97 NUREG-1801
XI.M32 ONE-TIME INSPECTION

Program Description 

The program includes measures to verify the effectiveness of an aging management program (AMP) and confirm the absence of an aging effect. For example, for structures and components that rely on an AMP, such as water chemistry control, this program verifies the effectiveness of 

the AMP by confirming that unacceptable degradation is not occurring and the intended function 

of a component will be maintained during the extended period of operation. One-time inspection is needed to address concerns for the potential long incubation period for certain aging effects 

on structures and components. There are cases where either (a) an aging effect is not 

expected to occur but there is insufficient data to completely rule it out, or (b) an aging effect is 

expected to progress very slowly. For these cases, there is to be confirmation that either the 

aging effect is indeed not occurring, or the aging effect is occurring very slowly as not to affect 

the component or structure intended function. A one-time inspection of the subject component 

or structure is an acceptable option for this verification. One-time inspection is to provide additional assurance that either aging is not occurring or the evidence of aging is so 

insignificant that an aging management program is not warranted. For example, for structures 

and components, such as Class 1 piping with a diameter less than nominal pipe size (NPS) 4 inch that do not receive volumetric examination during inservice inspection, the program confirms that crack initiation and growth due to stress corrosion cracking (SCC) or cyclic loading is not occurring and, therefore, there is no need to manage an aging related 

degradation for the period of extended operation. 

The elements of the program include (a) determination of the sample size based on an 

assessment of materials of fabrication, environment, plausible aging effects, and operating experience; (b) identification of the inspection locations in the system or component based on 

the aging effect; (c) determination of the examination technique, including acceptance criteria 

that would be effective in managing the aging effect for which the component is examined; and 

(d) evaluation of the need for follow-up examinations to monitor the progression of any aging 

degradation. 

When evidence of an aging effect is revealed by a one-time inspection, the routine evaluation of 

the inspection results would identify appropriate corrective actions. 

As set forth below, an acceptable verification program may consist of a one-time inspection of 

selected components and susceptible locations in the system. An alternative acceptable 

program may include routine maintenance or a review of repair records to confirm that these 

components have been inspected for aging degradation and significant aging degradation has 

not occurred and thereby verify the effectiveness of existing AMPs. One-time inspection, or any other action or program, is to be reviewed by the staff on a plant-specific basis. 

Evaluation and Technical Basis 

1. Scope of Program: The program includes measures to verify that unacceptable 

degradation is not occurring, thereby validating the effectiveness of existing AMPs or 

confirming that there is no need to manage aging-related degradation for the period of 

extended operation. The structures and components for which one-time inspection is to 

verify the effectiveness of the AMPs (e.g., water chemistry control, etc.) have been 

identified in the Generic Aging Lessons Learned (GALL) report. Examples include small 

bore piping in the reactor coolant system or the feedwater system components in boiling 

water reactors (BWRs) and pressurized water reactors (PWRs).

NUREG-1801 XI M-98 April 2001
2. Preventive Actions: One-time inspection is an inspection activity independent of methods 

to mitigate or prevent degradation. 

3. Parameters Monitored/Inspected: The program monitors parameters directly related to 

the degradation of a component. Inspection is performed in accordance with the 

requirements of the American Society of Mechanical Engineers (ASME) Code and 

10 CFR 50, Appendix B, by using a variety of nondestructive examination (NDE) methods, 

including visual, volumetric, and surface techniques. 

4. Detection of Aging Effects: The inspection includes a representative sample of the system population, and, where practical, focus on the bounding or lead components most 

susceptible to aging due to time in service, severity of operating conditions, and lowest 

design margin. For small-bore piping, actual inspection locations are based on physical accessibility, exposure levels, NDE techniques, and locations identified in Nuclear 

Regulatory Commission (NRC) Information Notice (IN) 97-46. 

Combinations of NDE, including visual, ultrasonic, and surface techniques, are performed by qualified personnel following procedures consistent with the ASME Code and 10 CFR 50, Appendix B. For small-bore piping less than NPS 4 in., including pipe, fittings, and branch 

connections, a plant-specific destructive examination of replaced piping due to plant modifications or NDE that permits inspection of the inside surfaces of the piping is to be 

conducted to ensure that cracking has not occurred. Follow-up of unacceptable inspection findings includes expansion of the inspection sample size and locations. 

The inspection and test techniques prescribed by the program verify any aging effects 

because these techniques, used by qualified personnel, have been proven effective and 

consistent with staff expectations. With respect to inspection timing, the one-time inspection is to be completed before the end of the current operating license. The applicant may schedule the inspection in such a way as to minimize the impact on plant operations. However, the inspection is not to be scheduled too early in the current operating term, which 

could raise questions regarding continued absence of aging effects prior to and near the 

extended period of operation. 

5. Monitoring and Trending: One-time inspection does not provide specific guidance on 

monitoring and trending. However, evaluation of the appropriateness of the techniques and 

timing of the one-time inspection improve with the accumulation of plant-specific and 

industry-wide experience. 

6. Acceptance Criteria: Any indication or relevant conditions of degradation detected are 

evaluated. The ultrasonic thickness measurements are to be compared to predetermined 

limits, such as design minimum wall thickness. 

7. Corrective Actions: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing the corrective actions, confirmation process, and administrative controls. 

8. Confirmation Process: See Item 7, above. 

9. Administrative Controls: See Item 7, above.

April 2001 XI M-99 NUREG-1801
10. Operating Experience: One-time inspection is a new program to be applied by the 

applicant. The elements that comprise these inspections (e.g., the scope of the inspections 

and inspection techniques) are consistent with years of industry practice and staff 

expectations. 

References 

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2000. 

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, ASME 

Boiler and Pressure Vessel Code, 1995 edition through the 1996 addenda, American 

Society of Mechanical Engineers, New York, NY. 

NRC Information Notice 97-46, Unisolable Crack in High-Pressure Injection Piping, 

U.S. Nuclear Regulatory Commission, July 9, 1997.

NUREG-1801 Xl M-100 April 2001
XI.M33 SELECTIVE LEACHING OF MATERIALS

Program Description 

The program for selective leaching of materials ensures the integrity of the components made 

of cast iron, bronze, brass, and other alloys exposed to a raw water, brackish water, treated 

water, or groundwater environment that may lead to selective leaching of one of the metal 

components. The aging management program (AMP) includes a one-time visual inspection and 

hardness measurement of selected components that may be susceptible to selective leaching 

to determine whether loss of materials due to selective leaching is occurring, and whether the 

process will affect the ability of the components to perform their intended function for the period 

of extended operation. 

Evaluation and Technical Basis 

1. Scope of Program: This AMP determines the acceptability of the components that may be 

susceptible to selective leaching and assess their ability to perform the intended function 

during the period of extended operation. These components include piping, valve bodies 

and bonnets, pump casings, and heat exchanger components. The materials of 

construction for these components may include cast iron, brass, bronze, or aluminum

bronze. These components may be exposed to a raw water, treated water, or groundwater environment. The AMP includes a one-time hardness measurement of a selected set of 

components to determine whether loss of material due to selective leaching is not occurring 

for the period of extended operation. 

The selective leaching process involves the preferential removal of one of the alloying elements from the material, which leads to the enrichment of the remaining alloying 

elements. Dezincification (loss of zinc from brass) and graphitization (removal of iron from 

cast iron) are examples of such a process. Susceptible materials, high temperatures, stagnant-flow conditions, and corrosive environment such as acidic solutions, for example, 

for brasses with high zinc content, and dissolved oxygen, are conducive to selective 

leaching. 

2. Preventive Actions: The one-time visual inspection and hardness measurement is an 

inspection/verification program; thus, there is no preventive action. However, it is noted that 

monitoring of water chemistry to control pH and concentration of corrosive contaminants, 

and treatment with hydrazine to minimize dissolved oxygen in water are effective in reducing 

selective leaching. 

3. Parameters Monitored/Inspected: The visual inspection and hardness measurement is to 

be a one-time inspection. Because selective leaching is a slow acting corrosion process, this measurement is performed just before the beginning of the license renewal period. 

Follow-up of unacceptable inspection findings includes expansion of the inspection sample 

size and location. 

4. Detection of Aging Effects: The one-time visual inspection and hardness measurement 

includes close examination of a select set of components to determine whether selective 

leaching has occurred and whether the resulting loss of strength and/or material will affect 

the intended functions of these components during the period of extended operation. 

Selective leaching generally does not cause changes in dimensions and is difficult to detect. 

However, in certain brasses it causes plug-type dezincification, which can be detected by 

visual inspection. One acceptable procedure is to visually inspect the susceptible

April 2001 XI M-101 NUREG-1801
components closely and conduct Brinell Hardness testing on the inside surfaces of the 

selected set of components to determine if selective leaching has occurred. If it is occurring, 

an engineering evaluation is initiated to determine acceptability of the affected components 

for further service. 

5. Monitoring and Trending: There is no monitoring and trending for the one-time visual 

inspection and hardness measurement. 

6. Acceptance Criteria: Identification of selective leaching will define the need for further 

engineering evaluation before the affected components can be qualified for further service. 

If necessary, the evaluation will include a root cause analysis. 

7. Corrective Actions: Evaluations are performed for test or inspection results that do not 

satisfy established acceptance criteria. The corrective actions program ensures that 

conditions adverse to quality are promptly corrected. If the deficiency is assessed to be 

significantly adverse to quality, the cause of the condition is determined and an action plan is developed to preclude repetition. As discussed in the appendix to this report, the staff 

finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing corrective 

actions. 

8. Confirmation Process: Site quality assurance (QA) procedures, review and approval 

processes, and administrative controls are implemented in accordance with the 

requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable in addressing 

the confirmation process and administrative controls. 

9. Administrative Controls: See Item 8, above. 

10. Operating Experience: One-time inspection is a new program to be applied by the 

applicant. The elements that comprise these inspections (e.g., the scope of the inspections and inspection techniques) are consistent with years of industry practice and staff 

expectations. 

References 

NRC Safety Evaluation Report Related to the License Renewal of Calvert Cliffs Nuclear Power 

Plant, Units 1 and 2, NUREG-1705, December 1999. 

NRC Safety Evaluation Report Related to the License Renewal of Oconee Nuclear Station, 

Units 1, 2, and 3, NUREG-1723, March 2000.

NUREG-1801 Xl M-102 April 2001
XI.M34 BURIED PIPING AND TANKS INSPECTION

Program Description 

The program includes (a) preventive measures to mitigate corrosion, and (b) periodic inspection 

to manage the effects of corrosion on the pressure-retaining capacity of buried carbon steel 

piping and tanks. Preventive measures are in accordance with standard industry practice for 

maintaining external coatings and wrappings. Buried piping and tanks are inspected when they 

are excavated during maintenance and when a pipe is dug up and inspected for any reason. 

As evaluated below, this is an acceptable option to manage buried components, except for the 

program element/attributes of detection of aging effects (regarding inspection frequency) and 

operating experience. Thus, the staff further evaluates an applicant's inspection frequency and 

operating experience with buried components. 

Evaluation and Technical Basis 

1. Scope of Program: The program relies on preventive measures such as coating and 

wrapping and periodic inspection for loss of material caused by corrosion of the external 

surface of buried carbon steel piping and tanks. Loss of material in these components, 

which may be exposed to aggressive soil environment, is caused by general, pitting, and 

crevice corrosion, and microbiologically influenced corrosion (MIC). Periodic inspections are 

performed when the components are excavated for maintenance or for any other reason. 

The scope of the program covers buried components that are within the scope of license 

renewal for the plant. 

2. Preventive Actions: In accordance with industry practice, underground piping and tanks 

are coated during installation with a protective coating system, such as coal tar enamel with 

a fiberglass wrap and a kraft paper outer wrap, a polyolif in tape coating, or a fusion bonded 

epoxy coating to protect the piping from contacting the aggressive soil environment. 

