-

NUREG-1796

Safety Evaluation Report

Related to the License Renewal of

the Dresden Nuclear Power Station,

Units 2 and 3 and Quad Cities

Nuclear Power Station, Units 1 and 2

Docket Nos. 50-237, 50-249, 50-254, and 50-265

Exelon Generation Company, LLC (Exelon)

U.S. Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation

Washington, DC 20555-0001
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NUREG-1796

Safety Evaluation Report

Related to the License Renewal of

the Dresden Nuclear Power Station,

Units 2 and 3 and Quad Cities

Nuclear Power Station, Units 1 and 2

Docket Nos. 50-237, 50-249, 50-254, and 50-265

Exelon Generation Company, LLC (Exelon)

Manuscript Completed: July 2004

Date Published: October 2004

Prepared by

T.J. Kim, R. Auluck

Division of Regulatory Improvement Programs

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001
iIIiiiiIIiiI

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ABSTRACT

This safety evaluation report (SER) documents the technical review of the Dresden Nuclear

Power Station (DNPS), Units 2 and 3 and Quad Cities Nuclear Power Station (QCNPS), Units 1

and 2, license renewal application (LRA) by the U.S. Nuclear Regulatory Commission (NRC)

staff (staff). By letter dated January 3, 2003, Exelon Generation Company (Exelon or the

applicant) submitted the LRA for Dresden and Quad Cities (D/QCNPS) in accordance with Title

10, Part 54 of the Code of Federal Regulations (10 CFR Part 54 or the Rule). Exelon requests

renewal of the operating licenses for DNPS Unit 2 (License No. DRP-19), DNPS Unit

3 (License No. DRP-25), QCNPS Unit 1 (License No. DRP-29), and QCNPS Unit

2 (License No. DRP-30) for a period of 20 years beyond the current license expirations of

midnight, December 22, 2009; January 12, 2011; December 14, 2012; and December 14, 2012,

respectively.

DNPS is located in Grundy County, Illinois, on the shore of a man-made cooling lake, with the

Illinois River to the north and the Kankakee River to the east. The QCNPS is located in Rock

Island County, IL, on the east bank of the Mississippi River opposite the mouth of the

Wapsipinicon River, and about 3 miles north of Cordova, IL. DNPS, Units 1 and 2, and

QCNPS, Units 2 and 3, each consist of a General Electric boiling-water reactor (BWR/3)

authorized to operate individually at a steady state reactor power level not to exceed 2957

megawatts-thermal, or approximately 850 megawatts-electric.

This SER presents the status of the staff's review of information submitted to the NRC through

June 22, 2004, the cutoff date for consideration in the SER. The staff identified open items and

confirmatory items that had to be resolved before the staff could make a final determination on

the application. Sections 1.5 and 1.6 of this report summarize these items and their

resolutions. Section 6 provides the staff's final conclusion of its review of the D/QCNPS LRA.

The NRC license renewal project manager is Mr. Rajender Auluck. Mr. Auluck may be reached

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

Environmental Impacts Program, U.S. Nuclear Regulatory Commission, Washington, DC

20555-0001.

-iii-

TABLE OF CONTENTS

Abstract ............... -iiiTable of Contents ................................................. .vAbbreviations ............. -xv1. Introduction and General Discussion ........... 1.1 Introduction ...................... 1.2 License Renewal Background ......... 1.2.1 Safety Reviews ............. 1.2.2 Environmental Reviews ....... 1.3 Principal Review Matters ............. 1.4 Interim Staff Guidance ............... 1.5 Summary of Open Items .............. 1.6 Summary of Confirmatory Items ........ 1.7 Summary of Proposed License Conditions

........

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

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

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

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

..... .1-1 ..... .1-1 ..... 1-2 ..... 1-3 ..... 1-5 ..... 1-5 ..... 1-6 ..... 1-8 .... 1-14

.... 1-31

2. Scoping and Screening Methodology for Identifying Structures and Components Subject to

Aging Management Review, and Implementation Results .. 2-1

2.1 Scoping and Screening Methodology ..................... 2.1.1 Introduction .................................

2.1.2 Summary of Technical Information in the Application . . 2.1.2.1 Scoping Methodology .................. 2.1.2.2 Screening Methodology ................. 2.1.3 Staff Evaluation ..............................

2.1.3.1 Scoping Methodology .................. 2.1.3.2 Screening Methodology ................. 2.1.4 Conclusions .............................. 2.1.5 References .................................

2.2 Plant-Level Scoping Results ........................... 2.2.1 Summary of Technical Information in the Application .. 2.2.2 Staff Evaluation ..............................

2.2.3 Conclusions .............................. 2.3 Scoping and Screening Results: Mechanical Systems ....... 2.3.1 Reactor Vessel, Internals, and Reactor Coolant System

2.3.1.1 Reactor Vessel ........................ 2.3.1.2 Reactor Vessel Intemals ................

2.3.1.3 Reactor Coolant System ................

2.3.1.4 Evaluation Findings ....................

2.3.1.5 References ...........................

2.3.2 Engineered Safety Features Systems ............. 2.3.2.1 High-Pressure Coolant Injection System ....

.. ... ..

.......

.......

.. . .. ..

.......

.......

.. ... ..

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

.......

.......

.. . .. ..

.......

.. .....

.......

.......

. ......

.. .....

. .... ..

.. .....

.. .....

.......

.. . .....

.. 2-1 .. 2-1 .. 2-1 .. 2-1 .. 2-8 .... 2-10

.... 2-11

.... 2-33

2-37 .... 2-38

.... 2-39

... 2-39

2-40 .... 2-41

2-41 .... 2-43 .... 2-43 .... 2-47 .... 2-53

.... 2-66

2-66 .... 2-67

2-67

2.3.2.2 Core Spray System .................. 2-69

2.3.2.3 Containment Isolation Components and Primary Containment

Piping System ............ 2-72
2.3.2.4 Reactor Core Isolation Cooling System-Quad Cities Only

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

2.3.2.5 Isolation Condenser-Dresden Only . . 2-81

2.3.2.6 Residual Heat Removal System-Quad Cities Only ... .. 2-86

2.3.2.7 Low-Pressure Coolant Injection System-Dresden Only ... 2-89

2.3.2.8 Standby Liquid Control System .

2.3.2.9 Standby Gas Treatment System .

2.3.2.10 Automatic Depressurization System

2.3.2.11 Anticipated Transient Without Scram System . .

2.3.2.12 Evaluation Findings .

2.3.2.13 References .

2.3.3 Auxiliary Systems .

2.3.3.1 Refueling Equipment .

2.3.3.2 Shutdown Cooling System (Dresden only) .

2.3.3.3 Control Rod Drive Hydraulic System .

2.3.3.4 Reactor Water Cleanup System.

2.3.3.5 Fire Protection System.

2.3.3.6 Emergency Diesel Generator and Auxiliaries ...

2.3.3.6A Diesel Generator Room Ventilation.

2.3.3.7 Main Control Room Heating, Ventilation, and Air

Conditioning.

2.3.3.8 HVAC-Reactor Building.

.. 2-92

.. 2-95

.. 2-101

.. 2-102

.. 2-104

.. 2-104

.. 2-104

.. 2-104

.. 2-107

.. 2-111

.. 2-119

.. 2-122

.. 2-128

.. 2-132

.. 2-134

.. 2-138

2.3.3.9 Emergency Core Cooling System Corner Room HVAC ... 2-140

2.3.3.10 Station Blackout Building HVAC ...... 2-143

2.3.3.11 Station Blackout System (Diesel and Auxiliaries) ....... 2-146

2.3.3.12 Diesel Generator Cooling Water System ..... ........ 2-148

2.3.3.13 Diesel Fuel Oil System ........ .................. 2-151

2.3.3.14 Process Sampling System ........................ 2-154

2.3.3.15 Carbon Dioxide System ........ .................. 2-157

2.3.3.16 Service Water System ........ ................... 2-159

2.3.3.17 Reactor Building Closed Cooling Water System ....... 2-162

2.3.3.18 Turbine Building Closed Cooling Water System ....... 2-165

2.3.3.19 Demineralizer Water Makeup System ..... .......... 2-168

2.3.3.20 Residual Heat Removal Service Water System (Quad Cities

Only) ............ ............................ 2-174

2.3.3.21 Containment Cooling Service Water System

(Dresden Only) .......... ........................ 2-180

2.3.3.22 Ultimate Heat Sink System ...... ................. 2-184

2.3.3.23 Fuel Pool Cooling and Filter Demineralizer System ..... 2-187

2.3.3.24 Plant Heating System ....... .................... 2-192

2.3.3.25 Containment Atmosphere Monitoring System .... ..... 2-195

2.3.3.26 Nitrogen Containment Atmosphere Dilution System .... 2-197

2.3.3.27 Drywell Nitrogen Inerting System ...... ............. 2-199

2.3.3.28 Safe Shutdown Makeup Pump System (Quad Cities

Only) ............. ........................... 2-202

2.3.3.29 Circulating Water System ....... ................. 2-208

2.3.3.30 Dresden Laundry Treatment System ................ 2-210

2.3.3.31 Zinc Injection System ....... .................... 2-212

2.3.4 Steam and Power Conversion Systems ......... ............. 2-214

-Vi-
2.3.4.1 Main Steam System ......................... 2.3.4.2 Feedwater System..........................

2.3.4.3 Condensate and Condensate Storage Systems ....

2.3.4.4 Main Condenser ............................ 2.3.4.5 Main Turbine and Auxiliary Systems ............. 2.3.4.6 Turbine Oil System ..........................

2.3.4.7 Main Generator and Auxiliary .................

2.3.4.8 Extraction Steam System (Quad Cities Only) ...... 2.3.4.9 Feedwater Heater Drains and Vents System ....... 2.4 Scoping and Screening Results: Structures ......................

2.4.1 Primary Containment ................................

2.4.1.1 Summary of Technical Information in the Application

....

....

.. ..

....

....

....

....

2-214

2-221

2-225

2-228

2-232

2-235

2-238

2-241

2-243

2-246

2-250

2-250

2-253

2-257

2.4.1.2 Staff Evaluation .......................... 2.4.1.3 Conclusions ............................. 2.4.2 Reactor Bulding. ................................... 2.4.2.1 Summary of Technical Information in the Application

2.4.2.2 Staff Evaluation .......................... 2.4.2.3 Conclusions ............................. 2.4.3 Main Control Room and Auxiliary Electric Equipment Room . .

2.4.3.1 Summary of Technical Information in the Application

2.4.3.2 Staff Evaluation .......................... 2.4.3.3 Conclusions ............................. 2.4.4 Turbine Building ....................................

2.4.4.1 Summary of Technical Information in the Application

2.4.4.2 Staff Evaluation .......................... 2.4.4.3 Conclusions ............................. 2.4.5 Diesel Generator Buildings. ........................... 2.4.5.1 Summary of Technical Information in the Application

2.4.5.2 Staff Evaluation .......................... 2.4.5.3 Conclusions....

2.4.6 Station Blackout Building and Yard Structures ............. 2.4.6.1 Summary of Technical Information in the Application

2.4.6.2 Staff Evaluation .......................... 2.4.6.3 Conclusions ............................. 2.4.7 Isolation Condenser Pump House (Dresden) ..............

2.4.7.1 Summary of Technical Information in the Application

2.4.7.2 Staff Evaluation .. . - 2.4.7.3 Conclusions..............................

2.4.8 Makeup Demineralizer Building (Dresden) ................

2.4.8.1 Summary of Technical Information in the Application

2.4.8.2 Staff Evaluation .......................... 2.4.8.3 Conclusions ............................. 2.4.9 Radwaste Floor Drain Surge Tank ......................

2.4.9.1 Summary of Technical Information in the Application

2.4.9.2 Staff Evaluation ..........................

2.4.9.3 Conclusions .............................

.... 2-258 .... 2-258

.... 2-260

.... 2-262

.... 2-262

.... 2-262 .... 2-264

.. ..

....

....

....

....

....

.. ..

.. ..

....

. .. .

....

....

....

....

....

....

....

....

2-265

2-265

2-265

2-267

2-267

2-268

2-268

2-270

2-270

2-270

2-270

2-272

2-274

2-275

2-275

2-276

2-276

2-277

2-277

2-278

2-278 .... 2-278

.... 2-278

.... 2-279

.... 2-280

2.4.10 Miscellaneous Foundations ................ ,.... .. . .... 2-280

2.4.10.1 Summary of Technical Information in the Application ... 2-280

2.4.10.2 Staff Evaluation ................ 2-281

-vii-
2.4.10.3 Conclusions ................................... 2-282

2.4.11 Crib House ........................................... 2-282

2.4.11.1 Summary of Technical Information in the Application ... 2-282

2.4.11.2 Staff Evaluation.

2.4.11.3 Conclusions.

2.4.12 Unit 1 Crib House (Dresden) ...........

2.4.12.1 Summary of Technical Information

2.4.12.2 Staff Evaluation ..............

2.4.12.3 Conclusions................

2.4.13 Station Chimney .....................

2.4.13.1 Summary of Technical Information

2.4.13.2 Staff Evaluation ..............

2.4.13.3 Conclusions................

2.4.14 Cranes and Hoists ...................

2.4.14.1 Summary of Technical Information

2.4.14.2 Staff Evaluation ..............

2.4.14.3 Conclusions................

2.4.15 Component Supports Commodity Group . .

2.4.15.1 Summary of Technical Information

2.4.15.2 Staff Evaluation ..............

2.4.15.3 Conclusions .................

2.4.16 Insulation Commodity Group ...........

2.4.16.1 Summary of Technical Information

2.4.16.2 Staff Evaluation ..............

2.4.16.3 Conclusions................

.................. 2-284

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

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

"in the Application

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

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

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

|in the Application

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

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

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

|in the Application

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

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

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

|in the Application

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

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

....

....

... .

....

. . .

....

....

. . .

....

....

....

. . .

....

2-289

2-290

2-290

2-290

2-292

2-292

2-292

2-293

2-293

2-294

2-294

2-295

2-300

2-300

2-300

2-302

2-304

in the

. .. ...

. .. ...

... ......... 2-304

Application ... 2-304

............. 2-305

............. 2-309

2.5 Scoping and Screening Results: Electrical and Instrumentation and Controls 2-309

2.5.1 Insulated Cables and Connections .......... 2-310

2.5.1.1 SummaryofTechnical Information in theApplication .... 2-310

2.5.1.2 Staff Evaluation .......... 2-310

2.5.1.3 Conclusions .......... 2-311

2.5.2 Bus Duct .......... 2-312

2.5.2.1 Summary of Technical Information in the Application .... 2-312

2.5.2.2 Staff Evaluation .......... 2-312

2.5.2.3 Conclusions .......... 2-312

2.5.3 High Voltage Transmission Conductors and Insulators . .2-313

2.5.3.1 Summary of Technical Information in the Application .... 2-313

2.5.3.2 Staff Evaluation .2-313

2.5.3.3 Conclusions .2-313

2.5.4 Electrical/I&C Penetration .. 2-314

2.5.4.1 Summary of Technical Information in the Application .... 2-314

2.5.4.2 Staff Evaluation. 2-314

2.5.4.3 Conclusions .2-315

2.5.5 References .. 2-315

3. Aging Management Review ..........................

3.0 Aging Management Review ...................

3.0.1 The GALL Format for the LRA ..........

3.0.2 The Staff's Review Process for GALL ....

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

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

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

.. 3-1

.. 3-1

.. 3-2

.. 3-3

-viii-
3.0.3 Common Aging Management Programs .... ; ................... 3-5

3.0.3.1 ASME Section Xl Inservice Inspection, Subsections IWB, IWC,

and IWD (B.1.1) . .3-8

3.0.3.2 Water Chemistry Program (B.1.2) . .3-10

3.0.3.3 BWR Stress Corrosion Cracking (B.1.7) . 3-14

3.0.3.4 Flow-Accelerated Corrosion (B.1.11) . 3-16

3.0.3.5 Bolting Integrity (B.1.12) . 3-18

3.0.3.6 Open-Cycle Cooling Water System (B.1.13) . 3-21

3.0.3.7 Closed-Cycle Cooling Water System (B.1.14) . 3-27

3.0.3.8 Compressed Air Monitoring (B.1.16) . 3-30

3.0.3.9 Above Ground Carbon Steel Tanks (B.1.20) . 3-33

3.0.3.10 One Time Inspection (B.1.23) . 3-36

3.0.3.11 Selective Leaching of Materials (B.1.24) . 3-40

3.0.3.12 Buried Piping and Tanks Inspection (B.1.25) . 3-43

3.0.3.13 10 CFR Part 50, Appendix J (8.1.28) . 3-47

3.0.3.14 Structures Monitoring Program (B.1.30) . 3-49

3.0.3.15 Heat Exchanger Test and Inspection Activities (B.2.6) . . . 3-53

3.0.3.16 Lube Oil Monitoring Activities (8.2.5) . 3-58

3.0.3.17 Periodic Inspection of Ventilation System Elastomers

(B.2.3) .. 3-62

3.0.3.18 Periodic Inspection of Components Subject to Moist

Environments (B.2.9) ............. 3-67

3.0.4 Quality Assurance For Aging Management Programs . . 3-69

3.0.4.1 Summary of Technical Information in Application . 3-70

3.0.4.2 Staff Evaluation . 3-71

3.0.4.3 Conclusions . 3-72

3.0.4.4 References . 3-72

3.0.5 Aging Management Review for Additional In-Scope Components.. .. 3-72

3.1 Reactor Vessel, Intemals, and Reactor Coolant System . 3-86

3.1.1 Summary of Technical Information in the Application . 3-86

3.1.2 Staff Evaluation . 3-86

3.1.2.1 Aging Management Evaluations in the GALL Report That Are

Relied on for License Renewal, Which Do Not Require Further

Evaluation . 3-89

3.1.2.2 Aging Management Evaluations in the GALL Report That Are

Relied on for License Renewal, For Which GALL Recommends

Further Evaluation . 3-90

3.1.2.3 Aging Management Programs for Reactor Vessel, Internals, and

Reactor Coolant System Components . 3-98

3.1.2.4 Aging Management Review of Reactor Vessel, Vessel Internals,

and Reactor Coolant System ................... 3-125

3.2 Engineered Safety Features Systems .. 3-176

3.2.1 Summary of Technical Information in the Application .. 3-176

3.2.2 Staff Evaluation ................ 3-177

3.2.2.1 Aging Management Evaluations in the GALL Report That Are

Relied on for License Renewal, Which Do Not Require Further

Evaluation ...... .. . . 3-179

-ix-
3.2.2.2 Aging Management Evaluations in the GALL Report That Are

Relied on for License Renewal, for Which GALL Recommends

Further Evaluation ............. ................... 3-180

3.2.2.3 Aging Management Programs for ESF System Components

........ ..................................... 3-188

3.2.2.4 Aging Management Review of Plant-Specific Engineered Safety

Features Systems Components ..................... 3-192

3.3 Auxiliary Systems ....... ....... 3-225

3.3.1 Summary of Technical Information in the Application .... ........ 3-226

3.3.2 Staff Evaluation ............ ............................ 3-226

3.3.2.1 Aging Management Evaluations in the GALL Report That Are

Relied on for License Renewal, Which Do Not Require Further

Evaluation ... . ................................. 3-230

3.3.2.2 Aging Management Evaluations in the GALL Report That Are

Relied on for License Renewal, For Which GALL Recommends

Further Evaluation ............. ................... 3-230

3.3.2.3 Aging Management Programs for Auxiliary System Components

......... .................................... 3-236

3.3.2.4 Aging Management Review of Auxiliary Systems ....... 3-259

3.3.2.5 General Aging Management Review Issues .... ....... 3-359

3.4 Steam and Power Conversion Systems .............................. 3-370

3.4.1 Summary of Technical Information in the Application .... ........ 3-371

3.4.2 Staff Evaluation ........................................ 3-371

3.4.2.1 Aging Management Evaluations in the GALL Report That Are

Relied on for License Renewal, Which Do Not Require Further

Evaluation ... . ................................. 3-373

3.4.2.2 Aging Management Evaluations in the GALL Report That Are

Relied on for License Renewal, for Which GALL Recommends

Further Evaluation .......... ...................... 3-373

3.4.2.3 Aging Management Program for the Steam and Power

Conversion System Components ...... .............. 3-375

3.4.2.4 Aging Management Review of the Steam and Power Conversion

Systems ....................................... 3-377

3.5 Containment, Structures, and Component Supports ........ ............ 3-392

3.5.1 Summary of Technical Information in the Application .... ........ 3-393

3.5.2 Staff Evaluation ........................................ 3-393

3.5.2.1 Aging Management Evaluations in the GALL Report That Are

Relied on for License Renewal, Which Do Not Require Further

Evaluation ... .................................. 3-400

3.5.2.2 Aging Management Evaluations in the GALL Report That Are

Relied on for License Renewal, for Which the GALL Report

Recommends Further Evaluation ...... .............. 3-400

3.5.2.3 Aging Management Programs for Containment, Structures, and

Component Supports .......... ................... 3-418

3.5.2.4 Aging Management Review of Plant-Specific Structures and

Structural Components ............................ 3-435

3.6 Electrical and Instrumentation and Controls ...... .................... 3-464

3.6.1 Summary of Technical Information in the Application .... ........ 3-465

3.6.2 Staff Evaluation ........................................ 3-465
3.6.2.1 Aging Management Evaluations in the GALL Report that Are

Relied on for License Renewal, Which Do Not Require Further

Evaluation.......... 6 3-467

3.6.2.2 Aging Management Evaluation in the GALL Report That Are

Relied on for License Renewal, For Which GALL Recommends

Further Evaluation ........... 3-468

3.6.2.3 Aging Management Programs for Electrical and l&C Components

.~3-468 ~~~~. .. . . . . . . . . .. . .. . . . . . ...-;346 3.6.2.4 Aging Management of Plant-Specific Components ...... 3-482

3.7 Conclusion for Aging Management .................. ... ............. 3-495

4. Time-Limited Aging Analyses .............................................. 4-1

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

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

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

4.1.3 Conclusions ............................................. 4-2

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

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

4.2.1.1 Reactor Vessel Materials Upper-Shelf Energy Reduction Due to

Neutron Embrittlement .......... .................... 4-4

4.2.1.2 Adjusted Reference Temperature for Reactor Vessel Materials

Due to Neutron Embrittlement ....... .................. 4-4

4.2.1.3 Reflood Thermal Shock Analysis of the Reactor Vessel .... 4-4

4.2.1.4 Reflood Thermal Shock Analysis of the Reactor Vessel Core

Shroud and Repair Hardware ........ ................. 4-5

4.2.1.5 Reactor Vessel Thermal Limit Analyses-Operating PressureTemperature Limits ........ ........................ 4-5

4.2.1.6 Reactor Vessel Circumferential Weld Examination Relief ... 4-6

4.2.1.7 Reactor Vessel Axial Weld Failure Probability ..... ....... 4-6

4.2.2 Staff Evaluation ................... ....................... 4-7

4.2.2.1 Reactor Vessel Materials Upper-Shelf Energy Reduction Due to

Neutron Embrittlement ........... ................... 4-7

4.2.2.2 Adjusted Reference Temperature for Reactor Vessel Materials

Due to Neutron Embrittlement ..... 4-12

4.2.2.3 Reflood Thermal Shock Analysis of the Reactor Vessel ... 4-13

4.2.2.4 Reflood Thermal Shock Analysis of the Reactor Vessel Core

Shroud and Repair Hardware ........ ................ 4-14

4.2.2.5 Reactor Vessel Thermal Limit Analyses-Operating PressureTemperature Limits .................... 4-15

4.2.2.6 Reactor Vessel Circumferential Weld Examination Relief . . 4-16

4.2.2.7 Reactor Vessel Axial Weld Failure Probability .... ....... 4-18

4.2.3 Conclusions .................... ........................ 4-21

4.3 Metal Fatigue .................................................. 4-22

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

4.3.1.1 Reactor Vessel Fatigue Analyses ..... ............... 4-22

4.3.1.2 Fatigue Analysis of the Reactor Internals ..... ......... 4-23

4.3.1.3 ASME Code, Section III, Class 1 Reactor Coolant Pressure

Boundary Piping and Component Fatigue Analysis .... ... 4-24

-xi-
4.3.1.4 Reactor Coolant Pressure Boundary Piping and Components

Designed to USAS B31.1, ASME Code, Section III, Classes 2 and

3, or ASME Code, Section VIII, Classes B and C .... ..... 4-25

4.3.1.5 Fatigue Analysis of the Isolation Condenser .... ........ 4-25

4.3.1.6 Effects of Reactor Coolant Environment on Fatigue Life of

Components and Piping (Generic Safety Issue 190) ...... 4-26

4.3.2 Staff Evaluation .................. ....................... 4-27

4.3.2.1 Reactor Vessel Fatigue Analysis ..... ................ 4-27

4.3.2.2 Fatigue Analysis of the Reactor Internals ..... ......... 4-27

4.3.2.3 ASME Code, Section ll, Class 1 Reactor Coolant Pressure

Boundary Piping and Component Fatigue Analysis ....... 4-28

4.3.2.4 Reactor Coolant Pressure Boundary Piping and Components

Designed to USAS B31.1, ASME Code, Section III, Classes 2 and

3, orASME Code, Section Vil, Classes B and C .... ..... 4-29

4.3.2.5 Fatigue Analysis of the Isolation Condenser .... ........ 4-29

4.3.2.6 Effects of Reactor Coolant Environment on Fatigue Life of

Components and Piping (Generic Safety Issue 190) ...... 4-30

4.3.3 Conclusions .................... ........................ 4-31

4.4 Environmental Qualification ........................ ............... 4-32

4.4.1 Environmental Qualification Program TLAA . ............. 4-32

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

4.4.1.2 Staff Evaluation ............. .. ................... 4-35

4.4.1.3 Conclusions ...................... 4-35

4.4.2 Generic Safety Issue 168, 'Environmental Qualification of Low-Voltage

Instrumentation and Control (I&C) Cables" ......... ............ 4-35

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

4.4.2.2 Staff Evaluation ........ ..... .. ................... 4-36

4.4.2.3 Conclusions ...................... 4-37

4.5 Loss of Prestress in Concrete Containment Tendons ........ ............ 4-37

4.6 Fatigue of Primary Containment, Attached Piping, and Components ........ 4-37

4.6.1 Summary of Technical Information in the Application . .......... 4-38

4.6.1.1 Fatigue Analysis of the Suppression Chamber, Vents and

Downcomers ..................................... 4-38

4.6.1.2 Fatigue Analysis of Safety Relief Valve Discharge Piping Inside

the Suppression Chamber, External Suppression Chamber

Attached Piping, and Associated Penetrations .... ....... 4-39

4.6.1.3 Drywell-to-Suppression Chamber Vent Line Bellows Fatigue

Analyses ........................................ 4-40

4.6.1.4 Primary Containment Process Penetration Bellows Fatigue

Analysis ........................................ 4-40

4.6.2 Staff Evaluation ............ ............................. 4-41

4.6.2.1 Fatigue Analysis of the Suppression Chamber, Vents, and

Downcomers ..................................... 4-41

4.6.2.2 Fatigue Analysis of Safety Relief Valve Discharge Piping Inside

the Suppression Chamber, External Suppression Chamber

Attached Piping, and Associated Penetrations .... ....... 4-42

4.6.2.3 Drywell-to-Suppression Chamber Vent Line Bellows Fatigue

Analyses ........................................ 4-43

-xii-
4.6.2.4 Primary Containment Process Penetration Bellows Fatigue

Analysis ...................... 4-43

4.6.3 Conclusions.4-43

4.7 Other Plant-Specific Time-Limited Aging Analyses .. 4-44

4.7.1 Reactor Building Crane Load Cycles . 4-44

4.7.1.1 Summary of Technical Information in the Application . 4-44

4.7.1.2 Staff Evaluation . 4-44

4.7.1.3- Conclusions . 4-45

4.7.2 Metal Corrosion . 4-45

4.7.2.1 Corrosion Allowance for Power-Operated Relief Valves ... 4-45

4.7.2.2 Degradation Rates of Inaccessible Exterior Drywell Plate

Surfaces . 4-46

4.7.2.3 Galvanic Corrosion in the Containment Shell and Attached Piping

Components due to Stainless Steel Emergency Core Cooling

System Suction Strainers . 4-52

4.7.3 Crack Growth Calculation of a Postulated Flaw in the Heat Affected Zone

of an Arc Strike in the Suppression Chamber Shell . . 4-54

4.7.3.1 Summary of Technical Information in the Application . 4-54

4.7.3.2 Staff Evaluation ................ 4-55

4.7.3.3 Conclusions .4-55

4.7.4 Radiation Degradation of Drywell Shell Expansion Gap Polyurethane

Foam . .4-56

4.7.4.1 Summary of Technical Information in the Application . 4-56

4.7.4.2 Staff Evaluation . 4-56

4.7.4.3 Conclusions . 4-57

4.7.5 High-Energy Line Break Postulation Based on Fatigue Cumulative

Usage Factor . 4-57

4.8 Conclusion for Time-Limited Aging Analyses . 4-57

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

6. Conclusions .. 6-1

Appendices

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

Appendix B: Chronology .. . B-1

Appendix C: Principal Contributors .. . C-1

Appendix D: References .. . D-1

Tables

3.0.3-1 Common Aging Management Programs .. . 3-5

3.0.3-2 System-Specific Management Programs .. . 3-6

-xiii-
3.1-1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor

Coolant System Evaluated in Chapter IV of the GALL Report .... ............ 3-87

3.2-1 Staff Evaluation for Dresden and Quad Cities Engineered Safety Features System

Components in the GALL Report ...................................... 3-177

3.3-1 Summary of Aging Management for Auxiliary Systems Evaluated in Chapter VII of the

GALL Report . .................................................... 3-227

3.3-3 Fire Protection Portions of Table 3.3-3-Staff Evaluation Table for Dresden and Quad

Cities Auxiliary System Components Evaluated in the GALL Report .... ....... 3-250

3.4-1 Summary of Aging Management Programs for Steam and Power Conversion Systems

Evaluated in Chapter VII of the GALL Report ............................ 3-372

3.5-1 Staff Evaluation for Structures and Structural Components in NUREG-1 801

(GALL)-Common Components of All Types of PWR and BWR Containment .... 3-394

3.5-2 PWR Concrete (Reinforced and Prestressed) and Steel Containment, BWR Concrete

(Mark II and ll) and Steel (Mark I, II, and l1l) Containment ..... .............. 3-395

3.5-3 Class I Structures ................................................. 3-397

3.5-4 Component Supports ............................................... 3-399

3.6-1 Staff Evaluation Table for Dresden and Quad Cities Electrical Components Evaluated in

the GALL Report .................................................. 3-466

4.2-1 Comparison of Results from Staff and BWRVIP Calculations ..... ............ 4-19

-xiv-
ABBREVIATIONS

A

AC

ACAD

ACI

ACRS

ACSR

ADAMS

ADS

AEC

AERM

AFW

AFU

AHU

AISC

ALARA

AMG

AMP

AMR

AMSAC

ANS

ANSI

AOR

APCSB

AR

ARI

ART

ASME

ASNT

ASTM

ATWS

AVT

AWG

BMI

BTP

B&W

BWR

BWROG

BWRVIP

C

CAM

CAR

CASS

CBF

CCST

ampacity

alternating current

atmospheric containment air dilution system

American Concrete Institute

Advisory Committee on Reactor Safeguards

aluminum conductor steel reinforced

Agencywide Document Access and Management System

Automatic depressurization system

Atomic Energy Commission

aging effect requiring management

auxiliary feedwater

air filtration unit

air handling unit

American Institute of Steel Construction

as low as reasonably achievable

aging management guideline

aging management program

aging management review

ATWS mitigation system actuation circuitry

American Nuclear Society

American National Standards Institute

abnormal occurrence report

Auxiliary and Power Conversion System Branch

action report

alternate rod insertion

adjusted reference temperature

American Society of Mechanical Engineers

American Society for Nondestructive Testing

American Society for Testing and Materials

anticipated transient without a scram

all-volatile treatment

American wire gauge

bottom mounted instrument

branch technical position

Babcock and Wilcox

boiling-water reactor

Boiling Water Reactor Owners Group

Boiling Water Reactor Vessel and Internals Project

Celsius

containment atmospheric monitoring

corrective action report

cast austenitic stainless steel

cycle-based fatigue

contaminated condensate storage tank

-xv-
CCsw

CCw

CDF

CDHR c

CD-ROM

CDWST

CF

CFR

Cl

CIC

CLB

CMAA

CO

CO2

ComEd

C-RAI

CRD

CRDA

CRD(H)

CRDM

CR HVAC

Cs

CST

CUF

CV

CW

D/QCNPS

DAM

DBA

DBD

DBE

DC

DFO

DG

DGB-HVAC

DGCW

DGSW

DNI

DNPIS

DNPS

DPR

DR

D-RAI

DRS

DSER

DWM

EC

containment cooling service water

component cooling water

core damage frequency

ontainer hydrogen detectors and recombiner

compact disk-read only memory

clean demineralized water storage tank

chemistry factor

Code of Federal Regulations

confirmatory item

contaminant isolation component

current licensing basis

Crane Manufactures Association of America

carbon monoxide

carbon dioxide

Commonwealth Edison

clarification of request for additional information

control rod drive

control rod drop accident

control rod drive (hydraulic)

control rod drive mechanism

air handles heating/cooling

containment spray system or carbon steel

condensate storage tank

cumulative usage factor

check valve

circulating water

Dresden/Quad Cities Nuclear Power Station

data acquisition modules

design-basis accident

design baseline document

design-basis event

direct current

diesel fuel oil

diesel generator

diesel generator building heating, ventilation, and air conditioning

diesel generator cooling water

diesel generator service water

drywell nitrogen inerting

drywell nitrogen purge and inerting system

Dresden Nuclear Power Station

developmental power reactor

drywell-to-refueling

draft request for additional information

development requirements specification

draft safety evaluation report

demineralizer water makeup

engineering change

-xvi-
ECCS

ECP

ECR-HVAC

EDG

EDY

EFPY

EFWST

EGC

EHC

EMA

EPN

EPR

EPRI

EPU

EQ

ESF

ESS

ESW

EWCS

F

FAC

FCC

Fen

FERC

FOI

FP

FPP

FRP

FSAR

FSER

FSSD

ft

ft-lb

FWRV

GALL

GE

GEIS

GL

GSI

GTR

HCU

HELB

HEPA

emergency core cooling system

electrochemical corrosion potential

emergency core cooling system corner room heating, ventilation, and air

conditioning

emergency diesel generator

effective degradation years

effective full-power year

emergency feedwater storage tank

Exelon Generation Company, LLC

electrohydraulic control

equivalent margin analysis

equipment part number

ethylene propylene rubber

Electric Power Research Institute

extended power uprate

environmental qualification

engineered safety features

electronic switching system

electroslag weld

electronic work control system

Fahrenheit

flow-accelerated corrosion

Federal Communications Commission

environmental fatigue multiplier

Federal Energy Regulatory Commission

factor of improvement

fire protection

fire protection program

fiberglass reinforced plastic

final safety analysis report

final safety evaluation report

fire safe shutdown

foot, feet

foot-pound

feedwater regulating valve

Generic Aging Lessons Learned (Report)

General Electric

generic environmental impact statement

generic letter

generic safety issue

generic technical report

hydraulic control unit

high energy line break

high efficiency particulate air

-xvii-
HIC high integrity container

HPCI high pressure coolant injection system

HRRM high-range radiation monitor

HRSS high radiation sampling system

HSLAS high strength low alloy steel

HSO hydrogen seal oil

HTK high temperature kerite

HVAC heating, ventilation, and air conditioning

HWC hydrogren water chemistry

HX heat exchanger

l&C instrumentation and control

IA instrument air

IASCC irradiation-assisted stress-corrosion cracking

ID inner diameter

IDR inspection discrepancy report

IE Inspection and Enforcement, Office of (NRC)