3. Parameters Monitored/Inspected: The program monitors parameters such as coating and 

wrapping integrity that are directly related to corrosion damage of the external surface of 

buried carbon steel piping and tanks. Coatings and wrappings are inspected by visual 

techniques. Any evidence of damaged wrapping or coating defects, such as coating 

perforation, holidays, or other damage, is an indicator of possible corrosion damage to the 

external surface of piping and tanks. 

4. Detection of Aging Effects: Periodic inspection of susceptible locations to confirm that 

coating and wrapping are intact, is an effective method to ensure that corrosion of external 

surfaces has not occurred and the intended function is maintained. Buried piping and tanks 

are inspected when they are excavated during maintenance. The inspections are performed 

in areas with the highest likelihood of corrosion problems, and in areas with a history of 

corrosion problems. However, because the inspection frequency is plant specific and also 

depends on the plant operating experience, the applicant's proposed inspection frequency 

is to be further evaluated for the extended period of operation. 

5. Monitoring and Trending: Results of previous inspections are used to identify susceptible 

locations. 

6. Acceptance Criteria: Any coating and wrapping degradations are reported and evaluated 

according to site corrective actions procedures.

April 2001 Xl M-1 03 NUREG-1801
7. Corrective Actions: The site corrective actions program, quality assurance (QA) procedures, site review and approval process, and administrative controls are implemented in accordance with the requirements of 10 CFR Part 50, Appendix B. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable in addressing the corrective actions, confirmation process, and administrative 

controls. 

8. Confirmation Process: See Item 7, above. 

9. Administrative Controls: See Item 7, above. 

10. Operating Experience: Operating experience shows that the program described here is 

effective in managing corrosion of external surfaces of buried carbon steel components. However, because the inspection frequency is plant specific and also depends on the plant operating experience, the applicant's plant-specific operating experience is further 

evaluated for the extended period of operation. 

References 

None.

NUREG-1 801 Xl M-104 April 2001
XI.S1 ASME SECTION XI, SUBSECTION IWE

Program Description 

10 CFR 50.55a imposes the inservice inspection (ISI) requirements of the American Society of 

Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code, Section XI, 

Subsection IWE for steel containments (Class MC) and steel liners for concrete containments 

(Class CC). The full scope of IWE includes steel containment shells and their integral 

attachments; steel liners for concrete containments and their integral attachments; containment 

hatches and airlocks; seals, gaskets and moisture barriers; and pressure-retaining bolting. This 

evaluation covers both the 1992 Edition with the 1992 Addenda and the 1995 Edition with the 

1996 Addenda, as approved in 10 CFR 50.55a. ASME Code Section XI, Subsection IWE and 

the additional requirements specified in 10 CFR 50.55a(b)(2) constitute an existing mandated 

program applicable to managing aging of steel containments, steel liners of concrete 

containments, and other containment components for license renewal. 

The primary ISI method specified in IWE is visual examination (general visual, VT-3, VT-I). 

Limited volumetric examination (ultrasonic thickness measurement) and surface examination 

(e.g., liquid penetrant) may also be necessary in some instances. Bolt preload is checked by 

either a torque or tension test. IWE specifies acceptance criteria, corrective actions, and 

expansion of the inspection scope when degradation exceeding the acceptance criteria is found. 

The evaluation of 10 CFR 50.55a and Subsection IWE as an aging management program 

(AMP) for license renewal is provided below. 

Evaluation and Technical Basis 

1. Scope of Program: Subsection IWE-1 000 specifies the components of steel containments 

and steel liners of concrete containments within its scope. The components within the scope 

of Subsection IWE are Class MC pressure-retaining components (steel containments) and 

their integral attachments; metallic shell and penetration liners of Class CC containments 

and their integral attachments; containment seals and gaskets; containment pressure

retaining bolting; and metal containment surface areas, including welds and base metal. The 

concrete portions of containments are inspected in accordance with Subsection IWL. 

Subsection IWE exempts the following from examination: 

(1) Components that are outside the boundaries of the containment as defined in the plant

specific design specification; 

(2) Embedded or inaccessible portions of containment components that met the 

requirements of the original construction code of record; 

(3) Components that become embedded or inaccessible as a result of vessel repair or 

replacement, provided IWE-1232 and IWE-5220 are met; and 

(4) Piping, pumps, and valves that are part of the containment system or that penetrate or 

are attached to the containment vessel (governed by IWB or IWC). 

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.

April 2001 XI S-1 NUREG-1 801
2. Preventive Action: No preventive actions are specified; Subsection IWE is a monitoring 

program. 

3. Parameters Monitored or Inspected: Table IWE-2500-1 specifies seven categories for 

examination. The categories, parts examined, and examination methods are presented in 

the following table. The first six examination categories (E-A through E-G) constitute the ISI 

requirements of IWE. Examination category E-P references 10 CFR Part 50, Appendix J 

leak rate testing. Appendix J leak rate testing is evaluated as a separate AMP for license 

renewal in XI.S4.

a The applicable examination method (where multiple methods are 

listed) depends on the particular subcategory within each category. 

b These two categories are optional, in accordance with 

10 CFR 50.55a(b)(2)(ix)(C). 

Table IWE-2500-1 references the applicable section in IWE-3500 that identifies the aging 

effects that are evaluated. The parameters monitored or inspected depend on the particular examination category. For Examination Category E-A, as an example, metallic surfaces 

(without coatings) are examined for evidence of cracking, discoloration, wear, pitting, 

excessive corrosion, arc strikes, gouges, surface discontinuities, dents, and other signs of 

surface irregularities. For Examination Category E-D, seals, gaskets, and moisture barriers 

are examined for wear, damage, erosion, tear, surface cracks, or other defects that may 

violate the leak-tight integrity. 

4. Detection of Aging Effects: The frequency and scope of examination specified in 

10 CFR 50.55a and Subsection IWE ensure that aging effects would be detected before 

they would compromise the design-basis requirements. As indicated in IWE-2400, inservice 

examinations and pressure tests are performed in accordance with one of two inspection 

programs, A or B, on a specified schedule. Under Inspection Program A, there are four 

inspection intervals (at 3, 10, 23, and 40 years) for which 100% of the required examinations

NUREG-1801

CATEGORY PARTS EXAMINED EXAMINATION METHODa 

E-A Containment surfaces General visual, visual VT-3 

E-Bb Pressure retaining welds Visual VT-1 

E-C Containment surfaces Visual VT-1, volumetric 

requiring augmented 

examination 

E-D Seals, gaskets, and Visual VT-3 

moisture barriers 

E-Fb Pressure retaining Surface 

dissimilar metal welds 

E-G Pressure retaining bolting Visual VT-1, bolt torque or 

tension test 

E-P All pressure-retaining 10 CFR Part 50, Appendix J 

components (pressure (containment leak rate 

retaining boundary, testing) 

penetration bellows, 

airlocks, seals, and 

gaskets)

XI S-2 April 2001
must be completed. Within each interval, there are various inspection periods for which a 

certain percentage of the examinations are to be performed to reach 100% at the end of that 

interval. In addition, a general visual examination is performed once each inspection period. 

After 40 years of operation, any future examinations will be performed in accordance with 

Inspection Program B. Under Inspection Program B, starting with the time the plant is placed into service, there is an initial inspection interval of 10 years and successive inspection 

intervals of 10 years each, during which 100% of the required examinations are to be 

completed. An expedited examination of containment is required by 10 CFR 50.55a in which 

an inservice (baseline) examination specified for the first period of the first inspection 

interval for containment is to be performed by September 9, 2001. Thereafter, subsequent 

examinations are performed every 10 years from the baseline examination. Regarding the 

extent of examination, all accessible surfaces receive a visual examination such as General 

Visual, VT-1, or VT-3 (see table in item 3 above). IWE-1240 requires augmented 

examinations (Examination Category E-C) of containment surface areas subject to 

degradation. A VT-1 visual examination is performed for areas accessible from both sides, 

and volumetric (ultrasonic thickness measurement) examination is performed for areas 

accessible from only one side. 

5. Monitoring and Trending: With the exception of inaccessible areas, all surfaces are 

monitored by virtue of the examination requirements on a scheduled basis. When 

component examination results require evaluation of flaws, evaluation of areas of 

degradation, or repairs, and the component is found to be acceptable for continued service, 

the areas containing such flaws, degradation, or repairs shall be reexamined during the next 

inspection period, in accordance with Examination Category E-C. When these 

reexaminations reveal that the flaws, areas of degradation, or repairs remain essentially 

unchanged for three consecutive inspection periods, these areas no longer require 

augmented examination in accordance with Examination Category E-C. 

IWE-2430 specifies that (a) examinations performed during any one inspection that reveal 

flaws or areas of degradation exceeding the acceptance standards are to be extended to 

include an additional number of examinations within the same category approximately equal 

to the initial number of examinations, and (b) when additional flaws or areas of degradation 

that exceed the acceptance standards are revealed, all of the remaining examinations within 

the same category are to be performed to the extent specified in Table IWE-2500-1 for the 

inspection interval. Alternatives to these examinations are provided in 

10 CFR 50.55a(b)(2)(ix)(D). 

6. Acceptance Criteria: IWE-3000 provides acceptance standards for components of steel 

containments and liners of concrete containments. Table IWE-341 0-1 presents criteria to 

evaluate the acceptability of the containment components for service following the 

preservice examination and each inservice examination. This table specifies the acceptance 

standard for each examination category. Most of the acceptance standards rely on visual 

examinations. Areas that are suspect require an engineering evaluation or require correction 

by repair or replacement. For some examinations, such as augmented examinations, 

numerical values are specified for the acceptance standards. For the containment steel shell 

or liner, material loss exceeding 10% of the nominal containment wall thickness, or material 

loss that is projected to exceed 10% of the nominal containment wall thickness before the 

next examination, are documented. Such areas are to be accepted by engineering 

evaluation or corrected by repair or replacement in accordance with IWE-3122.

April 2001 XI S-3 NUREG-1801
7. Corrective Actions: Subsection IWE states that components whose examination results 

indicate flaws or areas of degradation that do not meet the acceptance standards listed in 

Table-341 0-1 are acceptable if an engineering evaluation indicates that the flaw or area of 

degradation is nonstructural in nature or has no effect on the structural integrity of the 

containment. Except as permitted by 10 CFR 50.55a(b)(ix)(D), components that do not meet 

the acceptance standards are subject to additional examination requirements, and the 

components are repaired or replaced to the extent necessary to meet the acceptance 

standards of IWE-3000. For repair of components within the scope of Subsection IWE, IWE

3124 states that repairs and reexaminations are to comply with IWA-4000. IWA-4000 

provides repair specifications for pressure retaining components including metal 

containments and metallic liners of concrete containments. As discussed in the appendix to 

this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to 

address corrective actions. 

8. Confirmation Process: When areas of degradation are identified, an evaluation is 

performed to determine whether repair or replacement is necessary. If the evaluation 

determines that repair or replacement is necessary, Subsection IWE specifies confirmation 

that appropriate corrective actions have been completed and are effective. Subsection IWE 

states that repairs and reexaminations are to comply with the requirements of IWA-4000. 

Reexaminations are conducted in accordance with the requirements of IWA-2200, and the 

recorded results are to demonstrate that the repair meets the acceptance standards set 

forth in Table IWE-341 0-1. As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process. 

9. Administrative Controls: IWA-6000 provides specifications for the preparation, submittal, 

and retention of records and reports. As discussed in the appendix to this report, the staff 

finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address administrative 

controls. 