IEB inspection and enforcement bulletin

IGA intergranular attack

IGSCC intergranular stress-corrosion cracking

IHSI induction heat stress improvement

ILRT integrated leak rate test

in. inch, inches

IN information notice

INPO Institute of Nuclear Power Operations

IPA integrated plant assessment

IR insulation resistance

IRM intermediate range monitor

ISG interim staff guidance

ISI inservice inspection

ISP Integrated Surveillance Program

IST inservice testing

J joule

Ken effective multiplication factor

Kip one thousand pounds

KV kilovolt

LBB leak before break

LER licensee event report

LLRT local leak rate test

LOCA loss-of-coolant accident

LOOP loss of offsite power

LPCI low pressure coolant injection system

LPRM local power range monitor

-xviii-
LR

LRA

LRTI

LTOP

LWR

m

M/G

MCC

MeV

MG

MIC

miVy

MOV

MRV

MSIP

MSIV

MSL

MSV

MSIV

MT

MWe

license renewal

license renewal application

license renewal technical instruction

low-temperature over-pressurization

light water reactor

margin

motor generator

motor control center

one million electron volts

motor generator

microbiologically influenced corrosion

mils per year

motor-operated valve

minimum required value

mechanical stress improvement method

main steam isolation valve

mean sea level

main stop valve

main steam isolation valve

magnetic particle test

megawatt-electric

NACE

NaOH

NBI

NCAD

NCR

NDE

ND-QAP

NEI

NEPA

NFPA

NIS

NMCA

NNS

NPAR

NPS

NPSH

NRC

NSR

NSSS

NUMARC

NUREG

NUREG/CR

National Association of Corrosion Engineers

sodium hydroxide

nuclear boiler instrumentation

nitrogen containment atmospheric dilution

nonconformance report

nondestructive examination

Quality Assurance Program for Station Operation

Nuclear Energy Institute

National Environmental Policy Act of 1969

National Fire Protection Association

nuclear instrumentation system

noble metal chemical application

non-nuclear safety

nuclear plant aging research

nominal pipe size

net positive suction head

U.S. Nuclear Regulatory Commission

non-safety-related

nuclear steam supply system

Nuclear Management and Resources Council (now NEI)

Nuclear Regulatory Commission technical report

NUREG contractor report

-xix-
OBE

OD

OE

ODSCC

01

OPT

P(F/E)

P&I

P&ID

PC

PCIS

PDT

PLL

PM

PMT

PORV

ppm

PS

psi

psig

PT

P-T

PTS

PUAR

PVC

PWHT

PWR

QA

QAP

QCNPS

operating based event

outside diameter

operating experience

outside diameter stress-corrosion cracking

open item

operability test

Conditional failure probability

piping and instrumentation

piping and instrumentation diagram

primary containment

primary containment isolation system

piping design table

predicted lower limit

preventive maintenance

post-maintenance test

power operated relief valve

parts per million

process sampling

pounds per square inch

pounds per square inch gauge

penetrant test

pressure-temperature

pressurized thermal shock

plant-unique analysis reports

polyvinyl chloride

postweld heat treatment

pressurized-water reactor

quality assurance

quality action plan

Quad Cities Nuclear Power Station

RAI

RAT

RBCCW

RBH-HVAC

RCCA

RCIC

RCP

RCPB

RCS

RCU

RFP

RG

RHR

request for additional information

reserve auxiliary transformer

reactor building closed cooling water

reactor building heating, ventilation, and air conditioning

rod cluster control assembly

reactor core isolation cooling

reactor coolant pump

reactor coolant pressure boundary

reactor coolant system

refrigeration condensing unit

reactor feed pump

regulatory guide

residual heat removal

-xx-
1. INTRODUCTION AND GENERAL DISCUSSION

1.1 Introduction

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

licenses for the Dresden Nuclear Power Station (DNPS), Units 2 and 3, and Quad Cities

Nuclear Power Station (QCNPS), Units 1 and 2, as filed by Exelon Generation Company (EGC

or the applicant). By letter dated January 3, 2003, EGC submitted its application to the U.S.

Nuclear Regulatory Commission (NRC or the Commission) for renewal of the DNPS and

QCNPS operating licenses for up to an additional 20 years. The NRC received the application

on January 3, 2003. The NRC staff (the staff) reviewed the DNPS/QCNPS license renewal

application (LRA) for compliance with the requirements of Title 10, Part 54, of the Code of

Federal Regulations (10 CFR Part 54), "Requirements for Renewal of Operating Licenses for

Nuclear Power Plants," and prepared this report to document the results of its safety review.

The NRC license renewal project managers for the DNPS and QCNPS safety review are Mr.

Rajender Auluck and Mr. T. J. Kim. Mr. Auluck may be contacted by telephone at (301)

415-1025 or by electronic mail at RCA@nrc.qov. Alternatively, written correspondence can be

sent to the following address:

License Renewal and Environmental Impacts Program

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

Attention: R. Auluck, Mail Stop 0-11 F1

In its January 3, 2003, submittal letter, the applicant requested renewal of the operating

licenses issued under Section 1 04b of the Atomic Energy Act of 1954, as amended, for DNPS

Unit 2 (License No. DPR-19), DNPS Unit 3 (License No. DPR-25), QCNPS Unit 1 (License

No. DPR-29), and QCNPS Unit 2 (License No. DPR-30) for a period of 20 years beyond the

current license expirations of midnight, December 22, 2009, January 12, 201 1, December 14,

2012, and Decembefr14, 2012, respectively. The DNPS is located in Grundy County, Illinois,

on the shore of a man-made cooling lake, with the Illinois River to the north and the Kankakee

River to the east. The QCNPS is located in Rock Island County, Illinois, on the east bank of the

Mississippi River opposite the mouth of the Wapsipinicon River, and about 3 miles north of

Cordova, Illinois. Units 2 and 3 of the DNPS and Units 1 and 2 of the QCNPS each consist of a

General Electric boiling-water reactor (BWR/3) authorized to individually operate at a steadystate reactor power level not to exceed 2957 megawatts-thermal, or approximately 850

megawatts-electric. Details concerning the plant and the site are found in the updated final

safety analysis report (UFSAR) for DNPS/QCNPS.

The license renewal process proceeds along two tracks, which include both a technical review

of safety issues and an environmental review. The requirements for these two reviews are

specified in NRC regulations 10 CFR Parts 54 and 51, respectively. The safety review for the

DNPS and QCNPS license renewals is based on the applicant's LRA, docketed

correspondence, and the answers to requests for additional information (RAls) from the NRC

staff. In meetings and docketed correspondence, the applicant has also supplemented its

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

submitted through June 22, 2004. The public can review the LRA and all pertinent information

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

1-1
Rockville, Maryland 20852-2738. In addition, the DNPS/QCNPS LRA and significant

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

page at http://www.nrc.oov

This SER summarizes the findings of the staff's safety review of the DNPS/QCNPS LRA and

delineates the scope of the technical details considered in evaluating the safety aspects of the

proposed operation of the plants for up to an additional 20 years beyond the term of the current

operating licenses. The staff reviewed the LRA in accordance with NRC regulations and the

guidance presented in NUREG-1800, "Standard Review Plan for the Review of License

Renewal Applications for Nuclear Power Plants" (SRP-LR), which the NRC issued in July 2001.

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

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

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

Section 6 of the SER.

Appendix A is a list of commitments made by EGC. Appendix B is a chronology of the principal

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

Appendix C is a list of the principal NRC staff reviewers and its contractors for this project.

Appendix D is a list of the major references used in support of this SER.

In accordance with 10 CFR Part 51, the staff prepared plant-specific supplements to the

generic environmental impact statement (GEIS). These supplements discuss the

environmental considerations related to renewing the licenses for DNPS and QCNPS. The

plant-specific supplements to the GEIS were issued separately. The NRC staff issued

Supplement 17 to NUREG-1437, "Generic Environmental Impact Statement for License

Renewal of Nuclear Plants Regarding the Dresden Nuclear Power Station, Units 2 and 3," on

June 29, 2004, and Supplement 16 to NUREG-1437, "Generic Environmental Impact Statement

for License Renewal of Nuclear Plants Regarding the Quad Cities Nuclear Power Station, Units

1 and 2," on June 30, 2004.

1.2 License Renewal Background

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

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

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

basis of economic and antitrust considerations, rather than on technical limitations. However,

some individual plant and equipment designs may have been engineered on the basis of an

expected 40-year service life.

In 1982, the NRC anticipated interest in license renewal and held a workshop on nuclear power

plant aging. The NRC team then established a comprehensive program plan for nuclear plant

aging research (NPAR). On the basis of the results of that research, a technical review group

concluded that many aging phenomena are readily manageable and do not pose technical

issues that would preclude extending the life of nuclear power plants. In 1986, the NRC

published a request for comment on a policy statement that would address major policy,

technical, and procedural issues related to license renewal for nuclear power plants.

1-2
In 1991, the NRC published the license renewal rule in 10 CFR Part 54 (the Rule). The NRC

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

and develop experience to create implementation guidance. To establish a scope of review for

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

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

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

the review did not allow sufficient credit for existing aging management programs (AMPs),

particularly for the implementation of the Maintenance Rule (10 CFR 50.65), which also

manages plant aging phenomena.

As a result, in 1995, the NRC amended 10 CFR Part 54. The amended license renewal rule

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

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

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

unique to license renewal. The Rule changes were intended to ensure that important systems,

structures, and components (SSCs) within the scope of the Rule will continue to perform their

intended functions during the period of extended operation. In addition, the integrated plant

assessment (IPA) process was clarified and simplified to be consistent with the revised focus

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

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

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

and to fulfill, in part, the NRC's responsibilities under the National Environmental Policy Act of

1969 (NEPA).

1.2.1 Safety Reviews

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

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

operating plants provide and maintain an acceptable level of safety, with the possible

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

period of extended operation, as well as a few other safety-related issues.

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

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

In implementing these two principles, 10 CFR 54.4 defines the scope of license renewal as

including those plant SSCs (1) that are safety-related, (2) whose failure could affect

safety-related functions, and (3) that are relied on to demonstrate compliance with the NRC's

regulations for fire protection, environmental qualification (EQ), pressurized thermal shock

(PTS), anticipated transients without scram (ATWS), and station blackout (SBO).

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

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

(AMR). The SCs that are subject to an AMR are those that perform an intended function

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

subject to replacement based on a qualified life or specified time period. As required by

1-3
10 CFR 54.21 (a)(3), an applicant for a license renewal must demonstrate that the effects of

aging will be managed in such a way that the intended function or functions of the SCs that are

within the scope of license renewal will be maintained, consistent with the current licensing

basis (CLB), for the period of extended operation. Active equipment, however, is considered to

be adequately monitored and maintained by existing programs. In other words, the detrimental

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

identified and corrected through routine surveillance, performance monitoring, and maintenance

activities. The surveillance and maintenance programs for active equipment, as well as other

aspects of maintaining the plant design and licensing basis, are required to continue throughout

the period of extended operation.

Pursuant to 10 CFR 54.21 (d), the LRA is required to include a supplement to the updated final

safety analysis report (UFSAR). This UFSAR Supplement must contain a summary description

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

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

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

the initial length of time the plant will be operated, and these assumptions are incorporated into

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

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

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

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

operation.

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

Applications to Renew Nuclear Power Plant Operating Licenses"; NUREG-1800, "Standard

Review Plan for the Review of License Renewal Applications for Nuclear Power Plants" (SRPLR); and NUREG-1801, "Generic Aging Lessons Learned (GALL) Report." These documents

describe methods acceptable to the NRC staff for implementing the license renewal rule and

techniques used by the NRC staff in evaluating applications for license renewal. The RG

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

acceptable method of implementing the license renewal rule. The NEI guideline, NEI 95-10,

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

Renewal Rule," Revision 3, was issued in March 2001.

Exelon Generation Company is the fifth license renewal applicant to fully utilize the process

defined in NUREG-1801, otherwise known as the GALL Report. The purpose of the GALL

Report is to provide the staff with a summary of staff-approved AMPs for the aging of most SCs

that are subject to an AMR. If an applicant commits to implementing these staff-approved

AMPs, the time, effort, and resources used to review an applicant's LRA will be greatly reduced,

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

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

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

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

activities that the staff has determined will provide adequate aging management during the

period of extended operation.

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1.2.2 Environmental Reviews - ;

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

to facilitate environmental reviews for license renewal. The staff prepared the "Generic

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

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

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

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

These generic findings are identified as Category 1 issues in Subpart A of Appendix B to

10 CFR Part 51. Pursuant to 10 CFR 51.53(c)(3)(i), an applicant for license renewal may

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

impacts of license renewal that must be evaluated on a plant-specific basis (i.e., Category 2

issues) must be included in an environmental report in accordance with 10 CFR 51.53(c)(3)(ii).

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

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

and significant information was not considered in the GEIS. Two public meetings were held,

one near QCNPS on December 16, 2003, and one near DNPS on January 14,2004, as part of

the NRC's scoping process to identify environmental issues specific to each plant. The results

of the environmental reviews and recommendations on the license renewal actions are

documented in the NRC plant-specific Supplements 16 and 17 to the GEIS, which were issued

on June 30, 2004 and June 29, 2004, for QCNPS and DNPS, respectively.

1.3 Principal Review Matters

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

10 CFR Part 54. The staff performed its technical review of the DNPS/QCNPS LRA in

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

standards for renewing a license are contained in 10 CFR 54.29. This SER describes the

results of the staff's safety review.

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

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

DNPS/QCNPS, submitted by letter dated January 3,2003. The staff finds that the applicant

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

In 10 CFR 54.19(b), the Commission requires that license renewal applications (LRAs) include

"conforming changes to the standard indemnity agreement, 10 CFR 140.92, Appendix B, to

account for the expiration term of the proposed renewed license." The applicant stated the

following in Section 1.1.10 of its LRA regarding this issue:

The current indemnity agreement for Dresden and Quad Cities state in Article Vii that the agreement shall

terminate at the time of expiration of the licenses specified in Item 3 of the Attachment to the agreement.

Item 3 of the Attachment to the indemnity agreement, lists license numbers, DPR-19, DPR-25, DPR-29, and

DPR-30. Applicant requests that any necessary conforming changes be made to Article VII and Item 3 of

the Attachment, and any other sections of the indemnity agreement as appropriate to ensure that the

indemnity agreement continues to apply during both the terms of the current licenses and the terms of the

renewed licenses. Applicant understands that no changes may be necessary for this purpose if the current

license numbers for each of the units are retained.

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

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

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

In 10 CFR 54.21, the Commission requires that each LRA for a nuclear facility contain (a) an

IPA, (b) CLB changes during staff review of the LRA, (c) an evaluation of TLAAs, and (d) a

UFSAR Supplement. Sections 3 and 4 and Sections A and B of the LRA address the license

renewal requirements of 10 CFR 54.21(a), (c), and (d), respectively.

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

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

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

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

Supplement. The applicant's update to the LRA was issued on March 5, 2004.

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

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

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

DNPS/QCNPS. This adequately addresses the requirements of 10 CFR 54.22.

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

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

evaluation of the LRA in accordance with 10 CFR 54.21 and 10 CFR 54.22 is contained in

Sections 2, 3, and 4 of this SER.

The staff's evaluation of the environmental information required by 10 CFR 54.23 is contained

in the final plant-specific supplement to the GEIS, which states the considerations related to

renewing the licenses for DNPS/QCNPS. This was prepared by the staff separate from this

report. The report of the ACRS, required by 10 CFR 54.25, is incorporated into Section 5 of

this SER. The findings required by 10 CFR 54.29 can be found in Section 6 of this SER.

1.4 Interim Staff Guidance

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

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

lessons learned address the Commission's performance goals of maintaining safety, improving

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

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

interested stakeholders until the improved license renewal guidance documents are revised.

The current set of relevant ISGs and the SER sections in which the issues are addressed by

the staff are provided in the following table.

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Interim Staff Guidance for License Renewal

ISG Issue (Approved ISG No.) Purpose SER Section

Station Blackout (SBO) Scoping The license renewal rule 2.5.1.5.2

(ISG-02) 10 CFR 54.4(a)(3) includes 3.5.2.4.2

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

The SBO rule requires that a plant must withstand

and recover from an SBO event. The recovery time

for offsite power is much faster than that of

emergency diesel generators (EDG)s.

The offsite power system should be included within

the scope of license renewal.

Concrete Aging Management Lessons learned from the GALL demonstration 3.5.2.2.1

Program (ISG-03) project indicated that GALL is not clear whether 3.5.2.2.2

concrete need an AMP. 3.5.2.4.1

3.5.2.4.2

Fire Protection (FP) System Piping This ISG clarifies the staff position on wall thinning 3.3.2.3.2

(ISG.04) of FP piping system in GALL AMPs XL.M26 and 3.3.2.3.3

XL.M27. 3.3.2.4.6

The new position is that there is no need to

disassemble FP piping, as oxygen can be

introduced in the FP piping which can accelerate

corrosion. Instead, non-intrusive methods such as

volumetric inspection should be used.

Testing of sprinkler heads should be performed

every 50 years and 10 years after initial service.

This ISG eliminated Halon/carbon dioxide system

inspections for charging pressure, valve line ups,

and automatic mode of operation test from GALL.

The staff considers these test verifications to be

operational activities. -

Identification and Treatment of This ISG includes fuse holder AMR and AMP (i.e., 3.6.2.4.1

Electrical Fuse Holder (ISG-05) same as terminal blocks and other electrical

connections).

The position includes only fuse holders that are not

inside the enclosure of active components (e.g.,

inside of switchgears and inverters).

Operating experience finds that metallic clamps

(spring-loaded clips) have a history of age-related

failures from aging stressors'such as vibration,

thermal cycling, mechanical stress, corrosion, and

chemical contamination.

The staff finds that visual inspection of fuse clips is

not sufficient to detect the aging effects from

fatigue, mechanical stress, and vibration.

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1.5 Summary of Open Items

As a result of its review of the LRA for QCNPS and DNPS, including additional information

submitted to the NRC through June 22, 2004, the staff identified the following open items. An

issue was considered open if the applicant had not presented a sufficient basis for resolution.

Each open item (01) has been assigned a unique identifying number. The items identified in this

section have been properly closed by the technical staff.

01-2.1-1: (Section 2.1.3.1.2 - Application of the Scoping Criteria in 10 CFR 54.4(a)(2))

The staff determined that the applicant did not provide a sufficient basis for limiting

consideration of fluid spray interactions to only those non-safety-related SSCs located within 20

feet of an active safety-related SSC. In particular, the staff required additional clarification

regarding the capability of active and passive safety-related SSCs located greater than 20 feet

from a potential spray source to tolerate wetting, the specific operating experience that was

relied upon to determine that it was not credible for fluid sprays to affect equipment greater than

20 feet from a failure location, specific methods to detect leakage in normally accessible and

inaccessible areas, and justification for use of exposure duration in limiting the scope of

potential failure mechanisms considered during scoping. This issue was identified as Open

Item 2.1-1.

The applicant responded to Open Item 2.1-1 by letters dated April 9, 2004 and May 18, 2004

(ADAMS Accession Nos. ML041070456, and ML041480178). In addressing this open item, the

applicant revised the scoping methodology for nonsafety-related moderate energy piping

systems that have the potential to spatially interact with safety-related systems. Specifically,

the applicant eliminated the 20 foot separation criterion and credit for the early detection of

leakage that was previously used to exclude certain moderate energy nonsafety-related piping

and components from the scope of License Renewal. The revised methodology assumes that

all safety-related components, active as well as passive, could be adversely affected by spray

or wetting from a non-safety moderate energy system located in the same general area of the

plant. Therefore, the applicant stated that all components from moderate energy nonsafetyrelated systems located in the same general area as a safety-related component (active or

passive) would be included within the scope of license renewal. The applicant defined "General

area" as the same floor (elevation) of a major building with no barrier walls between the fluid

source and the safety-related component. Barrier walls were defined as barriers that form the

boundary of a room on the same elevation of a major building separating the safety-related

components from a spray or leak generated by a non-safety-related component located on the

other side of the barrier wall. The applicant stated that all barrier walls credited for protection of

safety-related components were previously included within the scope of license renewal during

structural scoping and subject to aging management review.

In accordance with the revised methodology, the applicant expanded the license renewal

boundaries of seventeen systems previously determined to be within the scope of license

renewal and identified an additional intended function for the main condenser at Quad Cities.

Additionally, the applicant added the following five nonsafety-related systems to the scope of

license renewal that were previously excluded from the scope of license renewal: circulating

water (Dresden and Quad Cities), laundry (Dresden), zinc addition (Dresden and Quad Cities),

extraction steam (Quad Cities), and feedwater heater vents and drains (Quad Cities) . In its

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May 18, 2004 response to Open ltem62.1-1, the applicant identified LRA revisions, scoping

results changes, and aging management program changes required as a result of the scoping

methodology revision. The staff review of these revised scoping results and associated aging

management programs are described in Sections 2.3 and 3.0.5 of this report.

On the basis of the above, the staff concludes that the applicant adequately resolved the issues

identified in Open Item 2.1-1. Specifically, the elimination of the twenty foot limitation on spray

interactions, consideration of potential adverse effects for both active and passive safetyrelated equipment, and elimination of credit for early detection of leakage adequately

addressed the staff's methodology concerns. Furthermore, the staff determined that the

applicant's revised methodology considered a reasonable spectrum of potential nonsafetyrelated spatial interactions with safety-related equipment. Therefore,-the staff concludes that

the revised methodology for scoping nonsafety-related equipment provides reasonable

assurance that the applicant considered nonsafety-related SSCs whose failure could prevent

satisfactory accomplishment of a safety-related intended function within the scope of license

renewal. On this basis, Open Item 2.1-1 is resolved.

01-3.5.2.3.2-1: (Section 3.5.2.3.2- ASME Section Xi, Subsection IWF (B.1.27))

Some of the Class MC supports discussed by the applicant in the RAI responses regarding

Class MC supports seemed to be inaccessible. Therefore, the staff needed to better

understand how the applicant is treating these supports. This was identified as Open Item

3.5.2.3.2-1.

To resolve the concerns, the staff requested the applicant to provide the following information:

(a) Identify each type of Class MC support by name and confirm whether the support will be

inspected under IWF during the period of extended operation. Provide a technical

explanation for those supports that are proposed to be inspected under another program

(such as IWE or Structures Monitoring) or for cases where no inspection is planned.

(b) Since Class MC supports are not currently being inspected, provide a commitment to

perform a baseline inspection of typical samples of each type of Class MC component.

support prior to the period of extended operation, to identify and correct any problems

affecting performance of intended functions.

(c) Describe how the performance of Class MC component supports in inaccessible areas

are currently being managed and how they will be managed during the period of

extended operation. Clarify the commitment to the provisions of 10 CFR 50.55(a)

covering inaccessible areas.

(d) Review the response to RAI 2.4-2 and identify the aging management program

applicable to each item (a) through (k). Also verify the consistency of this RAI response

with the response to RAI 2.4-10.

The applicant submitted the responses by letter dated April 9, 2004. *After reviewing the

applicant's responses, the staff accepts the applicant's proposed use of its Structures

Monitoring Program as an alternate AMP to the GALL's ASME IWF program for its Class MC

piping supports, with the following modifications.

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Modification #1 states that the sample size of the Class MC piping supports should be 15% of

the support population, as stipulated in Table IWF-2500-1, because the ten sample supports

proposed by the applicant were insufficient.

Modification #2 states that the person who performs the inspection should have demonstrated

knowledge of inspection attributes on Class MC piping supports and should be under oversight

guidance from the administrator or his designee during the initial inspection activity.

Modification #3 states that a baseline inspection should be performed on the sample supports

prior to the period of extended operation.

The applicant submitted its revised responses in a letter dated June 22, 2004. The responses

satisfactorily resolve the sample size and inspector's qualification issues. However, the staff

was not sure whether the applicant intended to only revise its Structures Monitoring Program

prior to the period of extended operation or actually have the MC supports and MC piping

sample supports inspected prior to the period of extended operation. In a telephone

conference on July 13, 2004, the applicant clarified that a baseline inspection would be

performed for these supports prior to the period of extended operation. This is part of

Commitment #30 in Appendix A of this SER. The staff considers the Open Item 3.5.2.3.2-1

resolved.

01-4.2.1 (c): (Section 4.2.2.1 - Reactor Vessel Materials Upper-Shelf Energy Reduction Due to

Neutron Embrittlement)

In RAI 4.2.1(c), the staff requested the applicant to provide all fluence data for all welds and

plates in the beltline and specify which one is bounding with respect to the RPV USE

evaluation. In response to RAI 4.2.1 (c), in a letter dated October 3, 2003, the applicant

provided 54-EFPY surface fluences and 54 EFPY 1/4T fluences for all the beltline material but

identified materials that are bounding with respect to the RPV material ART values at 54-EFPY.

The applicant also needed to identify the USE for all beltline materials at 54-EFPYs and to

identify the limiting materials for each unit. This was identified as Open Item 4.2.1 (c).

The applicant's April 9, 2004, letter indicated that all beltline materials, except for the

electroslag welds (ESWs) in Quad Cities Unit 2, will have predicted Charpy USE greater than

35 ft-lb, the minimum allowable USE based on the generic BWR equivalent margins analysis

documented in BWROG topical report entitled, " 10 CFR Part 50 Appendix G Equivalent Margin

Analysis for Low Upper Shelf Energy in BWR/2 Through BWR-6 Vessels." Therefore, all

beltline materials, except for the ESW in Quad Cities Unit 2, meet the margins of safety against

fracture equivalent to those required by Appendix G of Section Xl of the ASME Code.

The applicant reevaluated the USE value for Quad Cities Unit 2 ESW using all electroslag weld

material surveillance test results from Quad Cities Unit 2, and performed a plant-specific EMA

for the Quad Cities Unit 2 ESW. General Electric report GE-NE-0000-0027-0575-01, Revision

0, "The Upper Shelf Energy Evaluation for RPV Electroslag Welds at Quad Cities Unit 2,"

issued March 5, 2004, included in the applicant's April 9, 2004 letter, contains this analysis.

Using the limiting surveillance capsule 18 data and the methodology in RG 1.99, Revision 2, the

predicted Charpy USE for the ESW welds is 34.2 ft-lb, which is below the minimum established

in the generic BWROG topical report. The applicant's plant-specific EMA was performed using

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methods and criteria contained in RG'1.161, "Evaluation of Reactor Pressure Vessels with

Charpy Upper-Shelf Energy less than 50 Ft-Lb." and Appendix K of ASME Code, Section Xl.

Appendix K and RG 1.161 provide acceptance criteria and evaluation procedures for

; determining acceptability for operation of a reactor vessel when the vessel metal temperature is

in the upper shelf range. The methodology is based on the principles of elastic-plastic fracture

mechanics. Flaws will be postulated in the reactor vessel at locations of predicted low upper

shelf Charpy impact energy, and the applied J-integral for these flaws will be calculated and

compared with the J-integral fracture resistance of the material to determine acceptability. The

applicant's analysis showed that the applied J-integral of the postulated flaws and the J-integral

material fracture resistance with a minimum USE of 32.4 ft-lb satisfies the criteria of Appendix K

of the ASME Code, Section Xl and RG 1.161.

The analysis methods in Appendix K of the ASME Code initially followed the methodology in RG

1.161. The analysis methods in Appendix K of the ASME Code, Section Xl were changed in

the 1995 Addenda to the 1995 Edition. The analysis method in the 1995 Addenda to the 1995

Edition of the ASME Code changed the method of calculating the contribution to the applied Jintegral because of a radial thermal gradient. This change was incorporated into the ASME

Code to more accurately represent the contribution to the applied J-integral due to a radial

thermal gradient. The applicant's analysis was performed using the earlier analysis method,

i.e., the methods contained in RG 1.161. The staff confirmed the EMA using the analysis

methods in both Appendix K to the ASME Code, Section Xl, 1995 Addenda to the 1995 Edition,

and the earlier analysis method in RG 1.161. This analysis included the effects of the extended

power uprate condition. Since the limiting end of extended life USE for Quad Cities Unit 2 ESW

exceeds the minimum value of 32.4 ft-lb demonstrated in the applicant's plant-specific EMA, the

staff concludes that all beltline materials, including the ESW in Quad Cities Unit 2 RPV meet

the margins of safety against fracture equivalent to those required by Appendix G of Section Xl

of the ASME Code. Therefore Open Item 4.2.1 (c) is closed.

Ol-B.1.23-2: (Section 3.0.3.10.2 - One Time Inspection (B.1.23) - Plant Heating System

components) and (Section 3.4.2.4.1 Main Steam System-One Time Inspection (B.1.23) - Plant

Heating System components)

By RAls B.1.23-1, B.1.23-2, B.1.23, and 3.1.23-2.1 through B.1.23-2.6, the applicant was

requested to justify use of the One-Time Inspection program to manage aging effects for

various carbon steel, alloy steel, stainless steel, cast iron, and neoprene components in

environments such as moist air, steam, water (condensate), and containment atmosphere. By

letters dated October 3, 2003, January 26, 2004, and March 25, 2004, the applicant responded

to the staff's RAls as follows:

1) By RAls B.1.23-1, B.1.23-2(a), B.1.23-2.3 and B.1.23-2.4, the staff questioned use of the

One-Time Inspection program to manage loss of material and cracking for carbon steel,

stainless steel, cast iron, brass or bronze, and iron components in lube oil and fuel oil

environments. This was identified as Confirmatory Item B.1.23-1. By letters dated October 3,

2003, January 26, 2004 and April 9, 2004, the applicant stated that aging management

program, B.2.5, "Lubricating Oil Monitoring Activities," will be expanded to manage loss of

material and cracking for oil coolers and other components in lube oil, turbine electro-hydraulic

control (EHC) fluid, and generator hydrogen seal oil environments for the emergency diesel

generator system, station blackout diesel generator system, high pressure coolant injection

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system, electro-hydraulic control system, reactor core isolation cooling system (Quad Cities),

and generator hydrogen seal oil system (Quad Cities). Aging management program, B.1.23,

"Fuel Oil Chemistry," will be expanded to manage loss of material for components in a fuel oil

environment for the station blackout diesel generator system. The One-Time Inspection

program will not be credited to manage the aging effects for these components since periodic

inspections will be implemented. The staff considers the Lubricating Oil Monitoring Activities

and Fuel Oil Chemistry aging management programs appropriate to manage these aging

effects; therefore, staff finds this acceptable.

2) Table 3.3.2 of the LRA identifies components in the Plant Heating System which credit the

One-Time Inspection program to manage aging effects for components in a saturated steam or

condensate environment. By RAls B.1.23-1 and B.1.23-2(a) & (b), staff requested the applicant

to justify use of one-time inspections to manage the aging effects for these components. By

letters dated January 26, 2004 and March 25, 2004, the applicant stated that Plant Heating

System components in a saturated steam or condensate environment would be managed by

aging management program, B.2.8, "Periodic Inspection of Plant Heating System." The

program includes periodic inspections to manage cracking, loss of material, or leakage of

selected brass/bronze, carbon steel, cast iron, and stainless steel components. The staff

considers the Periodic Inspection of the Plant Heating System program appropriate to manage

these aging effects; therefore, staff finds this acceptable.

3) For the main steam system flexible hoses in a containment nitrogen environment, Reference

Number 3.4.2.18 of the LRA does not identify any aging effects for these neoprene hoses. By

RAls 3.4.1-3 and B. 1.23-2.1, staff requested the applicant to justify with respect to temperature,

radiation levels, and time, why neoprene hoses do not require aging management. In

responses dated October 3, 2003 and January 26, 2004, further review by the applicant

indicated that hoses in Reference Number 3.4.2.18 and 3.4.2.19 of the LRA are not comprised

of an elastomer material as earlier reported but are made of stainless steel with an overall

stainless steel outer braided jacket. Based on the hose material being stainless steel, the

applicant will use the One-Time Inspection program to verify that the hoses are constructed of

metal rather than an elastomer material. Any hoses found to be constructed of an elastomer

during the one-time inspection will be replaced with metal flexible hoses. The One-Time

Inspection program will perform inspections of the installed metal hoses for mechanical

damage. This applies to Quad Cities only. The applicant has noted that stainless steel hoses

are installed at Dresden. The staff considers use of the One-Time Inspection program

acceptable to verify that stainless steel hoses are installed and to inspect the stainless steel

hoses for damage.

4) For non-safety-related (NSR) vents or drains, piping, and valves in various systems, the LRA

identifies loss of material due to corrosion for carbon steel, stainless steel, brass, or bronze in

an environment of air, moisture, humidity, and leaking fluid. By RAI 3.3-2, the staff requested

the applicant to describe the types of corrosion expected and to provide criteria for selecting

one-time sample locations for these types of corrosion. The applicant stated in its letter dated

October 3, 2003 that general, crevice, and pitting corrosion are expected in these components.

The applicant compiled a list of the in-scope NSR vents and drains for the various systems

throughout the plants. The One-Time Inspection program will inspect a selected number of

NSR vent and drains for the affected systems. The sample population will be representative of

all material and environment combinations but may not include components for every system.

The criteria used for selection of susceptible inspection locations are as follows: 1)

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Corrosiveness of fluid passing through the vent, drain, or piping when in service. Those

components servicing more corrosive fluids are given preference. 2) Duration of service when

performing venting and draining operations. Those components with higher durations of

service are given preference. 3) Frequency of performance of venting and draining operations

through the selected components. Those components with higher performance frequencies are

given preference. 4) Period that component has been in service. Those components that have

been in service longest are given preference. By RAIs B.1.23-2(b) and B.1.23-2.2, staff

requested further justification that a one-time inspection is adequate to manage the aging

effects for these vent, drains, and valves. By letters dated October 3, 2003 and January 26,

2004, the applicant stated that the NSR vents, drains, valves, and piping are normally outboard

of closed safety relief valves or closed isolation valves and are not likely to contain moisture.

Any appreciable leakage or condensation inside these vents and drains would be identified in

the course of periodic operations or through the daily monitoring of unidentified inputs to

radwaste by the operating department. Malfunctioning isolation valves or other degraded

conditions are promptly repaired, replaced, or corrected. For the reasons stated above, the

applicant considers the rate of material loss due to corrosion to be slow; therefore, one-time

inspections will confirm the assumption that loss of material due to corrosion is occurring at a

sufficiently slow rate for the subject components. In the event that the results of the one-time

inspections fail to provide this confirmation, evaluations will be performed in accordance with

the site corrective action process to identify actions, including possible periodic inspections of

the vents and drains. Based on the applicant's response, staff concurs that the loss of material

due to corrosion for the subject vents, drains, piping, and valves are considered to occur at a

sufficiently slow rate such that a one-time inspection is adequate to manage this aging effect;

therefore, staff finds this acceptable.

(5) By RAls B.1.23-2 and B.1.23-2.6, the staff requested the applicant to provide justification for

using one-time inspections to manage carbon steel, cast iron, alloy steel, elastomer, and

neoprene components in a moist air environment that 1) varies with normal plant conditions, 2)

is impractical to monitor or control routinely, and 3) is similar to the environments associated

with the Aging Management References listed in part b of RAI B.1.23-2. This was identified as

Open Item B.1.23-2. By letter dated March 25,2004, the applicant concluded by further review

that periodic inspections of components in this population would be appropriate. A new aging

management program, B.2.9, "Periodic Inspection of Components Subject to Moist Air

Environments," was developed for these components. Specifically, the applicant will perform

periodic inspections of a representative sample of stainless steel, carbon steel, cast iron,

aluminum, copper, brass, and bronze components normally exposed to environments of air and

steam; moist air; saturated air; warm moist air; moist containment atmosphere; steam or

demineralized water; and hot diesel engine exhaust gases containing moisture and particulates.

In addition, the program inspects flexible hoses to detect age-related degradation prior to the

loss of function.

The applicant considers a one-time inspection appropriate for managing aging effects for the

standby gas treatment system and HVAC systems components with an internal environment of

occasional exposure to moist air" and an external environment of "ambient plant air" or "warm

moist air." Components in these systems include doors, closure bolts, equipment frames,

piping, fittings, valves, ducts, and filters fabricated of cast iron, carbon steel, brass, bronze,

stainless steel, and copper. Based on the materials and environments for these ventilation

system components, the applicant believes that 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

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- - -

progress very slowly. Based on favorable operating history that revealed no widespread

corrosion in the affected system, a limited number of components were selected as

representative of the ventilation systems. The worst-case one-time inspection locations will

include the following: the air intake ductwork of the standby gas treatment system; main control

room HVAC ductwork; emergency diesel generator HVAC air intake ductwork; reactor building

HVAC ductwork downstream of the steam coils and chilled water cooling coils; and main control

room HVAC drip pan and drainpipe. If the one-time inspection detects corrosion resulting in

material loss, results of the examination will be evaluated by engineering to determine the rate

of material loss and the need for additional inspections. Unacceptable results will be

documented in the corrective action program.

Based on the applicant's response, staff considers the Periodic Inspection of Components

Subject to Moist Air Environments acceptable to manage components in a moist air

environment and the One-Time Inspection program acceptable to manage ventilation systems

components 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.

Therefore Open Item B.1.23-2 and Confirmatory Item B.1.23-1 are closed.

1.6 Summary of Confirmatory Items

As a result of its review of the LRA for QCNPS and DNPS, including additional information

submitted to the NRC through June 22, 2004, the staff identified the following confirmatory

items. An issue was considered confirmatory if the staff and the applicant have reached a

satisfactory resolution, but the resolution has not yet been formally submitted to the staff. Each

confirmatory item (Cl) has been assigned a unique identifying number. The items identified in

this section have been properly closed by the technical staff.