10. Operating Experience: ASME Section XI, Subsection IWE was incorporated into 

10 CFR 50.55a in 1996. Prior to this time, operating experience pertaining to degradation of 

steel components of containment was gained through the inspections required by 10 CFR 

Part 50, Appendix J and ad hoc inspections conducted by licensees and the Nuclear 

Regulatory Commission (NRC). NRC Information Notice (INs) 86-99, 88-82 and 89-79 

described occurrences of corrosion in steel containment shells. NRC Generic Letter 

(GL) 87-05 addressed the potential for corrosion of boiling water reactor (BWR) Mark I steel 

drywells in the "sand pocket region." More recently, NRC IN 97-10 identified specific 

locations where concrete containments are susceptible to liner plate corrosion. The program 

is to consider the liner plate and containment shell corrosion concerns described in these 

generic communications. Implementation of the ISI requirements of Subsection IWE, in 

accordance with 10 CFR 50.55a, is a necessary element of aging management for steel 

components of steel and concrete containments through the period of extended operation. 

References 

10 CFR Part 50, Appendix J, Primaty Reactor Containment Leakage Testing for Water-Cooled 

Power Reactors, Office of the Federal Register, National Archives and Records 

Administration, 2000.

NUREG-1801 XI S-4 April 2001
10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2000. 

ASME Section Xl, Rules for Inservice Inspection of Nuclear Power Plant Components, 

Subsection IWA, General Requirements, 1992 Edition with 1992 Addenda; 1995 Edition with 

1996 Addenda, The ASME Boiler and Pressure Vessel Code, The American Society of 

Mechanical Engineers, New York, NY. 

ASME Section Xl, Rules for Inservice Inspection of Nuclear Power Plant Components, 

Subsection IWB, Requirements for Class 1 Components of Light-Water Cooled Power 

Plants, 1992 Edition with 1992 Addenda; 1995 Edition with 1996 Addenda, The ASME 

Boiler and Pressure Vessel Code, The American Society of Mechanical Engineers, New 

York, NY. 

ASME Section Xl, Rules for Inservice Inspection of Nuclear Power Plant Components, 

Subsection IWC, Requirements for Class 2 Components of Light-Water Cooled Power 

Plants, 1992 Edition with 1992 Addenda; 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 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, 1992 Edition with 1992 Addenda; 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 Inservice Inspection of Nuclear Power Plant Components, 

Subsection IWL, Requirements for Class CC Concrete Components of Light-Water Cooled 

Power Plants, 1992 Edition with 1992 Addenda; 1995 Edition with 1996 Addenda, The 

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

New York, NY. 

NRC Generic Letter 87-05, Request for Additional Information Assessment of Licensee 

Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywells, U.S. Nuclear 

Regulatory Commission, March 12, 1987. 

NRC Information Notice 86-99, Degradation of Steel Containments, U.S. Nuclear Regulatory 

Commission, December 8, 1986 and Supplement 1, February 14, 1991. 

NRC Information Notice 88-82, Torus Shells with Corrosion and Degraded Coatings in BWR 

Containments, U.S. Nuclear Regulatory Commission, October 14,1988 and Supplement 1, 

May 2, 1989. 

NRC Information Notice 89-79, Degraded Coatings and Corrosion of Steel Containment 

Vessels, U.S. Nuclear Regulatory Commission, December 1, 1989 and Supplement 1, June 

29, 1989. 

NRC Information Notice 97-10, Liner Plate Corrosion in Concrete Containment, U.S. Nuclear 

Regulatory Commission, March 13, 1997.

April 2001 XI S-5 NUREG-1801
Xl.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 Xl, Subsection IWL for 

reinforced and prestressed concrete containments (Class CC). The scope of IWL includes 

reinforced concrete and unbonded post-tensioning systems. This evaluation covers both the 

1992 Edition with the 1992 Addenda and the 1995 Edition with the 1996 Addenda, as approved in 10 CFR 50.55a. ASME Code Section Xl, Subsection IWL and the additional requirements specified in 10 CFR 50.55a(b)(2) constitute an existing mandated program applicable to 

managing aging of containment reinforced concrete and unbonded post-tensioning systems for 

license renewal. 

The primary inspection method specified in IWL is visual examination (VT-3C, VT-1, VT-1 C). For prestressed containments, tendon wires are tested for yield strength, ultimate tensile 

strength, and elongation. Tendon corrosion protection medium is analyzed for alkalinity, water 

content, and soluble ion concentrations. Prestressing forces are measured in selected sample tendons. IWL specifies acceptance criteria, corrective actions, and expansion of the inspection 

scope when degradation exceeding the acceptance criteria is found. 

The evaluation of 10 CFR 50.55a and Subsection IWL as an aging management program 

(AMP) for license renewal is provided below. 

Evaluation and Technical Basis 

1. Scope of Program: Subsection IWL-1 000 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-1 000. Subsection IWL exempts from examination portions of the concrete 

containment that are inaccessible (e.g., concrete covered by liner, foundation material, or 

backfill, or obstructed by adjacent structures or other components). 10 CFR 50.55a(b)(2)(viii) specifies additional requirements for inaccessible areas. It states that the licensee is to 

evaluate the acceptability of concrete in inaccessible areas when conditions exist in 

accessible areas that could indicate the presence of or result in degradation to such 

inaccessible areas. Steel liners for concrete containments and their integral attachments are 

not within the scope of Subsection IWL, but are included within the scope of Subsection 

IWE. 

2. Preventive Action: No preventive actions are specified; Subsection IWL is a monitoring 

program. If a coating program is currently credited for managing the effects of aging of 

concrete surfaces, then the program is to be continued during the period of extended 

operation. 

3. Parameters Monitored or Inspected: Table IWL-2500-1 specifies two categories for 

examination of concrete surfaces: Category L-A for all concrete surfaces and Category L-B 

for concrete surfaces surrounding tendon anchorages. Both of these categories rely on 

visual examination methods. Concrete surfaces are examined for evidence of damage or 

degradation, such as concrete cracks. IWL-251 0 specifies that concrete surfaces are 

examined for conditions indicative of degradation, such as those defined in ACI 201.1 R-77. 

Table IWL-2500-1 also specifies Category L-B for test and examination requirements for

NUREG-1801 XI S-6 April 2001
unbonded post tensioning systems. Tendon anchorage and wires or strands are visually 

examined for cracks, corrosion, and mechanical damage. Tendon wires or strands are also 

tested for yield strength, ultimate tensile strength, and elongation. Tendon corrosion 

protection medium is tested by analysis for alkalinity, water content, and soluble ion 

concentrations. 

4. Detection of Aging Effects: The frequency and scope of examinations specified in 

10 CFR 50.55a and Subsection IWL ensure that aging effects would be detected before 

they would compromise the design-basis requirements. The frequency of inspection is 

specified in IWL-2400. Concrete inspections are performed in accordance with Examination 

Category L-A. Under Subsection IWL, inservice inspections for concrete and unbonded 

post-tensioning systems are required at one, three, and five years following the structural 

integrity test. Thereafter, inspections are performed at five-year intervals. For sites with two 

plants, the schedule for inservice inspection is provided in IWL-2421. In the case of tendons, 

only a sample of the tendons of each tendon type requires examination at each inspection. 

The tendons to be examined during an inspection are selected on a random basis. Table 

IWL-2521 -1 specifies the number of tendons to be selected for each type (e.g., hoop, 

vertical, dome, helical, and inverted U) for each inspection period. The minimum number of 

each tendon type selected for inspection varies from 2 to 4%. Regarding detection methods 

for aging effects, all concrete surfaces receive a visual VT-3C examination. Selected areas, 

such as those that indicate suspect conditions and areas surrounding tendon anchorages, 

receive a more rigorous VT-1 or VT-i C examination. Prestressing forces in sample tendons 

are measured. In addition, one sample tendon of each type is detensioned. A single wire or 

strand is removed from each detensioned tendon for examination and testing. These visual 

examination methods and testing would identify the aging effects of accessible concrete 

components and prestressing systems in concrete containments. 

5. Monitoring and Trending: Except in inaccessible areas, all concrete surfaces are 

monitored on a regular basis by virtue of the examination requirements. For prestressed 

containments, trending of prestressing forces in tendons is required in accordance with 

paragraph (b)(2)(viii) of 10 CFR 50.55a. In addition to the random sampling used for tendon 

examination, one tendon of each type is selected from the first-year inspection sample and 

designated as a common tendon. Each common tendon is then examined during each 

inspection. This procedure provides monitoring and trending information over the life of the 

plant. 10 CFR 50.55a and Subsection IWL also require that prestressing forces in all 

inspection sample tendons be measured by lift-off tests and compared with acceptance 

standards based on the predicted force for that type of tendon over its life. 

6. Acceptance Criteria: IWL-3000 provides acceptance criteria for concrete containments. For 

concrete surfaces, the acceptance criteria rely on the determination of the "Responsible 

Engineer" (as defined by the ASME Code) regarding whether there is any evidence of 

damage or degradation sufficient to warrant further evaluation or repair. The acceptance 

criteria are qualitative; guidance is provided in IWL-251 0, which references ACI 201.1 R-77 

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 may also be 

used to augment the qualitative assessment of the responsible engineer. The acceptance 

standards for the unbonded post-tensioning system are quantitative in nature. For the post

tensioning system, quantitative acceptance criteria are given for tendon force and

April 2001 Xl S-7 NUREG-1 801
elongation, tendon wire or strand samples, and corrosion protection medium. 

10 CFR 50.55a and Subsection IWL do not define the method for calculating predicted 

tendon prestressing forces for comparison to the measured tendon lift-off forces. The 

predicted tendon forces are to be calculated in accordance with Regulatory Guide 1.35.1, 

which provides an acceptable methodology for use through the period of extended 

operation. 

7. Corrective Actions: Subsection IWL specifies that items for which examination results do 

not meet the acceptance standards are to be evaluated in accordance with IWL-3300 

•Evaluation" and described in an engineering evaluation report. The report is to include an 

evaluation of whether the concrete containment is acceptable without repair of the item and 

if repair is required, the extent, method, and completion date of the repair or replacement. 

The report also identifies the cause of the condition and the extent, nature, and frequency of 

additional examinations. Subsection IWL also provides repair procedures to follow in IWL

4000. This includes requirements for the concrete repair, repair of reinforcing steel, and 

repair of the post-tensioning system. As discussed in the appendix to this report, the staff 

finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address corrective 

actions. 

8. Confirmation Process: When areas of degradation are identified, an evaluation is 

performed to determine whether repair or replacement is necessary. As part of this 

evaluation, IWL-3300 specifies that the engineering evaluation report include the extent, 

nature, and frequency of additional examinations. IWL-4000 specifies the requirements for 

examination of areas that are repaired. Pressure tests following repair or modifications are 

in accordance with IWL-5000. As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process. 

9. Administrative Controls: IWA-1 400 specifies the preparation of plans, schedules, and 

inservice inspection summary reports. In addition, written examination instructions and 

procedures, verification of qualification level of personnel who perform the examinations, 

and documentation of a quality assurance program are specified. IWA-6000 specifically 

covers the preparation, submittal, and retention of records and reports. As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address administrative controls. 

10. Operating Experience: ASME Section XI, Subsection IWL was incorporated into 

10 CFR 50.55a in 1996. Prior to this time, operating experience pertaining to degradation of 

reinforced concrete and prestressing systems in concrete containments was gained through 

the inspections required by 10 CFR Part 50, Appendix J and ad hoc inspections conducted 

by licensees and the Nuclear Regulatory Commission (NRC). Recently, NRC Information 

Notice (IN) 99-10 described occurrences of degradation in prestressing systems. The 

program is to consider the degradation concerns described in this generic communication. 

Implementation of Subsection IWL, in accordance with 10 CFR 50.55a, is a necessary 

element of aging management for concrete containments through the period of extended 

operation.

NUREG-1 801 Xl S-8 April 2001
References

10 CFR Part 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled 

Power Reactors, Office of the Federal Register, National Archives and Records 

Administration, 2000. 

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, 2000. 

ACI Standard 201.1 R-77, Guide for Making a Condition Survey of Concrete in Service, 

American Concrete Institute. 