Cl.2.3.4.2-3: (Section 3.1.2.4.1 - Reactor Vessel)

The staff needed the following information from the applicant so that it can evaluate the aging

management of the capped CRD nozzles-(1) description of the configuration and location of

the capped nozzle including the existing base material for the nozzle, piping (if piping remnants

exist) and cap material, and any welds and material type (i.e., 82/182), (2) description of how

these welds and caps are managed (e.g., the applicability of the BWRVIP-75 inspection

requirements); and (3) discussion on whether the event at Pilgrim (leaking weld at capped

nozzle, September 30, 2003) is applicable to Dresden and Quad Cities. A description of the

Pilgrim event is discussed in LER 2003-006-00, dated November 24, 2003, which states that

the cracking was in an 82/182 weld metal that was repaired extensively. The applicant also

needed to include in the discussion the past inspection techniques applied, the results obtained,

mitigative strategies followed, weld repairs carried out, and any other relevant information. This

was identified as Confirmatory Item 2.3.4.2-3.

In the applicant's letters dated January 26, 2004, and April 9, 2004, the applicant responded to

supplementary RAI 2.3.4.2-3. In the applicant's letters, the applicant provided information

related to configuration and locations of the capped nozzles for each plant and described how

they are managed. At Dresden and Quad Cities, the configuration consists of 304L and 316L

SS caps and safe-ends welded to the original carbon steel nozzles. Aging management for

these components includes examination in accordance with Section Xl of the ASME Code for

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the nozzle as stated in AMP B.1.6, "ORD Return Line Nozzle," and one-time inspection in

accordance with AMP B.1.23, "One-Time Inspections" for the remaining portion (safe-end, cap

and welds). AMP B.1.2, 'Water Chemistry" is also credited for these components.

In addition, the applicant stated that the Pilgrim event does not apply to Dresden and Quad

Cities because (1) Pilgrim used an Alloy 600 cap welded directly to the nozzle whereas

D/QCNPS used a SS cap and installed a SS safe-end between the cap and the nozzle, (2)

Pilgrim used Alloy 82/182 welds whereas D/QCNPS used 308L and 309L SS welds, and (3)

Pilgrim had initial weld defects (lack of fusion) that required repair, whereas D/QCNPS welds

were completed without requiring any repair. D/QCNPS further stated that their nozzles and

caps had radiographic and penetrant testing performed during installation, and had subsequent

ultrasonic inspection of the nozzle-to-safe end welds and safe end-to-cap welds in response to

the Pilgrim event with no reportable indications. Also, per the D/QCNPS ISI programs,

penetrant testing had been performed on these welds with no recordable'indications. In

addition, Dresden and Quad Cities have placed their capped lines (small bore piping-less than 4

inches) in the One-Time Inspection Program, B.1.23. The staff finds the applicant's response

acceptable because it uses low carbon stress corrosion resistant stainless steel safe-ends,

caps, and weld material in lieu of Alloy 600, which has been known to be susceptible to stress

corrosion cracking based on operating experience. In addition, the caps were welded using low

carbon stainless steel weld metal (308L and 309L) with no weld repairs or recordable defects.

Pilgrim used Inconel 82/182 and had initial weld defects that required weld repairs, which may

have contributed to the cracking. Therefore, Dresden and Quad Cities capped return line

nozzle configuration is not similar to Pilgrim and the use of AMPs B.1.2, B.1.6 and B.1.23 is

acceptable for managing the aging of these components. Therefore, Confirmatory Item

2.3.4.2-3 is closed.

CI.3.0.3.14.2-1: (Section 3.0.3.14.2- Structures Monitoring Program (B.1.30))

The additional information provided by the applicant in its response to RAI B.1.30 sufficiently

answers the questions posed by the staff, with two exceptions. It was not clear whether the

category "Piping Component Supports including immediately adjacent piping/tubing," listed in

the response to item (a) of the RAI is meant to include non-ASME piping supports. It also was

not clear as to why the Structures Monitoring Program does not include "standard components

such as snubbers, struts and spring cans." In order to completely resolve the response to this

RAI, the staff requested that the applicant confirm the following:

(a) the B.1.30 program covers non-ASME piping supports

(b) there are no snubbers, struts and spring cans on non-ASME piping and components

This issue was identified as Confirmatory Item 3.0.3.14.2-1.

In its response to Confirmatory Item 3.0.3.14.2-1, dated December 5, 2003, the applicant

stated:

Exelon has reviewed the supplemental Information Request and provides the following clarification and

confirmation.

1)The Structure Monitoring Program, B.1.30, includes non-ASME piping supports for aging management. The

selection of component supports includes a representation of supports throughout the plant, considering

environmental conditions as well as configuration.

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2)There are standard components such as snubbers, struts, and spring cans on non-ASME piping and

components that are in-scope of the License Renewal, which are required to be managed for aging. The

Structural Monitoring Program, B.1.30, will inspect the non-ASME component supports including the standard

components. The in-scope non-ASME component supports are addressed in LRA Section 2.4.15, Table 2.4-15

under the Component Groups Support Members" with a 'Non-S/R Structural Support' component intended

function. Aging Management Reference 3.5.1.29 discusses the aging management of the non-ASME

component supports.

The staff finds the applicant's response to Confirmatory Item 3.0.3.14.2-1 to be acceptable,

because it clarified that the "Structural Monitoring Program," B.1.30, will inspect non-ASME

piping and component supports, including snubbers, struts, and spring cans. This commitment

is stated in the enhancements as "The program will provide for inspection of a sample of

non-insulated indoor piping external surfaces at locations immediately adjacent to periodically

inspected piping supports and inspection of standard components such as snubbers, struts,

and spring cans." under B.1.30, Structures Monitoring Program, in the applicant's response to

01-3.5.2.3.2 1: (Section 3.5.2.3.2- ASME Section XI, Subsection IWF (B.1.27)), dated June 22,

2004. Therefore Confirmatory Item 3.0.3.14.2-1 is resolved. This is part of Commitment #30 in

Appendix A of this SER.

Cl.3.1.2.3.2-1: (Section 3.1.2.3.2 - BWR Vessel ID Attachment Welds Program)

In RAI 4.2-BWRVIPs, the staff requested the applicant to submit the necessary commitments,

information, and changes for each of the following applicable BWRVIP reports:

* BWRVIP-05

* BWRVIP-18

* BWRVIP-25

* BWRVIP-26

* BWRVIP-27

* BWRVIP-38

* BWRVIP-41

* BWRVIP-42

* BWRVIP-47

* BWRVIP-48

* BWRVIP-49

* BWRVIP-74

* BWRVIP-75

* BWRVIP-76

* BWRVIP-78

* BWRVIP-86

* Other BWRVIP reports applicable to license renewal

In response to RAI 4.2-BWRVIPS, in a letter dated October 3, 2003, the applicant summarized

the NRC's request for information in the seven elements listed below and presented its

response to each of those elements.

(1) Verify that Dresden and Quad Cities are bounded by the conditions (materials configuration

and inspection methodologies) specified in the applicable BWRVIP documents.

Response: The BWRVIP documents were assembled with participation from the NSSS

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supplier and a wide representation from the BWR Owners Group, providing a level of

confidence in accuracy and bounding conditions of these documents.- However, during a

preliminary review when preparing this response, some material differences were noted.

Exelon will perform a detailed review of the applicable BWRVIP documents and verify that

Dresden and Quad Cities are bounded by the conditions specified or identify and evaluate any

exceptions noted.

(2) Provide a commitment to implement programs consistent with the applicable BWRVIP

documents or identify the applicable exceptions.

Response: At the completion of the review noted in item 1 above, Exelon will provide a list of

commitments to the applicable BWRVIP documents or identify specific exceptions taken.

(3) Describe how the commitments will be tracked.

Response: The commitments, once identified, will be placed in the site implementing

procedures with traceability back to the license renewal commitment being made.

(4) Summarize a program description of the applicable BWRVIP documents in the LRA

Appendix A, UFSAR Supplement.

Response: Several of the BWRVIP programs are identified in the LRA Appendix A, such as

BWRVIP-75, A.1.7; BWRVIP-27, A.1.8; BWRVIP-48, A.1.4; BWRVIP-49, A.1.8; BWRVIP-78,

A.1.22; and BWRVIP-86, A.1.22. Once the comprehensive list of commitments is identified in

item 2 above, Exelon will update the LRA Appendix A to provide a summary program

description to address each applicable BWRVIP document.

(5) Verify that technical specification changes needed to support implementation of the

applicable BWRVIP documents have been identified and processed.

Response: There are no additional technical specification changes anticipated. However, once

the detailed review summarized in item 1 above is complete, Exelon will confirm that no

technical specification changes are needed or identify the needed changes to be processed

prior to the start of the extended term of operation.

(6) Identify and evaluate any potential TLAA issue identified by the applicable BWRVIP

documents and/or commitments to perform future inspections when inspection tooling is made

available.

Response: All applicable TLAAs are discussed in Section 4 of the LRA.

(7) Address items 1 through 6 above for the 16 specific BWRVIP documents listed in the RAI

and identify and address other BWRVIP documents applicable to license renewal.

Response: Based on a preliminary review, there appears to be several other BWRVIP

documents applicable to license renewal, such as BWRVIP-07 and BWRVIP-63 for core shroud

repairs, and BWRVIP-26 for Water-Chemistry. Once the detailed review is completed, Exelon

will provide an amended response addressing items 1 through 6 for all BWRVIP documents

applicable to license renewal.

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The staff found the applicant's response incomplete. The response committed to perform a

detailed review of the BWRVIP documents applicable to license renewal, prepare an amended

response addressing items 1 through 7 for all of those documents applicable to license renewal,

and submit it to the staff for review and approval. Therefore, this response was incomplete until

an amended response was submitted and approved by the staff. This was identified as

Confirmatory Item 3.1.2.3.2-1.

In a letter dated April 9, 2004, the applicant submitted the following amended response to RAI

4.2-BWRVIPs addressing the seven items, which were listed in the initial response to RAI

4.2-BWRVIPs, for all of the BWRVIP documents applicable to license renewal.

1. Verify that Dresden and Quad Cities are bounded by the conditions (materials, configuration

and inspection methodologies) specified in the applicable BWRVIP documents.

Amended Response: The site-specific procedures at DIQCNPS implemented all of the

inspection methodologies contained in the applicable BWRVIP documents. Additionally, the

materials and configurations at D/QCNPS are similar to those specified in the BWRVIP

documents with an exception related to the steam dryer hold-down bracket attachment weld

(addressed in response to Supplementary RAI B.1.4). Regarding inspection methodologies,

the applicant has identified two exceptions related to BWRVIP-74: (1) use of risk-informed ISI

to supplement the ISI and GL 88-01 programs for reactor pressure vessel nozzles and safe

ends, and (2) use of an NRC-approved code case for the inspection of the reactor vessel leak

detection line. The first exception is evaluated in SER Section 3.1.2.4.1 and the second one in

SER Section 3.1.2.2.4.

2. Provide a commitment to implement programs consistent with the applicable E3WRVIP

documents or identify the applicable exceptions.

Amended Response: D/QCNPS provided a commitment for implementing the programs

consistent with the applicable BWRVIP documents and identified several exceptions. These

exceptions are associated with BWRVIP-38, BWRVIP-41, BWRIP-74, and BWRVIP-75 and are

described in SER Sections 3.1.2.3.6 and 3.1.2.4 as appropriate. In addition, the applicant has

committed to implement several BWRVIP reports that are being reviewed by the NRC, and will

identify any exceptions associated with these reports after the staff's reviews are completed.

See amended response 7 for the several BWRVIP reports being reviewed by the NRC. This is

part of Commitment #9 in Appendix A of this SER.

3. Describe how the commitments will be tracked.

Amended Response: All license renewal commitments are controlled by the Exelon

commitment management process described in LS-AA-1 10, Commitment Management.

Commitment tracking files will be generated for each individual activity credited to implement

the requirements of the AMP. In addition, steps in site procedures that implement the various

activities specified in the BWRVIP documents are annotated as NRC commitments and are

referenced to commitment tracking files that contain sufficient documentation describing the

source of the commitment.

4. Summarize a program description of the applicable BWRVIP documents in the LRA

Appendix A, UFSAR Supplement.

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Amended Response: The FSAR Supplement (LRA Appendix A) Programs A.1.1, A.1.2, A.1.4,

A.1.8, A.1.9, and A.1.22 have been updated to reflect the applicable BWRVIP documents, and

exceptions as noted in response to Item 2 above. A revised FSAR supplement incorporating

these changes was submitted to NRC in the attachment to Exelon transmittal letter dated March

5, 2004 as part of the annual update required by 10 CFR 54.21 (b).

5. Verify that technical specification changes needed to support implementation of the

applicable BWRVIP documents have been identified and processed.

Amended Response: The only Technical Specification change required for both sites involves

revision to the site pressure temperature (P-T) curves. The existing P-T curves will be revised

for 54 EFPY prior to the extended term of operation.-

6. Evaluate any potential TLAA issue identified by the applicable BWRVIP documents and/or

commitments to perform future inspections when inspection tooling is made available.

Amended Response: All applicable TLAA's were discussed in Section 4 of the LRA. The

applicant also committed to perform future inspections, as recommended by the BWRVIP

documents, when inspection tooling is made available. This commitment is discussed in SER

Section 3.1.2.3.6.

7. Address Items 1 through 6 above for the 16 specific BWRVIP documents listed in the RAI

and identify and address other BWRVIP documents applicable to license renewal.

Amended Response: In addition to the 16 specific BWRVIP documents listed in RAI

4.2-BWRVIPs, the applicant has identified four additional documents applicable to license

renewal: BWRVIP-29, BWRVIP-79, BWRVIP-104, and BWRVIP-116. NRC has issued a safety

evaluation report for the first document (BWRVIP-29) but not for the remaining three. However,

the applicant has provided an amended response in their letter dated April 9, 2004, addressing

items 1 through 6 for all 20 BWRVIP documents applicable to license renewal and has

committed to implement these 20 BWRVIP documents as discussed in the amended response

to Item 2.

The staff found the responses to RAI 4.2-BWRVIPs acceptable because they addressed all the

license renewal applicant action items as identified in the applicable BWRVIP reports, which are

listed in the response. In addition, the exceptions identified by the applicant are approved by

the staff. The staff has reviewed the updated FSAR Supplement programs and found that they

include adequate summary descriptions of the applicable BWRVIP documents. Thus the

responses are consistent with the BWRVIP reports applicable to license renewal. Therefore,

Confirmatory Item 3.1.2.3.2-1 is closed.

Cl.3.1.2.3.6-1: (Section 3.1.2.3.6 - BWR Vessel Intemals Program)

The staff issued RAI B.1.9-b requesting the applicant to confirm whether D/QCNPS follows the

BWRVIP-25 guidelines for managing aging of the rim hold-down bolts and, if so, to identify and

evaluate whether the projected stress relaxation-in the rim hold-down bolts is a TLAA issue. In

response to RAI B.1.9-b, in a letter dated October 3, 2003, the applicant stated that D/QCNPS

follows the BWRVIP-25 guidelines for management of the hold-down bolts. However, the

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-

D/QCNPS core plates had wedges installed along with the repair of their shrouds with tie rods.

The applicant further stated that BWRVIP-25 does not recommend inspection of rim hold-down

bolts if wedges are installed. The staff reviewed BWRVIP-25 and confirmed the accuracy of

the applicant's statements made in this response. The staff finds the applicant's response

acceptable because it follows the recommendations of BWRVIP-25, which is approved by the

staff. However, the applicant did not identify whether stress relaxation in the rim hold-down

bolts is a TLAA. This was identified as Confirmatory Item 3.1.2.3.6-1.

In response, the applicant stated that the stress relaxation of the rim hold-down bolts is not a

TLAA for Dresden or Quad Cities. Dresden and Quad Cities have installed wedge retainers,

which structurally replace the lateral load resistance provided by the rim hold-down bolts. As

such, the failure of the bolts due to stress relaxation is no longer a concern and inspection of

the bolts is not required. Therefore the stress relaxation of the rim hold-down bolts does not

meet the TLAA Criterion 5 - "involve conclusions or provide the basis for conclusion related to

the capability of the core plate to perform its intended function." Additionally, neither the rim

hold-down bolts, nor the wedges meet TLAA Criterion 3 -"time-limited assumptions defined by

the current operating term." The staff finds this response acceptable because the rim holddown bolts no longer provide structural load and do not meet the definition of a TLAA as

defined in 10 CFR 54.3(a)(3) and (5). In a letter dated January 26, 2004, the applicant

submitted the information described above. Therefore, Confirmatory Item 3.1.2.3.6-1 is closed.

Cl.3.1.2.3.8-1: (Section 3.1.2.3.8 - Reactor Vessel Surveillance program)

In response to Part 2 of Supplemental RAI B.1.22, in a letter dated November 21, 2003, the

applicant stated that if staff does not approve the proposed BWRVIP-1 16, the applicant will

provide a plant-specific surveillance plan for the license renewal period in accordance with 10

CFR Part 50, Appendices G and H, prior to entering the renewed license period. This is

Commitment #22 in Appendix A of this SER. This is considered Confirmatory Item 3.1.2.3.8-1.

In response to Part 2 of Supplemental RAI B.1.22, in a letter dated November 21, 2003, the

applicant stated that if the staff does not approve the proposed BWRVIP-1 16, Exelon will

provide a plant-specific surveillance plan for the license renewal period in accordance with

10 CFR Part 50, Appendices G and H, prior to entering the renewed license period. This is part

of Commitment #22 of Appendix A of this SER. This was identified as Confirmatory Item

3.1.2.3.8-1. The staff finds the response acceptable because the applicant commits to provide a

plant-specific surveillance program for the license renewal period in accordance with 10 CFR

Part 50, Appendices G and H, if the staff does not approve the proposed BWRVIP-1 16. In a

letter dated April 9, 2004, the applicant concurred with Commitment #22. Therefore,

Confirmatory Item 3.1.2.3.8-1 is closed.

Cl.3.1.2.4.2-1: (Section 3.1.2.4.2 - Reactor Vessel Internals (Including Fuel Assemblies and

Control Blades))

The response to RAI 3.1.7b states that Dresden and Quad Cities will implement the BWRVIP

recommendations and manage the effects of aging of IASCC through AMPs B.1.2 (Water

Chemistry) and B.1.9 (BWR Vessel Internals). AMP B.1.9 is consistent with NUREG-1801

which references the use of BWRVIP-26 for the inspection of the reactor vessel internals,

including the top guide, and BWRVIP-76 for the inspection of the shroud. However, according

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to Table 2-1 of BWRVIP-76, when fldences exceed 5 x 1020 n/cm2, a plant-specific analysis is

required to be submitted to the NRC. This issue was identified as Confirmatory Item 3.1.2.4.2-1.

In response to Confirmatory Item 3.1.2.4.2-1, in a letter dated April 9, 2004, the applicant states

that Table 2-1 of BWRVIP-76 provides inspection guidance for welds in un-repaired core

shrouds. Note 4 of Table 2-1 indicates that for plants where fluence at the shroud exceeds

5x1020 n/cm2, a plant-specific analysis is required to be submitted to the NRC. However, this

analysis is only for un-repaired core shrouds. -Since the core shrouds at Dresden and Quad

Cities have been repaired and the repairs structurally replace the horizontal welds, the

plant-specific analysis suggested by Table 2-1 is not applicable to these shrouds. The

applicant further states that the inspection frequencies for the DIQCNPS shrouds are

determined using the guidance contained in Section 3 of BWRVIP-76. The applicant inspects

the vertical core shroud welds in accordance with BWRVIP-76, Section 3. The staff finds the

response consistent with BWRVIP-76. Since the applicant has committed to implement

BWRVIP-76 when the staff SER is issued, this completes our review of this issue. Therefore,

Confirmatory Item 3.1.2.4.2-1 is closed.

CI.4.2.1: (Section 4.2.2.1 - Reactor Vessel Materials Upper-Shelf Energy Reduction Due to

Neutron Embrittlement)

The data for copper content in the limiting beltline plate and limiting beltline weld material

presented in LRA Section 4.2.1 appear to be different from the data presented in Appendix F to

the Dresden UFSAR. For example, LRA Table 4.2.1-2 lists 0.24 percent copper for the

Dresden Unit 2 limiting beltline weld material, whereas Table 22 in Appendix F lists a maximum

copper content of 0.21 percent for Dresden Unit 2. In RAI 4.2.1 (b), the staff requested the

applicant to resolve this apparent discrepancy. This was identified as Confirmatory Item 4.2.1.

In response to RAI 4.2.1 (b), in a letter dated October 3, 2003, the applicant provided the

following explanation:

For the beltline region, Table 21 (Shell Course 57-Lower Shell) and Table 22 (Shell Course

58-Lower-lntermediate Shell) of the Dresden FSAR gives values actual chemical analysis of

these materials. Tables 21 and 22 contain the chemical analysis for electroslag welds contained in

the original FSAR. Since the original publication of the FSAR, the accepted best estimate

chemistry for Electroslag Weld (ESW) materials used in 8&W vessels accepted by the NRC staff

is 0.24% Cu and 0.37% Ni. These values are reported in BAW-2258, 'Evaluation of RTNOT, USE

and Chemical Composition of Core Region Electroslag Welds for Dresden Units 2 and 3,"

Framatome Technologies, January 1996, and were previously accepted by the NRC in its review

of pressure temperature (P-T) limit curve report GE-NE-B13-02057-04R1a. Exelon submitted

reactor vessel chemistry values to the NRC in July 1998 in response to Generic Letter 92-01,

Supplement 1. The information provided in that response is included in NRC database RVID.

The staff accepts the applicant's response because the staff has verified the percentage of

copper content given in LRA Tables 4.2.1-1 to 4.2.1-8 for the limiting beltline USE materials

with the corresponding data in RVID. Therefore, Confirmatory Item 4.2.1 is closed.

CI.4.2.1(a): (Section 4.2.2.1 Reactor Vessel Materials Upper-Shelf Energy Reduction Due to

Neutron Embrittlement)

The peak EPU fluence on the vessel is located at approximately 82 inches above the bottom of

active fuel and is applied to the lower-intermediate shell and axial welds. Additionally, axial flux

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distribution factors are applied to different elevations (by shell) in the beltline region. For the

lower shell, the peak fluence is adjusted by the axial flux distribution factor based on an

elevation approximately 42 inches above the bottom of active fuel, which represents the lower

to lower-intermediate girth weld. The axial flux distribution factor for this location is 0.71. The

applicant stated that it applied this factor for calculating the peak pre-EPU fluence for the lower

to lower-intermediate shell girth weld and all lower shell materials. In a followup question to RAI

4.2.1 (a), the staff requested the applicant to describe how the pre-EPU axial flux profile

compares with the EPU axial flux profile. The staff also requested that the applicant submit

information about how the axial flux distribution factor was used in calculating the peak-EPU

fluence for the lower to lower-intermediate shell girth weld and all lower shell materials. This

was identified as Confirmatory Item 4.2.1 (a).

In a letter dated April 9, 2004, the applicant referred to Figure 2 in a letter from Exelon to NRC,

"Additional Information Regarding Request for License Amendment for Pressure-Temperature

Limits," dated July 31, 2003. This figure shows the pre-EPU and EPU axial flux distribution at

the inside surface of the reactor pressure vessel. The pre-EPU and EPU axial flux distribution

profiles are different, since the pre-EPU flux peaks at an elevation higher than the mid-plane,

whereas the EPU flux peaks at the mid-plane. The applicant stated that for determining the

peak 54-EFPY surface fluences at the lower shell plate material, lower shell welds and the

lower to lower-intermediate shell girth weld, the axial flux distribution factor of 0.71 is applied for

pre-EPU and 0.74 is applied for EPU conditions. The staff has independently verified the axial

flux distribution factors using the data presented in the figure mentioned above and also verified

the peak surface fluences for the lower shell and associated welds as calculated by the

applicant. The staff finds the response acceptable because the applicant has used appropriate

axial flux distribution factors for calculating the peak 54-EFPY surface fluence for the lower to

lower-intermediate shell girth weld and all lower shell materials when determining the limiting

materials. Therefore, Confirmatory Item 4.2.1 (a) is closed.

Cl.4.2.1.6: (Section 4.2.1.6 - Reactor Vessel Circumferential Weld Examination Relief)

The applicant was required to submit an update to LRA Section 4.2.6 to include the

circumferential weld examination relief analysis for Quad Cities in accordance with 10 CFR

54.3(a) upon staff's approval of the May 16, 2003, relief request. This issue was identified as

Confirmatory Item 4.2.1.6.

In response to Confirmatory Item 4.2.1.6, in a letter dated March 5, 2004, the applicant

submitted a revision to the UFSAR Supplement for the reactor vessel circumferential weld

examination relief TLAA. The revised supplement refers to the documents related to RPV

circumferential weld relief request extension for the license renewal term. The staff reviewed

this supplement and found that it provides an adequate summary description regarding the

evaluation of this TLAA. Therefore, Confirmatory Item 4.2.1.6 is closed.

CI.4.2.2: (Section 4.2.2.7 - Reactor Vessel Axial Weld Failure Probability)

This axial weld failure probability analysis is required to be performed as a license renewal

action item in accordance with the staff FSER of EPRI report TR-1 13596 (BWRVIP-74) and

compliance with the license renewal rule (10 CFR Part 54) enclosed in an October 18, 2001,

letter from Mr. C.l. Grimes to Mr. C. Terry. This action item, as stated in the staff's March 7,

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2000, letter to Mr. C. Terry, requires the license renewal applicant to monitor axial beltline weld

embrittlement. One acceptable method is to determine that the mean RTNDT of the limiting axial

beltline weld at the end of the extended period of operation is less than the values specified in

Table 1 of this FSER. Therefore this evaluation applies to Dresden Units 2 and 3, as well as to

Quad Cities Units 1 and 2. In addition, Dresden and Quad Cities have the same mean RTNOT,

because the initial RTNDT, chemical composition, and 54-EFPY surface fluence are the same for

the limiting beltline axial welds at Quad Cities and Dresden. Therefore, for Quad Cities and

Dresden plants, the mean RTNDT for the limiting beltline axial welds at 54-EFPYs is equal to 19

; C (67 OF). A comparison of the mean RTNDTvalue of 33 0C (91 OF) for the Clinton axial weld

from Table 4.2-1 of this SER with the Dresden and Quad Cities value of 19 0C (67 OF) shows

that the NRC analysis of the Clinton axial welds bounds the Dresden and Quad Cities welds.

The applicant should confirm that Quad Cities Units 1 and 2 have a mean value of 19 0C

(67 0F) and address this TLAA of the axial welds for Quad Cities in the UFSAR Supplement.

This was identified as Confirmatory Item 4.2.2.

In response to Confirmatory Item 4.2.2, in a letter dated March 25, 2004, the applicant

compared the limiting axial weld 54-EFPY properties for Quad Cities 1 and 2 against the

corresponding limiting values calculated by the NRC in the SER for BWRVIP-05 at 64 EFPY

and the limiting Clinton values taken from Table 2.6-5 in the March 7, 2000, supplement to the

SER. The applicant confirmed that the limiting axial welds at Quad Cities Units 1 and 2 have a

mean 54 EFPY RTNDT of 191C (671F), which is less than the value of 330C (91OF) for Clinton.

The comparison also shows that the conditional vessel failure probabilities for Quad Cities Units

1 and 2 are equal to 2.08 x 10' 7and 5.27 x 1 07, respectively. These failure probabilities are

less than the corresponding value for Clinton listed in Table 4.2-1 of this SER. The staff finds

the applicant's evaluation for this TLAA acceptable because the conditional probability of failure

of Quad Cities Unit 1 and 2 limiting axial welds at 54 EFPY is smaller than the corresponding

values calculated by the NRC staff in the SER for BWRVIP-05 at 64 EFPY and the limiting

Clinton values found in the March 7, 2000, supplement to the SER.

In a letter dated March 5, 2004, the applicant submitted a revision to the UFSAR supplement for

the reactor vessel axial weld failure probability. The staff reviewed this supplement and found

that it provides an adequate summary description regarding the evaluation of this TLAA.

Therefore, Confirmatory Item 4.2.2 is closed.

CI.B.1.2-1: (Section 3.0.3.2 -Water Chemistry Program (B.1.2))

The staff noted that due to a potential difference in the concentration of sodium pentaborate in

the system (the tank and suction piping are typically at a much higher concentration from the

remainder of the system), that the proposed chemistry inspections may not provide information

on the condition of the tank and pump suction piping. The staff requested in RAI B 1.2 -1 that

the applicant provide supplemental information regarding how aging degradation of the SBLC

tank and suction piping will be managed, since sampling chemistry downstream of the tank and

receipt inspection of the chemicals used in the tank will not provide adequate assurance that

degradation is not occurring in this section of the system. This issue was identified as

Confirmatory Item B.1.2-1.

The applicant responded in letters dated December 22, 2003 and March 25, 2004, that it will

perform an ultrasonic examination of portions of the SBLC tank. This is part of Commitment

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#23 of Appendix A of this SER. The ultrasonic examinations will be used to identify potential

loss of material and stress corrosion cracking. The applicant will perform one ultrasonic

inspection in each quadrant, near the bottom of the tank. The applicant considers this location

to be the most susceptible location for degradation. The UT examinations will include a portion

of the tank shell and vertical seam weld and, if accessible, a portion of a circumferential weld in

accordance with the applicant's NDE procedures. If necessary, the exam results will be

addressed by the applicant's corrective action program.

The staff finds that the applicant will adequately manage aging in the SBLC system through the

combined use of inspection of the pump casing, ultrasonic inspection of the SBLC tank, and

control of addition chemicals according to the applicant's receipt inspection program. Therefore,

Confirmatory Item B.1.2-1 is closed.

CI.B.1.17: (Section 3.3.2.3.2 - BWR Reactor Water Cleanup System (B.1.17))

Since the applicant stated that the entire RWCU system piping was replaced with IGSCCresistant piping in accordance with NRC GL 89-10, the staff subsequently requested the

applicant to provide the following information to be verified by the NRC Audit-Inspection Team:

(i) Clarify whether the entire RWCU system piping was replaced with IGSCC-resistant material

or whether only portions of the RWCU system piping for each plant were replaced.

(ii) Confirm that, if the entire RWCU system piping was replaced, the piping system includes all

the RWCU welds inboard and outboard of the second isolation valves. Confirm whether the

selection of material of the replaced piping and weld metal meet the material compositions as

described in GALL AMP XI.M25.

(iii) Verify that, if only portions of the RWCU system piping were replaced, the entire RWCU

system piping meets the screening criteria, 1 (a), (b), and (c) in GALL AMP XL.M25 program

element 1, Scope of the Program, as well as the material specifications in GALL AMP XL.M25

program element 2, Preventive Actions.

This was identified as Confirmatory Item B.1.17.

During the audit, the team confirmed the following technical information relating to this AMP

with the applicant at the request of the NRC's technical staff:

* All in-scope portions of the RWCU system piping outboard of the second isolation

valves were replaced with ASTM SA312 or SA376 Gr. TP316L with a carbon content of

less than 0.035%. RWCU piping inboard of the second isolation valve have not been

replaced with IGSCC resistant piping.

* The RWCU piping that is inboard of the second isolation valve is Class 1 and 2 piping

that is managed by the ISI Program (B.1.1), ASME Section Xl, Subsections IWB, IWC,

and IWD. All of the RWCU piping and welds on the in-scope portion outboard of the

second isolation valves were replaced. The replacement piping and weld metal meets

the material compositions as described in NUREG-1801, AMP XL.M25.

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* All the RWCU piping and welds on the in-scope portion outboard of the second isolation

valves were replaced with piping and weld material that meet the material compositions

as described in NUREG-1 801, AMP XI.M25. Screening criteria 1 (a), (b), and (c) of

NUREG-1 801, AMP XL.M25 do not apply to this piping.

* In a letter to the NRC, dated August 20, 1993, the licensee committed to replace all

RWCU IGSCC susceptible outboard supply and return line piping and the regenerative

heat exchangers with IGSCC resistant materials at both Dresden and Quad Cities.

License Renewal Boundary Drawings LR-DRE-M-30 and LR-QDC-M-47-1 show the piping

design table for the in-scope portion of the RWCU piping outboard of the second isolation

valves to be table AQ. Dresden specification K-4080 and Quad Cities specification R-441 1

provide the material specification for piping design table AQ. Design table AQ provides the

information on the piping material: all in-scope portions of the RWCU system piping outboard of

the second isolation valves were replaced with ASTM SA312 or SA376 Gr. TP316L with a

carbon content of less than 0.035%.

Based on the above information, the applicant confirmed that the ten elements of the GALL

program, "BWR Reactor Water Cleanup System," as specified in NUREG-1801, AMP XL.M25

(with the exception of the Water Chemistry Program as noted in the LRA) are applicable to

Dresden and Quad Cities, and that the applicant's program B.1.17 is consistent with GALL AMP

XI.M25, with the exception as noted in the LRA.

On the basis of its review of this AMP, GALL AMP XI.M25, AMR topical report M.05, and the ISI

Program plan, the audit team determined that this AMP is consistent with GALL AMP XL.M25,

with the exception as noted in the LRA. Therefore, Confirmatory Item B.1.17 is closed.

CI.B.1.23-1: (Section 3.0.3.10 - One Time Inspection (B.1.23))

See response for Open Item B.1.23-2.

CI.B.1.23-2.5: (Section 3.3.2.3.7 Periodic Inspection of Plant Heating System (B.2.8))

The applicant concluded that the Periodic Inspection of Plant Heating System program provides

assurance that plant heating system components are routinely inspected for deterioration and

leakage, and will adequately manage the components aging effects. The applicant stated that

the program provides reasonable assurance that intended functions are maintained consistent

with the current licensing basis during the period of extended operation. The staff compared

the program against BTP RLSB-1. This issue was identified as Confirmatory Item B.1.23-2.5.

By letter dated March 25, 2004, the applicant described its program to manage loss of material,

cracking, and leakage in selected plant heating system components for Dresden and Quad

Cities exposed to an environment of saturated steam and condensate. The staff reviewed this

program using the guidance in Branch Technical Position RLSB-1 in Appendix A of the SRP-LR

and focused on how the program manages aging effects through the effective incorporation of

the following 10 elements: program scope, preventive actions, parameters monitored or

inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective

; actions, confirmation process, administrative controls, and operating experience. The applicant

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-

indicated that the corrective actions, confirmation process, and administrative controls are part

of the site-controlled Quality Assurance Program. The staff's evaluation of the Quality

Assurance Program is provided separately in Section 3.0.4 of this SER. The remaining seven

elements are discussed below. The staff also reviewed the UFSAR supplements for Dresden

and Quad Cities to determine whether they provide an adequate description of the program.

[Program Scope] The program will manage age related degradation of plant heating system

components such as filter/strainer housings, piping and fittings, pump casings, sight glasses,

tanks, thermowells, traps, tubing, and valves. The staff finds that the scope is acceptable

because it includes those components that rely on the program for aging management.

[Preventive or Mitigative Actions] The plant heating system periodic inspections do not provide

any preventative actions. The inspections provide for condition monitoring to detect

degradation prior to a loss of function. Preventative or mitigative actions are not needed for this

condition monitoring program; therefore, the staff finds this acceptable.

[Parameters Monitored or Inspected] Visual inspections will be performed on a representative

sample of brass or bronze valves, carbon steel piping and fittings, cast iron filter housings,

pump casings and valves, and stainless steel thermowells and tubing used in the plant heating

systems to determine if aging degradation is occurring. The components are inspected to

ensure they are free of cracking, loss of material, and leakage. The inspection will consist of a

visual inspection on the internal surface of components for the presence of general, crevice,

galvanic, and pitting corrosion. The staff concludes that the applicant is inspecting the

appropriate parameters to identify the aging effects; therefore, the staff finds this acceptable.

[Detection of Aging Effects] The plant heating inspections are performed a periodic intervals,

and they detect aging prior to the equipment leaking so as to prevent spatial interaction with

safety-related equipment. Inspections will be performed in accordance with ASME Code

requirements and certified NDE examiners will conduct a VT-3 visual examination. The staff

finds this acceptable because the inspections will identify the aging effects managed by this

program.

[Monitoring and Trending] The condition of the components used in plant heating systems are

monitored at intervals of approximately every 5 years, but not trended. Components are

replaced if damage or unacceptable leakage is detected. Operating experience states that

leaks were identified and corrected in a timely manner and did not result in a loss of function of

any safety-related component. Staff finds that monitoring of these components periodically

every 5 years is adequate to identify aging degradation; therefore staff finds this acceptable .

[Acceptance Criteria] The applicant stated that components are inspected for cracking, loss of

material, and leakage. The components are replaced if a degraded condition is found.