ACI Standard 349.3R-96, Evaluation of Existing Nuclear Safety-Related Concrete Structures, 

American Concrete Institute. 

ASME Section Xl, Rules for Inservice Inspection of Nuclear Power Plant Components, Subsection IWA, General Requirements, 1992 Edition with 1992 Addenda; 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 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, 1992 Edition with 1992 Addenda; 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 Inservice Inspection of Nuclear Power Plant Components, 

Subsection IWL, Requirements for Class CC Concrete Components of Light-Water Cooled 

Power Plants, 1992 Edition with 1992 Addenda; 1995 Edition with 1996 Addenda, The 

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

New York, NY. 

NRC Information Notice 99-10, Revision 1, Degradation of Prestressing Tendon Systems in 

Prestressed Concrete Containment, U.S. Nuclear Regulatory Commission, October 7, 1999.

April 2001 XI S-9 NUREG-1 801
Xl.S3 ASME SECTION XI, SUBSECTION IWF

Program Description 

10 CFR 50.55a imposes the inservice inspection (ISI) requirements of the American Society of 

Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, Section Xl, for Class 1, 2, 3, 

and MC piping and components and their associated supports. Inservice inspection of supports 

for ASME piping and components is addressed in Section X1, Subsection IWF. This evaluation 

covers the 1989 Edition through the 1995 Edition and addenda through the 1996 Addenda, as 

approved in 10 CFR 50.55a. ASME Code Section Xl, Subsection IWF constitutes an existing 

mandated program applicable to managing aging of ASME Class 1, 2, 3, and MC supports for 

license renewal. 

The IWF scope of inspection for supports is based on sampling of the total support population. 

The sample size varies depending on the ASME Class. The largest sample size is specified for 

the most critical supports (ASME Class 1). The sample size decreases for the less critical 

supports (ASME Class 2 and 3). Discovery of support deficiencies during regularly scheduled 

inspections triggers an increase of the inspection scope, in order to ensure that the full extent of 

deficiencies is identified. The primary inspection method employed is visual examination. 

Degradation that potentially compromises support function or load capacity is identified for 

evaluation. IWF specifies acceptance criteria and corrective actions. Supports requiring 

corrective actions are re-examined during the next inspection period. 

The evaluation of Subsection IWF as an aging management program (AMP) for license renewal 

is provided below. 

Evaluation and Technical Basis 

1. Scope of Program: For Class 1 piping and component supports, Subsection IWF 

(1989 edition) refers to Subsection IWB for the inspection scope and schedule. According to 

Table IWB-2500-1, only 25% of nonexempt supports are subject to examination. Supports 

exempt from examination are the supports for piping systems that are exempt from 

examination, according to pipe diameter or service. The same supports are inspected in 

each 10-year inspection interval. For Class 2, 3, and MC piping and component supports, 

Subsection IWF (1989 edition) refers to Subsections IWC, IWD, and IWE for the inspection 

scope and schedule. According to Table IWC-2500-1, 7.5% of nonexempt supports are 

subject to examination for Class 2 systems. The same supports are inspected in each 

10-year inspection interval. No specific numerical percentages are identified in Subsections 

IWD and IWE for Class 3 and Class MC, respectively. 

Starting with the 1990 addenda to the 1989 edition, the scope of Subsection IWF was 

revised. The required percentages of each type of nonexempt support subject to 

examination were incorporated into Table IWF-2500-1. The revised percentages are 25% of 

Class 1 nonexempt piping supports, 15% of Class 2 nonexempt piping supports, 10% of 

Class 3 nonexempt piping supports, and 100% of supports other than piping supports (Class 

1, 2, 3, and MC). For pipe supports, the total sample consists of supports from each system 

(such as main steam, feedwater, residual heat removal), where the individual sample sizes 

are proportional to the total number of nonexempt supports of each type and function within 

each system. For multiple components other than piping, within a system of similar design, 

function, and service, the supports of only one of the multiple components are required to be

NUREG-1801 XI S-1 0 April 2001
examined. To the extent practical, the same supports selected for examination during the 

first inspection interval are examined during each successive inspection interval. 

2. Preventive Action: No preventive actions are specified; Subsection IWF is an inspection 

program. 

3. Parameters Monitored or Inspected: IWF specifies visual examination (VT-3) of supports. 

The parameters monitored or inspected include corrosion; deformation; misalignment; improper clearances; improper spring settings; damage to close tolerance machined or 

sliding surfaces; and missing, detached, or loosened support items. The visual inspection 

would be expected to identify relatively large cracks. 

Table IWF-2500-1 (1989 edition) specifies examination of the following: 

(F1.10) Mechanical connections to pressure-retaining components and building structure; 

(F1.20) Weld connections to building structure; 

(F1.30) Weld and mechanical connections at intermediate joints in multi-connected integral 

and nonintegral supports; 

(F1.40) Clearances of guides and stops, alignment of supports, and assembly of support 

items; 

(F1.50) Spring supports and constant load supports; 

(F1.60) Sliding surfaces; 

(F1.70) Hot or cold position of spring supports and constant load supports. 

(Starting with the 1990 addenda, these items are listed in paragraph IWF-2500.) 

4. Detection of Aging Effects: VT-3 visual examination is specified in Table IWF-2500-1. The 

complete inspection scope is repeated every 10-year inspection interval. The qualified VT-3 

inspector uses judgment in assessing general corrosion; observed degradation is 

documented if loss of structural capacity is suspected. 

5. Monitoring and Trending: There is no requirement to monitor or report progressive, time

dependent degradation. Unacceptable conditions, according to IWF-3400, are noted for 

correction or further evaluation. 

6. Acceptance Criteria: The acceptance standards for visual examination are specified in 

IWF-3400. In IWF-341 0(b)(5), "roughness or general corrosion which does not reduce the 

load bearing capacity of the support" is given as an example of a "non-relevant condition," 

which requires no further action. IWF-341 0(a) identifies the following conditions as 

unacceptable: 

(i) deformations or structural degradations of fasteners, springs, clamps, or other support 

items; 

(ii) missing, detached, or loosened support items; 

(iii) arc strikes, weld spatter, paint, scoring, roughness, or general corrosion on close 

tolerance machined or sliding surfaces; 

(iv) improper hot or cold positions of spring supports and constant load supports; 

(v) misalignment of supports; 

(vi) improper clearances of guides and stops.

April 2001 XI S-1 1 NUREG-1801
Identification of unacceptable conditions triggers an expansion of the inspection scope, in 

accordance with IWF-2430, and reexamination of the supports requiring corrective actions 

during the next inspection period, in accordance with IWF-2420(b). 

7. Corrective Actions: In accordance with IWF-3122, supports containing unacceptable conditions are evaluated or tested, or corrected before returning to service. Corrective 

actions are delineated in IWF-3122.2. IWF-3122.3 provides an alternative for evaluation or testing, to substantiate structural integrity and/or functionality. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to 

address corrective actions. 

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process. 

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address administrative controls. 

10. Operating Experience: To date, IWF sampling inspections have been effective in 

managing aging effects for ASME Class 1, 2, 3, and MC supports. There is reasonable 

assurance that the Subsection IWF inspection program will be effective through the period of extended operation. 

References 

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and 

Records Administration, January 2000. 

ASME Section Xl, Rules for Inservice Inspection of Nuclear Power Plant Components, Subsection IWB, Requirements for Class 1 Components of Light-Water Cooled Power Plants, 1989 Edition. The ASME Boiler and Pressure Vessel Code, The American Society of 

Mechanical Engineers, New York, NY. 

ASME Section Xl, Rules for Inservice Inspection of Nuclear Power Plant Components, Subsection IWC, Requirements for Class 2 Components of Light-Water Cooled Power Plants, 1989 Edition. The ASME Boiler and Pressure Vessel Code, The American Society of Mechanical Engineers, New York, NY. 

ASME Section XI, Rules for inservice Inspection of Nuclear Power Plant Components, Subsection IWD, Requirements for Class 3 Components of Light-Water Cooled Power Plants, 1989 Edition. The ASME Boiler and Pressure Vessel Code, The American Society of 

Mechanical Engineers, New York, NY. 

ASME Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components, Subsection IWE, Requirements for Class MC and Metallic Liners of Class CC Components of Light-Water Cooled Power Plants, 1989 Edition. The ASME Boiler and Pressure Vessel 

Code, The American Society of Mechanical Engineers, New York, NY.

NUREG-1801 Xl S-12 April 2001
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

Water Cooled Power Plants, 1989 Edition through the 1995 Edition with 1996 Addenda. The 

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

New York, NY.

April 2001 XI S-13 NUREG-1801
Xl.S4 10 CFR PART 50, APPENDIX J

Program Description 

As described in 10 CFR Part 50, Appendix J, containment leak rate tests are required "to assure 

that (a) leakage through the primary reactor containment and systems and components penetrating primary containment shall not exceed allowable leakage rate values as specified in 

the technical specifications or associated bases and (b) periodic surveillance of reactor 

containment penetrations and isolation valves is performed so that proper maintenance and 

repairs are made during the service life of the containment, and systems and components 

penetrating primary containment." 

Appendix J provides two options, A and B, either of which can be chosen to meet the 

requirements of a containment LRT program. Under Option A, all of the testing must be 

performed on a periodic interval. Option B is a performance-based approach. Some of the 

differences between these options are discussed below, and more detailed information for 

Option B is provided in the Nuclear Regulatory Commission (NRC) Regulatory Guide 

(RG) 1.163 and NEI 94-01, Rev. 0. 

Evaluation and Technical Basis 

1. Scope of Program: The scope of the containment LRT program includes all pressure retaining components. Two types of tests are implemented. Type A tests are performed to 

measure the overall primary containment integrated leakage rate, which is obtained by summing leakage through all potential leakage paths, including containment welds, valves, fittings, and components that penetrate containment. Type B tests are performed to 

measure local leakage rates across each pressure-containing or leakage-limiting boundary for containment penetrations. Type A and B tests described in 10 CFR Part 50, Appendix J, 

are acceptable methods for performing these LRTs. Leakage testing for containment 

isolation valves (normally performed under Type C tests), if not included under this program, is included under LRT programs for systems containing the isolation valves. 

2. Preventive Action: No preventive actions are specified; the containment LRT program is a 

monitoring program. 

3. Parameters Monitored or Inspected: The parameters to be monitored are leakage rates 

through containment shells; containment liners; and associated welds, penetrations, fittings, and other access openings. 

4. Detection of Aging Effects: A containment LRT program is effective in detecting degradation of containment shells, liners, and components that compromise the 

containment pressure boundary, including seals and gaskets. While the calculation of 

leakage rates demonstrates the leak-tightness and structural integrity of the containment, it 

does not by itself provide information that would indicate that aging degradation has initiated 

or that the capacity of the containment may have been reduced for other types of loads, such as seismic loading. This would be achieved with the additional implementation of an 

acceptable containment inservice inspection program as described in XI.S1 and XI.S2. 

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

NUREG-1801 XI S-14 April 2001
regular fixed time interval as defined in 10 CFR Part 50, Appendix J. In the case of Option B, 

the interval for testing may be increased on the basis of acceptable performance in meeting 

leakage limits in prior tests. Additional details for implementing Option B are provided in 

NRC Regulatory Guide 1.163 and NEI 94-01, Rev.0. 

6. Acceptance Criteria: Acceptance criteria for leakage rates are defined in plant technical 

specifications. These acceptance criteria meet the requirements in 10 CFR Part 50, 

Appendix J, and are part of each plant's current licensing basis. The current licensing basis 

carries forward to the period of extended operation. 

7. Corrective Actions: Corrective actions are taken in accordance with 10 CFR Part 50, 

Appendix J, and NEI 94-01. When leakage rates do not meet the acceptance criteria, an 

evaluation is performed to identify the cause of the unacceptable performance, and 

appropriate corrective actions must be taken. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address 

corrective actions. 

8. Confirmation Process: When corrective actions are implemented to repair a condition that 

causes excessive leakage, confirmation by additional leak rate testing is performed to 

confirm that the deficiency has been corrected. As discussed in the appendix to this report, 

the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the 

confirmation process. 

9. Administrative Controls: Results of the LRT program are documented as described in 

10 CFR Part 50, Appendix J, to demonstrate that the acceptance criteria for leakage have 

been satisfied. The test results that exceed the performance criteria must be assessed 

under 10 CFR 50.72 and 10 CFR 50.73. As discussed in the appendix to this report, the 

staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address 

administrative controls. 

10. Operating Experience: To date, the 10 CFR Part 50, Appendix J, LRT program has been 

effective in preventing unacceptable leakage through the containment pressure boundary. 

Implementation of Option B for testing frequency must be consistent with plant-specific 

operating experience. 

References 

10 CFR Part 50, Appendix J, Primary Reactor Containment Leakage Testing for Water-Cooled 

Power Reactors, Office of the Federal Register, National Archives and Records 

Administration, 2000. 

10 CFR 50.72, Immediate Notification Requirements for Operating Nuclear Power Reactors, 

Office of the Federal Register, National Archives and Records Administration, 1997. 

10 CFR 50.73, Licensee Event Report System, Office of the Federal Register, National Archives 

and Records Administration, 1997. 

NEI 94-01, Rev. 0, Industry Guideline for Implementing Performance-Based Option of 

10 CFR Part 50 Appendix J, Nuclear Energy Institute, July 26, 1995.

April 2001 XI S-15 NUREG-1801
NRC Regulatory Guide 1.163, Performance-Based Containment Leak-Test Program," 

U.S. Nuclear Regulatory Commission, September 1995.

NUREG-1801 XI S-16 April 2001
Xl.S5 MASONRY WALL PROGRAM

Program Description 

Nuclear Regulatory Commission (NRC) IE Bulletin (IEB) 80-11, "Masonry Wall Design," and 

NRC Information Notice (IN) 87-67, "Lessons Learned from Regional Inspections of Licensee 

Actions in Response to IE Bulletin 80-11 ," constitute an acceptable basis for a masonry wall 

aging management program (AMP). IEB 80-11 required the identification of masonry walls in 

close proximity to, or having attachments from, safety-related systems or components, and the 

evaluation of design adequacy and construction practice. NRC IN 87-67 recommended plant

specific condition monitoring of masonry walls and administrative controls to ensure that the 

evaluation basis developed in response to NRC IEB 80-11 is not invalidated by (1) deterioration 

of the masonry walls (e.g., new cracks not considered in the reevaluation), (2) physical plant 

changes such as installation of new safety-related systems or components in close proximity to 

masonry walls, or (3) reclassification of systems or components from non-safety-related to 

safety-related. 

Important elements in the evaluation of many masonry walls during the NRC IEB 80-11 program 

included (1) installation of steel edge supports to provide a sound technical basis for boundary 

conditions used in seismic analysis and (2) installation of steel bracing to ensure containment of 

unreinforced masonry walls during a seismic event. Consequently, in addition to the 

development of cracks in the masonry walls, loss of function of the structural steel supports and 

bracing would also invalidate the evaluation basis. 

The objective of the masonry wall program is to manage aging effects so that the evaluation 

basis established for each masonry wall within the scope of license renewal remains valid 

through the period of extended operation. Since the issuance of NRC IEB 80-11 and NRC 

IN 87-67, the NRC promulgated 10 CFR 50.65, the Maintenance Rule. Masonry walls may be 

inspected as part of the Structures Monitoring Program (XI.S6) conducted for the Maintenance 

Rule, provided the ten attributes described below are incorporated. 

The attributes of an acceptable Masonry Wall Program are described below. 

Evaluation and Technical Basis 

1. Scope of Program: The scope includes all masonry walls identified as performing intended 

functions in accordance with 10 CFR 54.4. 

2. Preventive Action: No specific preventive actions are required. 

3. Parameters Monitored or Inspected: The primary parameter monitored is wall cracking 

that could potentially invalidate the evaluation basis. 

4. Detection of Aging Effects: Visual examination of the masonry walls by qualified 

inspection personnel is sufficient. The frequency of inspection is selected to ensure there is 

no loss of intended function between inspections. The inspection frequency may vary from 

wall to wall, depending on the significance of cracking in the evaluation basis. Unreinforced 

masonry walls that have not been contained by bracing warrant the most frequent 

inspection, because the development of cracks may invalidate the existing evaluation basis.

April 2001 XI S-1 7 NUREG-1801
5. Monitoring and Trending: Trending is not required. Monitoring is achieved by periodic examination for cracking. 

6. Acceptance Criteria: For each masonry wall, the extent of observed cracking of masonry and degradation of steel edge supports and bracing is not to invalidate the evaluation basis. Corrective actions are taken if the extent of cracking and steel degradation is sufficient to invalidate the evaluation basis. An option is to develop a new evaluation basis that accounts for the degraded condition of the wall (i.e., acceptance by further evaluation). 

7. Corrective Actions: As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address corrective actions. 

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process. 

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address administrative controls. 

10. Operating Experience: Since 1980, masonry walls that perform an intended function have been systematically identified through licensee programs in response to NRC IEB 80-11, USI A-46, and 10 CFR 50.48. NRC IN 87-67 documented lessons learned from the NRC IEB 80-11 program, and provided recommendations for administrative controls and periodic inspection to ensure that the evaluation basis for each safety-significant masonry wall is maintained. Whether conducted as a stand-alone program or as part of structures monitoring for MR, a masonry wall AMP that incorporates the recommendations delineated in NRC IN 87-67 should ensure that the intended functions of all masonry walls within the 

scope of license renewal are maintained for the period of extended operation. 

References 

10 CFR 50.48, Fire Protection, Office of the Federal Register, National Archives and Records 

Administration, 2000. 

10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power 

Plants, Office of the Federal Register, National Archives and Records Administration, 2000. 

NRC Generic Letter 87-02, Verification of Seismic Adequacy of Mechanical and Electrical 

Equipment in Operating Reactors, Unresolved Safety Issue (USI) A-46, U.S. Nuclear Regulatory Commission, February 19,1987. 

NRC IE Bulletin 80-11, Masonry Wall Design, U.S. Nuclear Regulatory Commission, 

May 8, 1980. 

NRC Information Notice 87-67, Lessons Learned from Regional Inspections of Licensee Actions in Response to IE Bulletin 80-11, U.S. Nuclear Regulatory Commission, December 31, 

1987.

NUREG-1801 XI April 2001 S-18
Xl.S6 STRUCTURES MONITORING PROGRAM

Program Description 

Implementation of structures monitoring under 10 CFR 50.65 (the Maintenance Rule) is 

addressed in Nuclear Regulatory Commission (NRC) Regulatory Guide (RG) 1.160, Rev. 2, and 

NUMARC 93-01, Rev. 2. These two documents provide guidance for development of licensee

specific programs to monitor the condition of structures and structural components within the 

scope of the Maintenance Rule, such that there is no loss of structure or structural component 

intended function. 

Because structures monitoring programs are licensee-specific, the Evaluation and Technical 

Basis for this aging management program (AMP) is based on the implementation guidance provided in Regulatory Guide 1.160, Rev. 2, and NUMARC 93-01, Rev. 2. Existing licensee

specific programs developed for the implementation of structures monitoring under 

10 CFR 50.65 are acceptable for license renewal provided these programs satisfy the 10 

attributes described below. 

If protective coatings are relied upon to manage the effects of aging for any structures included 

in the scope of this AMP, the structures monitoring program is to address protective coating 

monitoring and maintenance. 

Evaluation and Technical Basis 

1. Scope of Program: The applicant specifies the structure/aging effect combinations that are 

managed by its structures monitoring program. 

2. Preventive Action: No preventive actions are specified. 

3. Parameters Monitored or Inspected: For each structure/aging effect combination, the 

specific parameters monitored or inspected are selected to ensure that aging degradation leading to loss of intended functions will be detected and the extent of degradation can be 

determined. Parameters monitored or inspected are to be commensurate with industry codes, standards and guidelines, and are to also consider industry and plant-specific operating experience. Although not required, ACI 349.3R-96 and ANSI/ASCE 11-90 provide 

an acceptable basis for selection of parameters to be monitored or inspected for concrete 

and steel structural elements and for steel liners, joints, coatings, and waterproofing membranes (if applicable). If necessary for managing settlement and erosion of porous 

concrete subfoundations, the continued functionality of a site de-watering system is to be 

monitored. The plant-specific structures monitoring program is to contain sufficient detail on 

parameters monitored or inspected to conclude that this program attribute is satisfied. 

4. Detection of Aging Effects: For each structure/aging effect combination, the inspection methods, inspection schedule, and inspector qualifications are selected to ensure that aging degradation will be detected and quantified before there is loss of intended functions. 

Inspection methods, inspection schedule, and inspector qualifications are to be 

commensurate with industry codes, standards and guidelines, and are to also consider 

industry and plant-specific operating experience. Although not required, ACI 349.3R-96 and 

ANSI/ASCE 11-90 provide an acceptable basis for addressing detection of aging effects. 

The plant-specific structures monitoring program is to contain sufficient detail on detection to 

conclude that this program attribute is satisfied.

April 2001 Xl S-19 NUREG-1801
5. Monitoring and Trending: Regulatory Position 1.5, "Monitoring of Structures," in RG 1.160, 

Rev. 2, provides an acceptable basis for meeting the attribute. A structure is monitored in 

accordance with 10 CFR 50.65 (a)(2) provided there is no significant degradation of the 

structure. A structure is monitored in accordance with 10 CFR 50.65 (a)(1) if the extent of 

degradation is such that the structure may not meet its design basis or, if allowed to 

continue uncorrected until the next normally scheduled assessment, may not meet its 

design basis. 

6. Acceptance Criteria: For each structure/aging effect combination, the acceptance criteria 

are selected to ensure that the need for corrective actions will be identified before loss of 

intended functions. Acceptance criteria are to be commensurate with industry codes, 

standards and guidelines, and are to also consider industry and plant-specific operating 

experience. Although not required, ACI 349.3R-96 provides an acceptable basis for 

developing acceptance criteria for concrete structural elements, steel liners, joints, coatings, and waterproofing membranes. The plant-specific structures monitoring program is to 

contain sufficient detail on acceptance criteria to conclude that this program attribute is 

satisfied. 

7. Corrective Actions: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address corrective actions. 

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process. 

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address administrative controls. 

10. Operating Experience: Although in many plants structures monitoring programs have only 

recently been implemented, plant maintenance has been ongoing since initial plant 

operation. A plant-specific program that includes the attributes described above will be an 

effective AMP for license renewal. 

References 

10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power 

Plants, Office of the Federal Register, National Archives and Records Administration, 2000. 

ACI Standard 349.3R-96, Evaluation of Existing Nuclear Safety-Related Concrete Structures, 

American Concrete Institute. 

ANSI/ASCE 11-90, Guideline for Structural Condition Assessment of Existing Buildings, 

American Society of Civil Engineers. 

NRC Regulatory Guide 1.160, Rev. 2, Monitoring the Effectiveness of Maintenance at Nuclear 

Power Plants, U.S. Nuclear Regulatory Commission, March 1997. 

NUMARC 93-01, Rev. 2, Industry Guideline for Monitoring the Effectiveness of Maintenance at 

Nuclear Power Plants (Line-In/Line-Out Version), Nuclear Energy Institute, April 1996.