Inspections will be performed in accordance with ASME Code requirements and corrective

actions state that evaluations are performed for inspection results that do not satisfy

established criteria. The staff finds that the applicant's proposal to perform inspections in

accordance with ASME Code requirements and use of engineering evaluations of degradation

components will provide acceptance criteria against which the need for corrective actions will be

evaluated; therefore, staff finds this acceptable.

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[Operating Experience] The applicant stated that Dresden and Quad Cities have experienced

leaks in the plant heating systems, but that these leaks were identified and corrected in a timely

manner and did not result in a loss of function of any safety-related system, structures, or

components. The staff notes that the plant heating system is in scope of license renewal due to

the potential for spatial interactions. The staff finds that the operating experience of timely

correction of system leaks plus the additional periodic visual inspections supports the

applicant's conclusion that the program will be effective in managing aging of the components

in the scope of this program; therefore, the staff finds this acceptable. Therefore Confirmatory

Item B.1.23-2.5 is closed.

CI.B.1.25-1: (Section 3.0.3.12 - Buried Piping and Tanks Inspection)

The staff had additional concerns regarding concrete asbestos piping and buried carbon steel

piping and requested clarifying information. Specifically, with regard to concrete asbestos

piping, the applicant's operating history indicated that failures of the piping have occurred. On

the basis of this experience, the staff requested justification for why a one-time inspection was

not warranted, as well as confirmation that the soil environment for the piping was not

aggressive. With regard to buried carbon steel piping, the applicant indicated that much of the

piping may not be coated. Given that some of the piping may not be coated, the staff

questioned why this was not identified as an exception to the GALL program. This was

identified as Confirmatory Item B.1.25-1.

The applicant responded to the staff's request for supplemental information in letters dated

December 12, 2003 and March 25, 2004. The applicant indicated that the buried concrete

piping likely failed as a result of ground shifting or heavy loads transported in the vicinity of the

piping. This piping is located in a soil and ground water environment which is not aggressive to

concrete based on pH values between 7 to 9, chlorides 5 to 30 ppm, and sulfates 10 to 30 ppm.

These values are within the NUREG 1801 criteria (chlorides less than 500 ppm, sulfates less

than 1500 ppm and pH greater than 5.5). The applicant indicated that buried carbon steel and

ductile iron piping in the Fire Suppression System are externally coated with coal tar wrapping;

however, there was some question regarding use of coating on other carbon steel buried

piping. The applicant provided supplemental information after a detailed review of plant

documents that indicates that all carbon steel buried piping at Dresden and Quad Cities was

externally coated. The applicant further indicated that the installation specification required an

inspection of the coating integrity prior to burial.-The applicant provided operating experience

from a recent plant modification that required excavation of some Fire Suppression System

piping at Quad Cities. A section of 10 inch schedule 40 carbon steel piping was recently

excavated. The applicant indicated that the piping was coated with coal tar wrapping and had

been buried in the early 1970's. The nominal wall thickness of this piping is 0.365 inches. The

measured minimum and maximum wall thicknesses were 0.320 inches and 0.400 inches

respectively. The applicant concluded that there was little effect of aging on this piping after

burial for approximately 30 years. The applicant also surveyed the craft personnel who

performed the work to assess the condition of the external pipe coating. The applicant

provided qualitative information that the coating was 'generally in good condition" based on the

craft personnel. The staff finds the applicant's response acceptable because the applicant

provided information regarding the cause of the concrete piping degradation, provided

information consistent with NUREG 1801 that indicates the environment is not aggressive to

concrete, that there is reasonable assurance that the buried piping is coated and provided

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additional operating experience that indicates there is limited aging degradation of buried

piping. Therefore, Confirmatory Item B.1.25-1 is closed.

CI.B.2.5-1: (Section 3.0.3.16 Lube Oil Monitoring Activities)

In its October 3, 2003, response to RAI B.1.23-2(a), the applicant committed to include the

following additional components in the scope of this program: components in the reactor core

isolation cooling (RCIC) system, additional components in the high pressure coolant injection

(HPCI) system, additional components in the emergency diesel generator and auxiliaries

system, and additional components in the station blackout diesel system. In addition, the

applicant committed to add components exposed to EHC oil (main turbine and auxiliary

systems) and generator hydrogen seal oil (turbine oil system - Quad Cities only) to the scope of

this program. The staff found that adding the above components to the scope of this program

is appropriate, since maintaining oil quality is important for preventing aging effects. However,

the applicant did not provided updates to the program elements to address the increased scope

of the program. The applicant was requested to provide the appropriate revisions to the 10

elements and the UFSAR summary description of this program. This issue was identified as

Confirmatory Item B.2.5-1.

In its draft supplemental response dated December 18, 2003, the applicant further committed to

add components exposed to EHC oil (main turbine and auxiliary systems) and generator

hydrogen seal oil (turbine oil system) to the scope of this program. The applicant added these

components to the scope of the program by letter dated January 26, 2004. The staff found that

adding the above components to the scope of this program is appropriate, since maintaining oil

quality is important for preventing aging effects in these components.

In a letter dated June 22, 2004, the applicant committed to include the following additional

component in the scope of this program: components in the reactor recirculation motor

generation oil system. The staff found that adding the above component to the scope of this

program is appropriate, since maintaining oil quality is important for preventing aging effects in

these components.

[Program Scope] The applicant stated that this AMP is applicable to heat exchanger and other

components exposed to a lubricating oil environment in the HPCI, emergency diesel generator

and auxilaries, (SBO) diesel and auxlilaries, reactor core isolation cooling (RCIC), generator

hydrogen seal oil (HSO), main turbine and auxiliaries (electro-hydraulic control (EHC) oil

subsystem), and reactor recirculation motor generator systems. The staff finds that the scope is

acceptable because it includes those components that rely on the program for aging

management.

[Preventive or Mitigative Actions] The applicant's program monitors and controls the oil

properties and impurity levels. When the parameters exceed predefined limits, actions are

taken to restore the conditions. The staff finds that maintaining the oil parameters mitigates

loss of material and cracking in lubricating oil systems; therefore, the staff finds this acceptable.

[Parameters Monitored or Inspected] The applicant stated that the parameters monitored by

the program include viscosity, total acid number, total base number, rotary bomb oxidation test,

water demulsability, particle count, fuel and combustion byproducts, sediment, water, anti1-28
foaming characteristics, whole particle counting, air release and emission spectrum. The

applicant also stated that the parameters monitored by the program depends on oil type and

; type of service. The staff notes that loss of material due to general, crevice, and pitting

corrosion and cracking are applicable aging effects for lubricating oil cooler components in a

lubricating oil environment at locations containing water or contaminants such as chloride ions.

By RAI B.2.5(a), the staff asked the applicant to clarify whether water, moisture, and chloride

ions are monitored for all type of oil and service. If not, the staff requested the applicant to

provide justification for not including these parameters in monitoring. In its response dated

October 3, 2003, the applicant stated that water/moisture is monitored as part of the Lubricating

Oil Monitoring Activities program. No monitoring for chloride ions is provided in this program.

The applicant explained that EPRI 1003056, Non-Class 1 Mechanical Implementation Guideline

and Mechanical Tools, Revision 3, Appendices C and G were reviewed in the development of

the Lubricating Oil Monitoring Activities program. These appendices address oil environments

in general and lubricating oil environments for heat exchangers, respectively. Appendix C

identifies damaging effects associated with chlorides in fuel oil environments, but no similar

effects are identified for lubricating oil environments. Appendix G does not identify any

applicable aging effects associated with chlorides for lubricating oil environments in heat

exchanger components. The applicant also stated that there is no site operating experience of

failure or degradation in oil environments attributed to the presence of chlorides. Therefore, the

applicant concluded that monitoring for chloride ions is not required for the Lubricating Oil

Monitoring Activities program. Based on the applicant's operating experience, the staff finds

that the applicant's response satisfactorily addresses the staff's concerns and RAI B.2.5(a) is

considered closed. The staff concludes that the applicant is monitoring the appropriate oil

parameters; therefore, the staff finds this acceptable.

[Detection of Aging Effects] The applicant stated that samples of lubricating oil are taken

monthly for EDGS, EHC oil, reactor recirculation motor generator oil, and HSO systems,

quarterly for HPCI, SBO diesel generators, semi-annually for the RCIC pump, and every 24

months for the RCIC turbine. Sampling frequency is increased if plant and equipment operating

conditions indicate a need to do so. The applicant stated that the sampling would reveal aging

degradation because increased impurities and degradation of oil properties indicate

degradation of material in lubricating oil systems. The staff finds this acceptable because

sampling and analyses are performed periodically, and the analysis is capable of detecting

aging degradation.

The staff also notes that the aging effects of the heat exchangers are also managed by the

'Closed-Cycle Cooling Water System" and/or aHeat Exchanger Test and Inspection Activities,"

AMPs B.1.1 4 and B.2.6, respectively. For other components, the applicant uses the One-Time

Inspection Program (B.1.23) to verify the effectiveness of the Lube Oil Monitoring Activities

AMP. The inspections and performance testing under these programs provides additional

assurance that loss of material and cracking will be detected before the loss of intended

function; therefore, the staff finds this acceptable.

* [Monitoring and Trending] The Lube Oil Monitoring program monitors the relevant parameters

via samples taken monthly for EDGs, quarterly for HPCI, SBO diesel generators, EHC oil, and

HSO systems, semi-annually for the RCIC pump, and every 24 months for the RCIC turbine.

The oil analysis results are trended and evaluated using computer software and a database.

The applicant stated that the lubricating oil analysis results are trended and evaluated using

computer software and a database. The staff finds that monitoring through sample analysis is

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appropriate and that the frequency is consistent with industry experience; therefore, the staff

finds the monitoring and trending to be acceptable.

[Acceptance Criteria] The applicant stated that normal, alert, and fault levels have been

established for the various chemical and physical properties, wear metals, additives, and

contaminant levels based on information from oil manufacturers, equipment manufacturers, and

industry guidelines, for the specific oil type and application. The applicant also stated that the

program maintains contaminant and parameter limits within the application-specific limits. By

RAI B.2.5(b), the staff asked the applicant to explain the acceptance criteria of water, moisture,

and contaminants. In its response dated October 3, 2003, the applicant provided the acceptable

limits for water/moisture and contaminants at normal, alert, and fault levels for emergency

diesel generator and SBO diesel components with MOBILGARD 450 NC oil and for HPCI

turbine components with MOBIL VAPROTEC LIGHT oil. The applicant stated the acceptable

limits are based on EPRI 1003056, "Non-Class 1 Mechanical Implementation Guideline and

Mechanical Tools," Revision 3, and that any failures to meet these criteria result in a condition

evaluation, an identification of root causes, and correction of the adverse condition. The staff

finds that the acceptance criteria are consistent with industry guidelines and that the applicant's

activities in case of failure to meet these acceptance criteria are reasonable; therefore, the staff

finds the acceptance criteria acceptable.

[Operating Experience] The applicant stated that oil sampling and analysis have detected

particulate or water contamination (or both) in lubricating oil systems. The operating experience

has produced procedure and program changes, which have improved the effectiveness of

lubricating oil testing and inspection activities. By RAI B.2.5(c), the staff asked the applicant to

describe the corrective actions made and the operating experience since these corrective

actions were implemented. In its response dated October 3, 2003, the applicant provided four

examples of corrective actions made as a result of operating experience involving lube oil

sampling and analysis. In one of the examples, the applicant stated that the 10/28/99 oil

analysis of the Unit 1A (1 B) SBO diesel engine crankcases indicated high percentage volume

for sediment of 0.3 % (upper limit of 0.05% volume). All physical parameters other than

sediment were found to be suitable for use. A recommendation was made to continue

sampling/trending oil sample results on a quarterly frequency. The sampling procedure was

revised to include requirements to perform sampling on a quarterly basis, and trend results. In

another example, the applicant stated that a number of Quad Cities oil analysis results for

RHRSW pump bearings showed high metal levels. It was determined that the high/increased

wear level concentrations could have been indications of pump shaft, housing, rolling element

bearing or bearing cage clearance wear. It was determined that the pump bearing oil analysis

required large amounts of oil to be collected because smaller sample amounts had a tendency

to show high/erratic wear levels. The sampling procedure was revised to include requirements

to draw a relatively large sample. The applicant stated that no operating experience involving

recurrence of heat exchanger degradations since implementation of the associated corrective

actions. The staff finds that the applicant's response satisfactorily addresses the staff's

concerns and RAI B.2.5(c) is considered closed. The staff finds that the applicant's operating

experience supports the conclusion that the program will be effective in preventing aging of the

components in the scope of this program; therefore, the staff finds this acceptable. Therefore

Confirmatory Item B.2.5-1 is closed.

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1.7 Summary of Proposed License Conditions

; As a result of the staff's review of the DNPS/QCNPS application for license renewal, including

the additional information and clarifications submitted subsequently, the staff identified three

proposed license conditions. The first license condition requires the applicant to include the

UFSAR Supplement in the next UFSAR update required by 10 CFR 50.71(e) following issuance

of the renewed license. The second license condition requires that the future activities

identified in the UFSAR Supplement and Appendix A of this SER to be completed prior to the

period of extended operation. The third license condition requires the implementation of the

most recent staff-approved version of the Boiling Water Reactor Vessels and Internals Project

i (BWRVIP) Integrated Surveillance Program (ISP) as the method to demonstrate compliance

with the requirements of 10 CFR Part 50, Appendix H. Any changes to the BWRVIP ISP

capsule withdrawal schedule must be submitted for NRC staff review and approval. Any

changes to the BWRVIP ISP capsule withdrawal schedule which affects the time of withdrawal

of any surveillance capsules must be incorporated into the licensing basis. If any surveillance

capsules are removed without the intent to test them, these capsules must be stored in manner

which maintains them in a condition which would support re-insertion into the RPV, if

necessary.

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2. SCOPING AND SCREENING METHODOLOGY FOR IDENTIFYING

STRUCTURES AND COMPONENTS SUBJECT TO AGING

MANAGEMENT REVIEW, AND IMPLEMENTATION RESULTS

2.1 Scopinq and Screening Methodoloy2.1.1 Introduction

Title 10, Section 54.21, of the Code of Federal Regulations (10 CFR 54.21), "Contents of

Application-Technical Information," requires that each application for license renewal (LR)

contain an integrated plant assessment (IPA). The IPA must list and identify those structures,

systems and components (SSCs) that are within the scope of license renewal in accordance

with 10 CFR 54.4 and subject to an aging management review (AMR).

In Section 2.1, "Scoping and Screening Methodology," of the license renewal application (LRA)

the applicant described the scoping and screening methodology used to identify the SSCs at

the Dresden and Quad Cities Nuclear Power Stations that are within the scope of license

renewal and subject to an AMR. The staff reviewed the applicant's scopinig and screening

methodology to determine if it meets the scoping requirements stated in 10 CFR 54.4(a) and

the AMR screening requirements stated in 10 CFR 54.21.

In developing the scoping and screening methodology for the Dresden and Quad Cities Nuclear

Power Stations LRA, the applicant considered the requirements of 10 CFR Part 54, the

statements of consideration related to the license renewal rule (the Rule), and the guidance

provided in the Nuclear Energy Institute (NEI) report NEI 95-10, Industry Guideline for

Implementing the Requirements of 10 CFR Part 54-The License Renewal Rule." In addition,

the applicant also considered the U.S. Nuclear Regulatory Commission (NRC) staff's license

renewal interim staff guidance (ISG) documents and related correspondence.

2.1.2 Summary of Technical Information in the Application

In Sections 2.0 and 3.0 of the LRA, the applicant provided the technical information required by

10 CFR 54.21 (a). In LRA Section 2.1, "Scoping and Screening Methodology," the applicant

described the process used to identify the SSCs that meet the license renewal scoping criteria

under 10 CFR 54.4(a), as well as the process used to identify the SSCs that are subject to an

AMR as required by 10 CFR 54.21 (a)(1). Additionally, LRA Section 2.2 ("Plant-Level Sc6ping

Results"), Section 2.3 ("Scoping and Screening Results: Mechanical Systems"), Section 2.4

("Scoping and Screening Results: Structures"), and Section 2.5 ("Scoping and Screening

Results: Electrical and Instrumentation and Control Systems") provided the results of the

process used to identify the structures and components (SCs) that are subject to an AMR.

2.1.2.1 Scoping Methodology

In Section 2.1 of the LRA, the applicant described the methodology used to scope mechanical,

structural, and electrical and instrumentation and controls (I&C) SSCs pursuant to the

requirements of the 10 CFR 54.4(a) scoping criteria. The applicant's scoping methodology, as

! described in the LRA, is presented in the sections below.

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

The applicant described the general approach to scoping safety-related, non-safety-related

(NSR), and SSCs credited with demonstrating compliance with certain regulated events in

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

approaches specific to each of the three 10 CFR 54.4(a) scoping criteria are described in the

following sections.

Application of the Scopinq Criteria in 10 CFR 54.4(a)(1). In LRA Sections 2.1.2.1, "Title

10 CFR 54.4(a)(1)-Safety-Related," and 2.1.4, "Scoping Methodology" the applicant discussed

the methodology used to identify SSCs meeting the 10 CFR 54.4(a)(1) safety-related license

renewal scoping criteria. The applicant stated that at the Dresden and Quad Cities Nuclear

Power Stations, safety-related classifications for components are documented on engineering

drawings and in a controlled plant component database. The applicant relied upon the safetyrelated classification as reported in these source documents to identify SSCs satisfying scoping

criteria of 10 CFR 54.4(a)(1).

Application of the Scoping Criteria in 10 CFR 54.4(a)(2). In LRA Sections 2.1.2.2 "Title

10 CFR 54.4(a)(2)-Non-Safety-Related Affecting Safety-Related", 2.1.4 "Scoping

Methodology", and 2.1.6 "Additional Considerations Incorporated Into the Methodology", the

applicant discussed the methodology used to identify SSCs meeting the 10 CFR 54.4(a)(2)

non-safety-related license renewal scoping criteria. The applicant performed 10 CFR 54.4(a)(2)

scoping evaluations using a two-stage process that consisted of an initial scoping evaluation

followed by a revised scoping evaluation. During the initial 10 CFR 54.4(a)(2) non-safetyrelated scoping evaluation, the applicant identified non-safety-related SSCs that explicitly

supported a safety-related function. The revised non-safety-related scoping methodology

considered the potential adverse effects from the failure of non-safety-related SSCs attached to

safety-related equipment and spatial interactions resulting from the failure of non-safety-related

SSCs on the performance of a safety-related function. The applicant described both the initial

and revised 10 CFR 54.4(a)(2) scoping methodology in Section 2.1.2.2 of the LRA.