NUREG-1801 XI S-20 April 2001
XI.S7 RG 1.127, INSPECTION OF WATER-CONTROL STRUCTURES ASSOCIATED WITH 

NUCLEAR POWER PLANTS 

Program Description 

Nuclear Regulatory Commission (NRC) Regulatory Guide (RG) 1.127, Revision 1, "Inspection of 

Water-Control Structures Associated with Nuclear Power Plants," describes an acceptable basis 

for developing an inservice inspection and surveillance program for dams, slopes, canals, and 

other water-control structures associated with emergency cooling water systems or flood 

protection of nuclear power plants. The RG 1.127 program addresses age-related deterioration, 

degradation due to extreme environmental conditions, and the effects of natural phenomena 

that may affect water-control structures. The RG 1.127 program recognizes the importance of 

periodic monitoring and maintenance of water-control structures so that the consequences of 

age-related deterioration and degradation can be prevented or mitigated in a timely manner. 

RG 1.127 provides detailed guidance for the licensee's inspection program for water-control 

structures, including guidance on engineering data compilation, inspection activities, technical 

evaluation, inspection frequency, and the content of inspection reports. Water-control structures 

covered by the RG 1.127 program include concrete structures; embankment structures; spillway 

structures and outlet works; reservoirs; cooling water channels and canals, and intake and 

discharge structures; and safety and performance instrumentation. RG 1.127 delineates current 

NRC practice in evaluating inservice inspection programs for water-control structures. The 

attributes of an acceptable aging management program (AMP) for license renewal are 

described below. 

For plants not committed to RG 1.127, Revision 1, aging management of water-control 

structures may be included in the Structures Monitoring Program (XI.S6). However, details 

pertaining to water-control structures are to incorporate the attributes described herein. 

Evaluation and Technical Basis 

1. Scope of Program: RG 1.127 applies to water-control structures associated with 

emergency cooling water systems or flood protection of nuclear power plants. The water

control structures included in the RG 1.127 program are concrete structures; embankment 

structures; spillway structures and outlet works; reservoirs; cooling water channels and 

canals, and intake and discharge structures; and safety and performance instrumentation. 

2. Preventive Action: No preventive actions are specified; RG 1.127 is a monitoring program. 

3. Parameters Monitored or Inspected: RG 1.127 identifies the parameters to be monitored 

and inspected for water-control structures. The parameters vary depending on the particular 

structure. Parameters to be monitored and inspected for concrete structures include 

cracking, movements (e.g., settlement, heaving, deflection), conditions at junctions with 

abutments and embankments, erosion, cavitation, seepage, and leakage. Parameters to be 

monitored and inspected for earthen embankment structures include settlement, 

depressions, sink holes, slope stability (e.g., irregularities in alignment and variances from 

originally constructed slopes), seepage, proper functioning of drainage systems, and 

degradation of slope protection features. Further details of parameters to be monitored and 

inspected for these and other water-control structures are specified in Section C.2 of 

RG 1.127.

April 2001 Xl S-21 NUREG-1801
4. Detection of Aging Effects: Visual inspections are primarily used to detect degradation of water-control structures. In some cases, instruments have been installed to measure the 

behavior of water-control structures. RG 1.127 indicates that the available records and readings of installed instruments are to be reviewed to detect any unusual performance or distress that may be indicative of degradation. RG 1.127 describes periodic inspections, to be performed at least once every five years. Similar intervals of five years are specified in ACI 349.3R for inspection of structures continually exposed to fluids or retaining fluids. Such intervals have been shown to be adequate to detect degradation of water-control structures 

before they have a significant effect on plant safety. RG 1.127 also describes special inspections immediately following the occurrence of significant natural phenomena, such as large floods, earthquakes, hurricanes, tomadoes, and intense local rainfalls. 

5. Monitoring and Trending: Water-control structures are monitored by periodic inspection as described in RG 1.127. In addition to monitoring the aging effects identified in Attribute (3) above, inspections also monitor the adequacy and quality of maintenance and operating procedures. RG 1.127 does not discuss trending. 

6. Acceptance Criteria: Acceptance criteria to evaluate the need for corrective actions are not specified in RG 1.127. However, the "Evaluation Criteria" provided in Chapter 5 of ACI 349.3R-96 provides acceptance criteria (including quantitative criteria) for determining the adequacy of observed aging effects and specifies criteria for further evaluation . Although not required, plant-specific acceptance criteria based on Chapter 5 of ACI 349.3R-96 are acceptable. Acceptance criteria for earthen structures such as dams, canals, and embankments are to be consistent with programs falling within the regulatory jurisdiction of the Federal Energy Regulatory Commission (FERC) or the U.S. Army Corps of Engineers. 

7. Corrective Actions: RG 1.127 recommends that the licensee's inservice inspection and surveillance program include periodic inspections of water-control structures to identify deviations in structural conditions due to age-related deterioration and degradation from the original design basis. When findings indicate that significant changes have occurred, the conditions are to be evaluated. This includes a technical assessment of the causes of distress or abnormal conditions, an evaluation of the behavior or movement of the structure, and recommendations for remedial or mitigating measures. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to 

address corrective actions. 

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process. 

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address administrative controls. 

10. Operating Experience: Degradation of water-control structures has been detected, through RG 1.127 programs, at a number of nuclear power plants, and in some cases, it has required remedial action. No loss of intended functions has resulted from these occurrences. 

Therefore, it can be concluded that the inspections implemented in accordance with the guidance in RG 1.127 have been successful in detecting significant degradation before loss 

of intended function occurs.

NUREG-1801 April 2001 Xl S-22
NOTE: For dam inspection and maintenance, programs under the regulatory jurisdiction of 

FERC or the U.S. Army Corps of Engineers, continued through the period of extended 

operation, will be adequate for the purpose of aging management. For programs not falling 

under the regulatory jurisdiction of FERC or the U.S. Army Corps of Engineers, the staff will 

evaluate the effectiveness of the aging management program based on compatibility to the 

common practices of the FERC and Corps programs. 

References 

ACI Standard 349.31R-96, Evaluation of Existing Nuclear Safety-Related Concrete Structures, 

American Concrete Institute. 

NRC Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear 

Power Plants, Revision 1, U.S. Nuclear Regulatory Commission, March 1978.

April 2001 Xl S-23 NUREG-1801
XI.S8 PROTECTIVE COATING MONITORING AND MAINTENANCE PROGRAM 

Program Description 

Proper maintenance of protective coatings inside containment (defined as Service Level I in 

Nuclear Regulatory Commission [NRC] Regulatory Guide [RG] 1.54, Rev. 1) is essential to 

ensure operability of post-accident safety systems that rely on water recycled through the 

containment sump/drain system. Degradation of coatings can lead to clogging of strainers, which reduces flow through the sump/drain system. This has been addressed in NRC Generic 

Letter (GL) 98-04. 

Maintenance of Service Level I coatings applied to carbon steel surfaces inside containment 

(e.g., steel liner, steel containment shell, penetrations, hatches) also serves to prevent or 

minimize loss of material due to corrosion. Regulatory Position C4 in RG 1.54, Rev. 1, describes 

an acceptable technical basis for a Service Level I coatings monitoring and maintenance 

program that can be credited for managing the effects of corrosion for carbon steel elements 

inside containment. The attributes of an acceptable program are described below. 

A comparable program for monitoring and maintaining protective coatings inside containment, developed in accordance with RG 1.54, Rev. 0 or the American National Standards Institute 

(ANSI) standards (since withdrawn) referenced in RG 1.54, Rev. 0, and coatings maintenance 

programs described in licensee responses to GL 98-04, is also acceptable as an aging 

management program (AMP) for license renewal. 

Evaluation and Technical Basis 

1. Scope of Program: The minimum scope of the program is Service Level I coatings, defined 

in RG 1.54, Rev 1, as follows: "Service Level I coatings are used in areas inside the reactor 

containment where the coating failure could adversely affect the operation of post-accident 

fluid systems and thereby impair safe shutdown." 

2. Preventive Action: With respect to loss of material due to corrosion of carbon steel 

elements, this program is a preventive action. 

3. Parameters Monitored or Inspected: Regulatory Position C4 in RG 1.54, Rev 1, states 

that "ASTM D 5163-96 provides guidelines that are acceptable to the NRC staff for 

establishing an in-service coatings monitoring program for Service Level I coating systems in operating nuclear power plants..." ASTM D 5163-96, subparagraph 9.2, identifies the 

parameters monitored or inspected to be "any visible defects, such as blistering, cracking, 

flaking, peeling, rusting, and physical damage." 

4. Detection of Aging Effects: ASTM D 5163-96, paragraph 5, defines the inspection frequency to be each refueling outage or during other major maintenance outages as 

needed. ASTM D 5163-96, paragraph 8, discusses the qualifications for inspection personnel, the inspection coordinator and the inspection results evaluator. 

ASTM D 5163-96, subparagraph 9.1, discusses development of the inspection plan and the 

inspection methods to be used. It states, "A general visual inspection shall be conducted on 

all readily accessible coated surfaces during a walk-through. After a walk-through, thorough visual inspections shall be carried out on previously designated areas and on areas noted 

as deficient during the walk-through. A thorough visual inspection shall also be carried out 

on all coatings near sumps or screens associated with the Emergency Core Cooling System

NUREG-1801 Xl S-24 April 2001
(ECCS)." This subparagraph also addresses field documentation of inspection results. 

ASTM D 5163-96, subparagraph 9.5, identifies instruments and equipment needed for 

inspection. 

5. Monitoring and Trending: ASTM D 5163-96 identifies monitoring and trending activities in 

subparagraph 6.2, which specifies a pre-inspection review of the previous two monitoring 

reports, and in subparagraph 10.1.2, which specifies that the inspection report should 

prioritize repair areas as either needing repair during the same outage or postponed to 

future outages, but under surveillance in the interim period. 

6. Acceptance Criteria: ASTM D 5163-96, subparagraphs 9.2.1 through 9.2.6, 9.3 and 9.4, 

contain guidance for characterization, documentation, and testing of defective or deficient 

coating surfaces. Additional ASTM and other recognized test methods are identified for use 

in characterizing the severity of observed defects and deficiencies. The evaluation covers 

blistering, cracking, flaking, peeling, delamination, and rusting. ASTM D 5163-96, 

paragraph 11, addresses evaluation. It specifies that the inspection report is to be evaluated 

by the responsible evaluation personnel, who prepare a summary of findings and 

recommendations for future surveillance or repair, including an analysis of reasons or 

suspected reasons for failure. Repair work is prioritized as major or minor defective areas. A 

recommended corrective action plan is required for major defective areas, so that these 

areas can be repaired during the same outage, if appropriate. 

7. Corrective Actions: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address corrective actions. 

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process. 

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address administrative controls. 

10. Operating Experience: NRC Generic Letter 98-04 describes industry experience pertaining 

to coatings degradation inside containment and the consequential clogging of sump strainers. RG 1.54, Rev. 1, was issued in July 2000. Monitoring and maintenance of Service 

Level I coatings conducted in accordance with Regulatory Position C4 is expected to be an 

effective program for managing degradation of Service Level I coatings, and consequently 

an effective means to manage loss of material due to corrosion of carbon steel structural 

elements inside containment. 

References 

ASTM D 5163-96, 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. 

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.

April 2001 XI S-25 NUREG-1801
NRC Regulatory Guide 1.54, Rev. 0, Quality Assurance Requirements for Protective Coatings 

Applied to Water-Controlled Nuclear Power Plants, U.S. Nuclear Regulatory Commission, 

June 1973. 

NRC Regulatory Guide 1.54, Rev. 1, Quality Assurance Requirements for Protective Coatings 

Applied to Water-Controlled Nuclear Power Plants, U.S. Nuclear Regulatory Commission, 

July 2000

NUREG-1801 XI S-26 April 2001
XI.E1 ELECTRICAL CABLES AND CONNECTIONS NOT SUBJECT TO 10 CFR 50.49 

ENVIRONMENTAL QUALIFICATION REQUIREMENTS 

Program Description 

In most areas within a nuclear power plant, the actual ambient environments (e.g., temperature, 

radiation, or moisture) are less severe than the plant design environment. However, in a limited 

number of localized areas, the actual environments may be more severe than the plant design 

environment for those areas. Conductor insulation materials used in cables and connections 

may degrade more rapidly than expected in these adverse localized environments. An adverse 

localized environment is a condition in a limited plant area that is significantly more severe than 

the specified service environment for the cable. An adverse variation in environment is 

significant if it could appreciably increase the rate of aging of a component or have an 

immediate adverse effect on operability. 

The purpose of the aging management program described herein is to provide reasonable 

assurance that the intended functions of electrical cables and connections that are not subject 

to the environmental qualification requirements of 10 CFR 50.49 and are exposed to adverse 

localized environments caused by heat, radiation, or moisture will be maintained consistent with 

the current licensing basis through the period of extended operation. This program considers 

the technical information and guidance provided in NUREG/CR-5643, IEEE Std. P1 205, 

SAND96-0344, and EPRI TR-1 09619. 

The program described herein is written specifically to address cables and connections at plants 

whose configuration is such that most (if not all) cables and connections installed in adverse 

localized environments are accessible. This program, as described, can be thought of as a 

sampling program. Selected cables and connections from accessible areas (the inspection 

sample) are inspected and represent, with reasonable assurance, all cables and connections in 

the adverse localized environments. If an unacceptable condition or situation is identified for a 

cable or connection in the inspection sample, a determination is made as to whether the same 

condition or situation is applicable to other accessible or inaccessible cables or connections. As 

such, this program does not apply to plants in which most cables are inaccessible. 

As stated in NUREG/CR-5643, "The major concern with cables is the performance of aged 

cable when it is exposed to accident conditions." The statement of considerations for the final 

license renewal rule (60 Fed. Reg. 22477) states, "The major concern is that failures of 

deteriorated cable systems (cables, connections, and penetrations) might be induced during 

accident conditions." Since they are not subject to the environmental qualification requirements 

of 10 CFR 50.49, the electrical cables and connections covered by this aging management 

program are either not exposed to harsh accident conditions or are not required to remain 

functional during or following an accident to which they are exposed. 

Evaluation and Technical Basis 

1. Scope of Program: This inspection program applies to accessible electrical cables and 

connections within the scope of license renewal that are installed in adverse localized 

environments caused by heat or radiation in the presence of oxygen. 

2. Preventive Actions: This is an inspection program and no actions are taken as part of this 

program to prevent or mitigate aging degradation.

April 2001 XI E-1 NUREG-1 801
3. Parameters Monitored/Inspected: A representative sample of accessible electrical cables 

and connections installed in adverse localized environments are visually inspected for cable 

and connection jacket surface anomalies, such as embrittlement, discoloration, cracking, or 

surface contamination. The technical basis for the sample selected is to be provided. 

4. Detection of Aging Effects: Conductor insulation aging degradation from heat, radiation, 

or moisture in the presence of oxygen causes cable and connection jacket surface 

anomalies. Accessible electrical cables and connections installed in adverse localized 

environments are visually inspected at least once every 10 years. This is an adequate period to preclude failures of the conductor insulation since experience has shown that 

aging degradation is a slow process. A 1 0-year inspection frequency will provide two data 

points during a 20-year period, which can be used to characterize the degradation rate. The 

first inspection for license renewal is to be completed before the period of extended 

operation. 

5. Monitoring and Trending: Trending actions are not included as part of this program because the ability to trend inspection results is limited. Although not a requirement, trending would provide additional information on the rate of degradation. 

6. Acceptance Criteria: The accessible cables and connections are to be free from 

unacceptable, visual indications of surface anomalies, which suggest that conductor 

insulation or connection degradation exists. An unacceptable indication is defined as a 

noted condition or situation that, if left unmanaged, could lead to a loss of the intended 

function. 

7. Corrective Actions: All unacceptable visual indications of cable and connection jacket surface anomalies are subject to an engineering evaluation. Such an evaluation is to 

consider the age and operating environment of the component, as well as the severity of the 

anomaly and whether such an anomaly has previously been correlated to degradation of 

conductor insulation or connections. Corrective actions may include, but are not limited to, testing, shielding or otherwise changing the environment, or relocation or replacement of the 

affected cable or connection. When an unacceptable condition or situation is identified, a 

determination is made as to whether the same condition or situation is applicable to other 

accessible or inaccessible cables or connections. As discussed in the appendix to this 

report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to 

address corrective actions. 

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process. 

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address administrative controls. 

10. Operating Experience: Operating experience has shown that adverse localized 

environments caused by heat or radiation for electrical cables and connections may exist 

next to or above (within three feet of) steam generators, pressurizers or hot process pipes, such as feedwater lines. These adverse localized environments have been found to cause 

degradation of the insulating materials on electrical cables and connections that is visually observable, such as color changes or surface cracking. These visual indications can be 

used as indicators of degradation.

NUREG-1801 XI E-2 April 2001
References

EPRI TR-1 09619, Guideline for the Management of Adverse Localized Equipment 

Environments, Electric Power Research Institute, Palo Alto, CA, June 1999. 

IEEE Std. P1205-2000, IEEE Guide for Assessing, Monitoring and Mitigating Aging Effects on 

Class 1E Equipment Used in Nuclear Power Generating Stations. 

NUREG/CR-5643, Insights Gained From Aging Research, U. S. Nuclear Regulatory 

Commission, March 1992. 

SAN D96-0344, 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.

April 2001 X1 E-3 NUREG-1801
XI.E2 ELECTRICAL CABLES NOT SUBJECT TO 10 CFR 50.49 ENVIRONMENTAL 

QUALIFICATION REQUIREMENTS USED IN INSTRUMENTATION CIRCUITS 

Program Description 

In most areas within a nuclear power plant, the actual ambient environments (e.g., temperature, 

radiation, or moisture) are less severe than the plant design environment. However, in a limited 

number of localized areas, the actual environments may be more severe than the plant design 

environment for those areas. Conductor insulation materials used in electrical cables may 

degrade more rapidly than expected in these adverse localized environments. An adverse 

localized environment is a condition in a limited plant area that is significantly more severe than 

the specified service environment for the cable. An adverse variation in environment is 

significant if it could appreciably increase the rate of aging of a component or have an 

immediate adverse effect on operability. 

Exposure of electrical cables to adverse localized environments caused by heat or radiation can 

result in reduced insulation resistance (IR). Reduced IR causes an increase in leakage currents 

between conductors and from individual conductors to ground. A reduction in IR is a concern for 

circuits with sensitive, low-level signals such as radiation monitoring and nuclear 

instrumentation since it may contribute to inaccuracies in the instrument loop. 

The purpose of the aging management program described herein is to provide reasonable 

assurance that the intended functions of electrical cables that are not subject to the 

environmental qualification requirements of 10 CFR 50.49 and are used in circuits with 

sensitive, low-level signals exposed to adverse localized environments caused by heat, 

radiation or moisture will be maintained consistent with the current licensing basis through the 

period of extended operation. This program considers the technical information and guidance 

provided in NUREG/CR-5643, IEEE Std. P1205, SAND96-0344, and EPRI TR-109619. 

In this aging management program, routine calibration tests performed as part of the plant 

surveillance test program are used to identify the potential existence of aging degradation. When an instrumentation loop is found to be out of calibration during routine surveillance 

testing, trouble shooting is performed on the loop, including the instrumentation cable. 

As stated in NUREG/CR-5643, "The major concem with cables is the performance of aged 

cable when it is exposed to accident conditions." The statement of considerations for the final 

license renewal rule (60 Fed. Reg. 22477) states, "The major concern is that failures of 

deteriorated cable systems (cables, connections, and penetrations) might be induced during 

accident conditions." Since they are not subject to the environmental qualification requirements of 10 CFR 50.49, the electrical cables covered by this aging management program are either 

not exposed to harsh accident conditions or are not required to remain functional during or 

following an accident to which they are exposed. 

Evaluation and Technical Basis 

1. Scope of Program: This program applies to electrical cables used in circuits with sensitive, 

low-level signals such as radiation monitoring and nuclear instrumentation that are within the 

scope of license renewal. 

2. Preventive Actions: This is a surveillance testing program and no actions are taken as 

part of this program to prevent or mitigate aging degradation.

NUREG-1801 Xl E-4 April 2001
3. Parameters Monitored/Inspected: The parameters monitored are determined from the 

plant technical specifications and are specific to the instrumentation loop being calibrated, 

as documented in the surveillance test procedure. 

4. Detection of Aging Effects: Calibration provides sufficient indication of the need for 

corrective actions by monitoring key parameters and providing trending data based on 

acceptance criteria related to instrumentation loop performance. The normal calibration 

frequency specified in the plant technical specifications provides reasonable assurance that 

severe aging degradation will be detected prior to loss of the cable intended function. The 

first tests for license renewal are to be completed before the period of extended operation. 

5. Monitoring and Trending: Trending actions are not included as part of this program 

because the ability to trend test results is dependent on the specific type of test chosen. 

Although not a requirement, test results that are trendable provide additional information on 

the rate of degradation. 

6. Acceptance Criteria: Calibration readings are to be within the loop-specific acceptance 

criteria, as set out in the plant technical specifications surveillance test procedures. 

7. Corrective Actions: Corrective actions such as recalibration and circuit trouble-shooting 

are implemented when an instrument loop is found to be out of calibration. As discussed in 

the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, 

acceptable to address corrective actions. 

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process. 

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address administrative controls. 

10. Operating Experience: Operating experience has shown that a significant number of cable 

failures are identified through routine calibration testing. Changes in instrument calibration 

can be caused by degradation of the circuit cable and are one indication of potential 

electrical cable degradation. 

References 

EPRI TR-1 09619, Guideline for the Management of Adverse Localized Equipment 

Environments, Electric Power Research Institute, Palo Alto, CA, June 1999. 

IEEE Std. P1205-2000, IEEE Guide for Assessing, Monitoring and Mitigating Aging Effects on 

Class 1E Equipment Used in Nuclear Power Generating Stations. 

NUREG/CR-5643, Insights Gained From Aging Research, U. S. Nuclear Regulatory 

Commission, March 1992. 

SAN D96-0344, 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.

April 2001 XI E-5 NUREG-1801
XI.E3 INACCESSIBLE MEDIUM-VOLTAGE CABLES NOT SUBJECT TO 10 CFR 50.49 

ENVIRONMENTAL QUALIFICATION REQUIREMENTS 

Program Description 

Most electrical cables in nuclear power plants are located in dry environments. However, some 

cables may be exposed to condensation and wetting in inaccessible locations, such as conduits, cable trenches, cable troughs, duct banks, underground vaults or direct buried installations. 

When an energized medium-voltage cable is exposed to wet conditions for which it is not 

designed, water treeing or a decrease in the dielectric strength of the conductor insulation can 

occur. This can potentially lead to electrical failure. 

The purpose of the aging management program described herein is to provide reasonable 

assurance that the intended functions of inaccessible medium-voltage cables that are not 

subject to the environmental qualification requirements of 10 CFR 50.49 and are exposed to 

adverse localized environments caused by moisture while energized will be maintained 

consistent with the current licensing basis through the period of extended operation. An adverse 

localized environment is a condition in a limited plant area that is significantly more severe than 

the specified service environment for the cable. An adverse variation in environment is 

significant if it could appreciably increase the rate of aging of a component or have an 

immediate adverse effect on operability. This program considers the technical information and 

guidance provided in NUREG/CR-5643, IEEE Std. P1205, SAND96-0344, and EPRI TR

109619. 

In this aging management program periodic actions are taken to prevent cables from being 

exposed to significant moisture, such as inspecting for water collection in cable manholes and 

conduit, and draining water, as needed. In-scope, medium-voltage cables exposed to significant moisture and significant voltage are tested to provide an indication of the condition of the 

conductor insulation. The specific type of test performed will be determined prior to the initial 

test, and is to be a proven test for detecting deterioration of the insulation system due to wetting, such as power factor, partial discharge, or polarization index, as described in EPRI TR-1 03834

P1-2, or other testing that is state-of-the-art at the time the test is performed. 

As stated in NUREG/CR-5643, "The major concern with cables is the performance of aged cable when it is exposed to accident conditions." The statement of considerations for the final 

license renewal rule (60 Fed. Reg. 22477) states, "The major concern is that failures of 

deteriorated cable systems (cables, connections, and penetrations) might be induced during accident conditions." Since they are not subject to the environmental qualification requirements of 10 CFR 50.49, the electrical cables covered by this aging management program are either 

not exposed to harsh accident conditions or are not required to remain functional during or 

following an accident to which they are exposed. 

Evaluation and Technical Basis 

1. Scope of Program: This program applies to inaccessible (e.g., in conduit or direct buried) 

medium-voltage cables within the scope of license renewal that are exposed to significant moisture simultaneously with significant voltage. Significant moisture is defined as periodic 

exposures to moisture that last more than a few days (e.g., cable in standing water). Periodic exposures to moisture that last less than a few days (i.e., normal rain and drain) are 

not significant. Significant voltage exposure is defined as being subjected to system voltage for more than twenty-five percent of the time. The moisture and voltage exposures

NUREG-1 801 XI E-6 April 2001
described as significant in these definitions, which are based on operating experience and 

engineering judgement, are not significant for medium-voltage cables that are designed for 

these conditions (e.g., continuous wetting and continuous energization is not significant for 

submarine cables). 

2. Preventive Actions: Periodic actions are taken to prevent cables from being exposed to 

significant moisture, such as inspecting for water collection in cable manholes and conduit, 

and draining water, as needed. Medium-voltage cables for which such actions are taken are 

not required to be tested since operating experience indicates that prolonged exposure to 

moisture and voltage are required to induce this aging mechanism. 

3. Parameters Monitored/inspected: In-scope, medium-voltage cables exposed to 

significant moisture and significant voltage are tested to provide an indication of the 

condition of the conductor insulation. The specific type of test performed will be determined 

prior to the initial test, and is to be a proven test for detecting deterioration of the insulation 

system due to wetting, such as power factor, partial discharge, or polarization index, as 

described in EPRI TR-1 03834-Pl -2, or other testing that is state-of-the-art at the time the 

test is performed. 

4. Detection of Aging Effects: In-scope, medium-voltage cables exposed to significant 

moisture and significant voltage are tested at least once every 10 years. This is an adequate 

period to preclude failures of the conductor insulation since experience has shown that 

aging degradation is a slow process. A 10-year inspection frequency will provide two data 

points during a 20-year period, which can be used to characterize the degradation rate. The 

first tests for license renewal are to be completed before the period of extended operation. 

5. Monitoring and Trending: Trending actions are not included as part of this program 

because the ability to trend test results is dependent on the specific type of test chosen. 

Although not a requirement, test results that are trendable provide additional information on 

the rate of degradation. 

6. Acceptance Criteria: The acceptance criteria for each test is defined by the specific type 

of test performed and the specific cable tested. 

7. Corrective Actions: An engineering evaluation is performed when the test acceptance 

criteria are not met in order to ensure that the intended functions of the electrical cables can 

be maintained consistent with the current licensing basis. Such an evaluation is to consider 

the significance of the test results, the operability of the component, the reportability of the 

event, the extent of the concern, the potential root causes for not meeting the test 

acceptance criteria, the corrective actions required, and the likelihood of recurrence. When 

an unacceptable condition or situation is identified, a determination is made as to whether 

the same condition or situation is applicable to other inaccessible, in-scope, medium-voltage 

cables. As discussed in the appendix to this report, the staff finds the requirements of 

10 CFR Part 50, Appendix B, acceptable to address corrective actions. 

8. Confirmation Process: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation 

process. 

9. Administrative Controls: As discussed in the appendix to this report, the staff finds the 

requirements of 10 CFR Part 50, Appendix B, acceptable to address administrative controls.

April 2001 XI E-7 NUREG-1 801
10. Operating Experience: Operating experience has shown that XLPE or high molecular 

weight polyethylene (HMWPE) insulation materials are most susceptible to water tree 

formation. The formation and growth of water trees varies directly with operating voltage. 

Treeing is much less prevalent in 4kV cables than those operated at 13 or 33kV. Also, 

minimizing exposure to moisture minimizes the potential for the development of water 

treeing. As additional operating experience is obtained, lessons learned can be used to 

adjust the program, as needed. 

References 

EPRI TR-1 03834-Pl -2, Effects of Moisture on the Life of Power Plant Cables, Electric Power 

Research Institute, Palo Alto, CA, August 1994. 

EPRI TR-1 09619, Guideline for the Management of Adverse Localized Equipment 

Environments, Electric Power Research Institute, Palo Alto, CA, June 1999. 

IEEE Std. P1205-2000, IEEE Guide for Assessing, Monitoring and Mitigating Aging Effects on 

Class 1E Equipment Used in Nuclear Power Generating Stations. 

NUREG/CR-5643, Insights Gained From Aging Research, U. S. Nuclear Regulatory 

Commission, March 1992. 

SAND96-0344, Aging Management Guideline for Commercial Nuclear Power Plants - Electrical 

Cable and Terminations, prepared by Sandia National Laboratories for the U.S. Department 

of Energy, September 1996.

NUREG-1801 XI E-8 April 2001
APPENDIX

QUALITY ASSURANCE FOR 

AGING MANAGEMENT PROGRAMS

April 2001 A-i NUREG-1801
This Page Intentionally Left Blank

NUREG-1801 A-ii April 2001
QUALITY ASSURANCE FOR AGING MANAGEMENT PROGRAMS

The license renewal applicant must demonstrate that the effects of aging on structures and 

components subject to an aging management review (AMR) will be adequately managed to 

ensure that their intended functions will be maintained consistent with the current licensing basis 

(CLB) of the facility for the period of extended operation. Therefore, those aspects of the AMR 

process that affect the quality of safety-related structures, systems, and components are subject 

to the quality assurance (QA) requirements of Appendix B to 10 CFR Part 50. For non-safety

related structures and components subject to an AMR, the existing 10 CFR Part 50, 

Appendix B, QA program may be used to address the elements of corrective actions, 

confirmation process, and administrative controls on the following bases: 

"Criterion XVI of 10 CFR Part 50, Appendix B, requires that measures be established to 

ensure that conditions adverse to quality, such as failures, malfunctions, deviations, 

defective material and equipment, and nonconformances, are promptly identified and 

corrected. In the case of significant conditions adverse to quality, measures must be 

implemented to ensure that the cause of the nonconformance is determined and that 

corrective action is taken to preclude repetition. In addition, the root cause of the significant 

condition adverse to quality and the corrective action implemented must be documented and 

reported to appropriate levels of management. 

" Because Criterion XVI of 10 CFR Part 50, Appendix B, requires that measures be taken to 

preclude repetition of significant conditions adverse to quality, follow-up actions must be 

taken to verify effective implementation of the proposed corrective action. This verification 

comprises the confirmation process element for aging management programs for license 

renewal. For example, in managing internal corrosion of piping, a mitigation program (water 

chemistry) may be used to minimize susceptibility to corrosion. However, it may also be 

necessary to have a condition monitoring program (ultrasonic inspection) to verify that 

corrosion is indeed insignificant. When corrective actions are necessary for significant 

conditions, follow-up activities are to confirm that the corrective actions implemented are 

effective in preventing recurrence. 

" Administrative controls are the provisions associated with organization and management, 

policies, orders, instructions, procedures, record keeping, and designations of authority and 

responsibility that are necessary to ensure operation of the facility in a safe manner. 10 CFR 

50.34(b)(6)(ii) and 10 CFR 50.36(c)(5) require that nuclear power plant license applicants 

include in the final safety analysis report information on the managerial and administrative 

controls to be used to ensure safe operation. 10 CFR 50.34(b)(6)(ii) and 10 CFR 50.36(c)(5) 

also stipulate that Appendix B to 10 CFR Part 50 sets forth the requirements for these 

managerial and administrative controls. Accordingly, programs consistent with the 

requirements of 10 CFR Part 50, Appendix B, also satisfy the administrative controls 

element necessary for aging management programs (AMPs) for license renewal. 

Notwithstanding the suitability of its provisions to address quality-related aspects of the AMR 

process for license renewal, 10 CFR Part 50, Appendix B, covers only safety-related structures, 

systems, and components. Therefore, absent a commitment by the applicant to expand the 

scope of its 10 CFR Part 50, Appendix B, QA program to include non-safety-related structures 

and components subject to an AMR for license renewal, the AMPs applicable to such structures 

and components are to provide alternative means to address corrective actions, confirmation 

process, and administrative controls. Such alternate means would be subject to review by NRC 

on a case-by-case basis.

April 2001 A-1 NUREG-1801
This Page Intentionally Left Blank

NUREG-1801 A-2 April 2001
tITLE AND SUBTITLE 

-Generic Aging Lessons Learned (GALL) Report 

Tabulation of Results

" IRICLEAR REGULATORY COMMISSION I

i NRC FORM 335 (2-49) 

NROM 1102 

3201.3202

S. AUTHOR(S) 6. TYPE OF REPORT 

Technical Guidance 

7. PERIOD COVERED civsiv Dat-s) 

8. PERFORMING ORGANIZATION - NAME AND ADDRESS (HNRC. •f Dvm • Offk or.pA0,.- U.S .•wR iuory amm~sa. 8m ad 29uoI. 

Division of Regulatory Improvement Programs 

Office of Nuclear Reactor Regulation 

U.S. Nuclear Regulatory Commission 

Washington, D.C. 20555-0001

9. SPONSORING ORGANIZATION - NAME AND ADDRESS (f NRC. type "Smeasbmot if dWmactor. pNRCDi Or,=e or Rpq• US. NucAw roWauiy Cwundmia

Same as above

'0. SUPPLEMENTARY NOTES

11. ABSTRACT ,wO wr or inas) 

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

plant programs and documents the technical basis for determining where existing programs are adequate without modification and where existing programs should be augmented for the extended period of 

operation. The evaluation results documented in the GALL report indicate that many of the existing 

programs are adequate to manage the aging effects for particular structures or components for license 

renewal without change. The GALL report also contains recommendations on specific areas for which 

existing programs should be augmented for license renewal. An applicant may reference the GALL report 

in a license renewal application to demonstrate that the programs at the applicant's facility correspond to 

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

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

report information into the NUREG-1 800, "Standard Review Plan for Review of License Renewal 

Applications for Nuclear Power Plants," as directed by the Commission, should improve the efficiency of 

the license renewal process.

12 KEY WORDS/DESCRIPTORS Ain ,,s ¢. 3 f -m!D /mg I~p-vI) im AVAiLABIUTY STATEMENT 

License Renewal unlimited 

License Renewal Applicant 14. SECURITY CLASSIFICATION 

License Renewal Application ln- Pipe) 

Aging Management Programs unclassified 

Time-limited Aging Analyses Aging Effects (nhs RPoe) .unclassified 

Existing Programs 15. NUMBER OF PAGES 

1 •16. PRICE

NRC FORM 335 (2-9)

1. REPORT NUMBER 

(ASS1gned by NRC. Add Vol.. SUPp.. ft-, 

Sad Addoskum n NUMlDu, 9 any.) 

NUREG-1801 

Vol. 2 

3. DATE REPORT PUBLISHED 

MONTH YEAR 

July 2001 

4. FIN OR GRANT NUMBER

BIBUOGRAPHIC DATA SHEET 

(See kusucftms o ow romm)
Federal Recycling Program