Initial Non-safety-Related Scoping

In Section 2.1.2.2 of the LRA, the applicant stated that for every non-safety-related plant

system or structure, applicable sections of the Dresden and Quad Cities Updated Final Safety

Analysis Reports (UFSARs) and other current licensing basis (CLB) documents were reviewed

to determine whether the system or structure was credited with supporting satisfactory

accomplishment of a safety-related function. Based on this review, the applicant classified nonsafety-related systems or structures explicitly credited in CLB documents with supporting

accomplishment of a safety-related function as satisfying criterion 10 CFR 54.4(a)(2). Because

the Maintenance Rule (10 CFR 50.65) includes SSCs scoping criteria similar to

10 CFR 54.4(a)(2), the applicant stated that the Dresden and Quad Cities Maintenance Rule

functional evaluation reports were also reviewed to identify any additional non-safety-related

system or structure functions that supported satisfactory accomplishment of a safety-related

function. Non-safety-related SSCs functions that were identified in the Maintenance Rule

functional evaluation reports as supporting a safety-related function and confirmed to be part of

the CLB were classified as satisfying the 10 CFR 54.4(a)(2) scoping criterion.

Revised Non-safety-Related Scoping

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Following issuance of NRC guidance on the identification and treatment of SSCs which meet

10 CFR 54.4(a)(2) in a March 15, 2002, letter from Mr. C. Grimes to Mr. A. Nelson, the

applicant revised the non-safety-related scoping methodology. The applicant's revised

methodology included non-safety-related SSCs connected to safety-related SSCs within the

scope of license renewal up to the first equivalent anchor past the safety/non-safety interface.

In addition, non-safety-related SSCs that had a spatial relationship such that their failure could

adversely impact the performance of a safety-related SSCs intended function were included in

the scope of license renewal. The applicant stated that it considered the pipe whip, jet

impingement, general flooding, spray, and displacement/falling as spatial interactions during the

revised 10 CFR 54.4(a)(2) scoping process. However, the applicant did not consider pipe whip,

jet impingement, general flooding, or spray of a gas to be credible spatial interactions for gas

systems to adversely affect safety-related SSCs. As such, those systems containing gas were

excluded from the scope of the spatial interaction review and plant walkdowns. Displacement

and falling were considered credible interactions for gas systems, and, thus, all supports for gas

systems were included in the scope of license renewal.

Application of the Scoping Criteria in 10 CFR 54.4(a)(3). In LRA Sections 2.1.2.3, "Title

10 CFR 54.4(a)(3)-The Five Regulated Events," 2.1.3.5, 'Technical Position Papers," 2.1.4,

"Scoping Methodology," and 2.1.6, "Additional Considerations Incorporated Into the

Methodology," the applicant discussed the methodology used to identify SSCs credited for

performing a function that demonstrates compliance with regulations for fire protection (FP),

environmental qualification, pressurized thermal shock, anticipated transients without scram,

and station blackout (SBO) pursuant to the 10 CFR 54.4(a)(3) license renewal scoping criteria.

In Section 2.1.2.3 of the LRA, the applicant stated that, because the Dresden and Quad Cities

Nuclear Power Stations are boiling water reactors (BWRs), 10 CFR 50.61, the regulation for

pressurized thermal shock, was not applicable to the LRA. For each of the other four applicable

regulated events, the applicant utilized technical position papers to provide input to the scoping

process. The technical position papers identified (1) the systems and structures that are relied

upon to demonstrate-compliance with these regulations, (2) functional requirements for each

system or structure, and (3) additional documentation that may be used for scoping of

components credited to demonstrate compliance with each of the applicable regulated events.

The applicant stated that guidance provided by the technical position papers was used to

determine components credited in the regulated events. The SSCs credited in the regulated

events have been classified as satisfying criterion 10 CFR 54.4(a)(3) and have been identified

as within the scope of license renewal.

2.1.2.1.2 Documentation Sources Used for Scoping and Screening

In LRA Section 2.1.3, "Documentation Sources Used for Scoping and Screening," the applicant

stated that information derived from the following sources was reviewed during the license

renewal scoping and screening process:

* Updated Final Safety Analysis Reports

* Maintenance Rule Databases

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a current licensing basis and design basis documents, including safety evaluation reports,

technical specifications, licensing correspondence, and engineering evaluations and

calculations

* system and structure operational description documents

* technical position papers prepared to support scoping evaluations of the regulated events

identified in 10 CFR 54.4(a)(3)

* controlled plant component databases, such as the electronic work control system

(EWCS) which contains integrated design and maintenance record management

information at the level of detail at which distinct maintenance or modification activities

typically are performed

* systems and structures lists created from system lists contained in the plant controlled

database and the Maintenance Rule databases

* the license renewal database developed as a project tool to support various license

renewal activities

The applicant stated that this information was used to identify the functions performed by plant

systems and structures. These functions were then compared to the scoping criteria in

10 CFR 54.4(a)(1-3) to determine if the associated plant system or structure performed a

license renewal intended function. These sources were also used to develop the list of

structures and components subject to an AMR.

2.1.2.1.3 System, Structure, and Component Level Scoping

In LRA Section 2.1.4, "Scoping Methodology," the applicant described the scoping methodology

for systems and structures that were safety-related, non-safety-related, or relied upon to

perform a function to demonstrate compliance with the regulated events described in

10 CFR 54.4(a)(3). The applicant described the approaches used to scope mechanical

systems, electrical and l&C systems, and structures in accordance with 10 CFR 54.4(a). The

scoping methodology for each of these component classifications is described in the sections

below.

Mechanical System and Component Scoping Methodology. In LRA Section 2.1.4.1,

'Mechanical System Scoping Methodology," the applicant described the methodology for

performing license renewal scoping of mechanical systems. The applicant identified six major

activities associated with mechanical system scoping. These include identification of the

system purpose and functions, determination of the system evaluation boundary, comparison of

system functions against 10 CFR 54.4 (a)(1-3), identification of supporting systems, creation of

license renewal boundary diagrams, and component-level scoping. Each of these activities is

described below.

* identification of the system purpose and functions

The applicant stated that a description was prepared for each mechanical system that

identified all functions (intended and nonintended) that the system was designed to

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perform. The applicant used information obtained from the UFSAR system descriptions,

Maintenance Rule database records, CLB documents, design-basis documents, piping

and instrumentation diagrams (P&IDs), and system operating descriptions to develop the

system description.

* determination of the system evaluation boundary

The applicant identified a system evaluation boundary for each system, which included all

of the components needed for the system to'perform all of its'functions, including those

functions determined not to be license renewal (LR) intended functions.

* comparison of system functions against 10 CFR 54.4(a)(1-3)

All identified system functions were compared against the criteria of 10 CFR 54.4(a)(1),

(a)(2), and (a)(3). Each of the system functions satisfying scoping criteria in

10 CFR 54.4(a) was identified as a system intended function. The applicant's

methodology permitted a system function to be classified as an intended function under

more than one of the three scoping criteria in 10 CFR 54.4(a). Those systems for which

no functions were identified as satisfying any of the three scoping criteria were classified

as systems outside the scope of the Rule. -When a system was determined to be outside

the scope of the Rule, all of the components for that system listed in the LR database

were identified as outside the scope of the Rule and were excluded from further scoping

or screening evaluations. However, the applicant stated that it reviewed all components

before they were excluded from further consideration to ensure that it did not

inappropriately remove any safety-related or environmentally qualified components from

the scope of license renewal.

* identification of supporting systems

After a mechanical system was determined to be within the scope of the Rule, the

applicant stated that an evaluation was performed to identify all of the in-scope system's

supporting systems. Each of the supporting systems was then reviewed to determine if its

failure could prevent satisfactory accomplishment of any intended function of the in-scope

system. When the applicant identified that a supporting system was needed to maintain

an intended function of the in-scope system, the supporting system was determined to be

in scope.

* creation of license renewal boundary diagrams

The applicant annotated plant P&lDs to create a license renewal boundary diagram for

each mechanical system within the scope of license renewal. License renewal boundary

diagrams included (1) the system evaluation boundary, (2) the in-scope components

required to ensure success of the system intended functions, and (3) the out-of-scope

components which are not required to ensure success of the system-level intended

functions.

* component-level scoping

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Following scoping of mechanical systems and the determination of system evaluation

boundaries, the applicant performed component-level scoping. A system component list

was developed in the license renewal database to support the mechanical component

scoping methodology. The applicant reviewed the system functions, drawings, and other

information sources to determine if failure of a system component would result in failure of

a system intended function. A component was determined to be in scope if it was safetyrelated and met the criteria of 10 CFR 54.4(a)(1), if it was determined that the component

was needed to fulfill a system intended function, if the component met the criteria of

10 CFR 54.4(a)(2), or if the component was needed to support the intended function of

the system needed to meet the regulation for regulated events. The applicant stated that

every safety-related component was included within the scope of the Rule. All other

components in the LR database for a given system were reviewed to determine if they

supported any of the intended functions for a given system.

The applicant stated that all electrical and l&C components within the evaluation boundary

of in-scope mechanical systems were included within the scope of the Rule and evaluated

using the spaces approach described in Section 2.1.4.2 of the LRA. The electrical and

l&C components from all plant systems (mechanical/electrical and l&C) and structures

were scoped collectively under one electrical and l&C component group. However, if the

electrical and l&C components provided a mechanical component function, such as a

pressure boundary, the components were evaluated individually for aging management

along with other components in the mechanical system.

Structure and Structural ComDonent Scoping Methodology. The applicant described the

methodology used for structural scoping in Section 2.1.4.3, "Structure Scoping Methodology," of

the LRA. Structures include freestanding buildings, separately evaluated rooms that are

contiguous with freestanding buildings, the primary containment shell, tank foundations, the

station chimney, and commodity-like groupings of cranes and hoists. The applicant stated that

the list of structures used for scoping was developed through review of site plot drawings in

conjunction with a walkdown of the property at each site. The UFSARs were relied upon to

identify safety classification of structures and structural components. Class I structures and

structural components were considered safety-related.

The structural scoping methodology described in the LRA was similar to the mechanical system

scoping described in Section 2.1.4.1 of the LRA. Structure descriptions were prepared that

included all structure functions. Structure evaluation boundaries were determined, including

examination of structure interfaces. All structure functions were evaluated against the criteria of

10 CFR 54.4(a)(1-3) and the results of this evaluation were documented in the LR database.

In those instances in which the structure intended functions were supported by other structures

or systems, the supporting systems or structures were identified and evaluated against the

criteria in 10 CFR 54.4(a)(2). The applicant stated that although a structural boundary drawing

was not created for structures, a single boundary diagram based on site plot or equipment

layout drawings was created for each site and displays all of the structures in relation to one

another.

The applicant noted that, although the controlled plant component database includes some

structural components such as pipe supports, equipment anchors, ladders, and doors, it does

not include most of the structural components that constitute a structure. Therefore, for

structures determined to be within the scope of the Rule, more detailed structural drawings

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were reviewed and, where needed,'Walkdowns were performed to identify structural elements

(such as structural steel, foundations, floors, walls, ceilings, penetrations, stairways, or curbs).

For in-scope structures, all structural components that are required to support the intended

functions of the structure were entered into the LR database as generic structural components

and were identified as within the scope of the Rule.

i Electrical and Instrumentation and Control System and Component Scoping Methodology. The

applicant described the methodology used to scope electrical and l&C systems in

Section 2.1.4.2, "Electrical and Instrumentation and Control System Scoping Methodology," of

the LRA. At the system level, the scoping methodology utilized for electrical and l&C systems

was identical to the mechanical system-level scoping described in Section 2.1.4.1. The

UFSAR, Maintenance Rule database records, CLB and design-basis documents, and system

description documents applicable to the system were reviewed to determine the system safety

classification and to identify all of the system functions. All system level functions were

evaluated against the criteria of 10 CFR 54.4(a)(1-3). The supporting systems needed to

maintain the in-scope system intended functions were identified and evaluated against the

criteria in 10 CFR 54.4(a)(2). License renewal boundary diagrams were not created for

electrical systems. However, boundary diagrams showing the basic electrical distribution

throughout the plant and the associated switchyards were created for each site.

The applicant stated that the spaces approach was used to scope electrical and l&C

components. Therefore, the applicant identified the electrical and l&C commodity groups that

were installed in the plant rather than performing a detailed review to scope specific electrical

and l&C components in each in-scope system.

Commodity Group Scoping. In Section 2.1.6 of the LRA, the applicant described its use of

mechanical, structural, and electrical commodity groups for certain types of generic

components during the scoping process. The use of these commodity groups for each of these

scoping areas is discussed below.

In Section 2.1.6 of the LRA, the applicant stated that mechanical system piping

components that-were not uniquely identified in the controlled plant component databases

were evaluated as part of a system-specific commodity group. When a system was

determined to include in-scope commodity items, the commodity items for the system

were evaluated and were entered as a representative commodity component into the LR

database for the system. For systems determined to have in-scope commodity

components made of more than one material. The LR database was modified to include

multiple commodity component records corresponding to the different component

materials.

The applicant also noted that Dresden and Quad Cities use thermal insulation and

jacketing on piping and equipment for a variety of purposes. The applicant recognized

that thermal insulation and jacketing on piping and equipment could not readily be scoped

against the requirements of 10 CFR 54.4(a)(2) based simply on the plant system where

they are used. Therefore, for each plant piping system, the applicant reviewed the

insulated pipe plant specifications to determine which systems had installed insulation.

For each piping system with insulation installed, the applicant identified an insulation

commodity group representing all of the insulation of that type within the system and

initially classified the insulation commodity group as within the scope of license renewal.

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During AMR of the insulation commodity group, further evaluation of the design purpose

for the insulation requirement for each system confirmed or revised the in-scope

classification of the system insulation components.

* Structural elements and components were evaluated in commodity groupings that were

based on similarity of materials and component functions. For example, an in-scope

building comprises several wall elements and may include multiple, but similar, structural

components such as equipment supports or doors. The scoping and screening evaluation

did not identify and evaluate these multiple structural components on an individual basis.

Rather, the evaluation grouped similar structural components as generic components for

scoping and screening.

* Electrical and I&C components in electrical and l&C systems and some electrical and l&C

components in mechanical systems and structures were evaluated as a consolidated

electrical and l&C component group. Electrical components were identified and assigned

to this consolidated electrical and l&C component group for scoping and screening

evaluation. All components assigned to the consolidated electrical and l&C component

group were initially identified as in scope of the Rule. After their assignment to the

consolidated electrical and l&C component group, some individual components were

reevaluated on the basis of their specific design function. If it were determined that the

component did not perform an intended function as described in 10 CFR 54.4, the

component was classified as outside the scope of the Rule.

2.1.2.2 Screening Methodology

Following the identification of SSCs within the scope of license renewal, the applicant

implemented a process for determining which SSCs would be subject to an AMR in accordance

with the requirements of 10 CFR 54.21(a)(1). In LRA Section 2.1.5, "Screening Methodology,"

the applicant discussed these screening activities as they related to the SCS that are within the

scope of license renewal. These screening activities consisted of the identification of

mechanical, structural, and electrical and l&C components within the scope of license renewal

and subject to an AMR. The applicant's screening methodology described in the LRA for

mechanical, structural, and electrical and l&C components is presented below.

2.1.2.2.1 Mechanical Component Screening

Following component-level scoping for mechanical systems, the applicant performed screening

to identify those mechanical components that were subject to an AMR. As described in LRA

Section 2.1.5.1, "Mechanical System Component Screening Methodology," the applicant used

the following methodology.

After a mechanical system component was categorized in the LR database as within the scope

of the Rule, the applicant classified the component as either active or passive based on an

evaluation of the component description and type. The applicant used the active/passive

component determinations documented in Appendix B of NEI 95-10, as guidance for this

activity. Components that were recognized during screening as short-lived were eliminated from

the AMR process, and the basis for the classification as short-lived was documented in the LR

database. All other in-scope passive components were identified as long-lived. Long-lived,

passive components within the scope of license renewal were identified as subject to an AMR

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and evaluated to determine their component-level intended function(s). During the AMR

process, if detailed review of maintenance procedures and requirements determined that a

component previously categorized as long-lived was subject to replacement based on a

qualified life or specified time period, the component was recategorized as short-lived and

eliminated from the AMR evaluation process. The results of the component screening were

recorded in the LR database.

2.1.2.2.2 Structural Component Screening

Following component-level scoping for structures, the applicant performed screening to identify

those civilstructural components that were subject to an AMR. In LRA Section 2.1.5.3,

"Structural Component Screening Methodology," the applicant described the methodology used

to screen civil/structural components. The applicant stated that when a structure or structural

component was determined to be within the scope of license renewal, the structure screening

methodology classified the component as passive. An evaluation was made to determine

whether in-scope structural components were subject to replacement based on a qualified time

period. If the in-scope structural component were subject to replacement based on a qualified

time period, the component was identified as short-lived and was excluded from an AMR. The

applicant stated that, except for a very limited number of structural components that were

excluded on the basis of being subject to replacement per criterion 10 CFR 54.21 (a)(1)(ii), all in

scope structures and structural components were subject to an AMR.

2.1.2.2.3 Electrical and I&C Component Screening

In LRA Section 2.1.5.2, "Electrical and l&C System Component Screening Methodology," the

applicant described the methodology used to screen electrical and I&C components. The

applicant stated that, based on the spaces approach to AMR for electrical components, all

electrical and l&C components classified as within the scope of the license renewal were

evaluated as a consolidated electrical and I&C component group. The applicant stated that

components were categorized as "active" or "passive" based on the determinations

documented in Appendix B of NEI 95-10. In-scope components determined to be passive were

identified in the LR database as subject to an AMR. In Section 2.1.6 of the LRA, the applicant

stated that for most passive components within the scope of license renewal, the determination

of whether a component was short-lived or long- lived was made during the AMR process when

procedures for maintaining and replacing plant equipment were reviewed in detail. The

component-level intended function(s) were determined for each in-scope passive component

and recorded in the LR database. All passive electrical and I&C commodity components, such

as cables, are subject to an AMR unless they were specifically evaluated and determined not to

perform an intended function as described in 10 CFR 54.4. Electrical and I&C components

from mechanical systems were screened collectively using the spaces approach along with

similar components from electrical and l&C systems. This also applied to any electrical and

I&C components associated with structures. Any mechanical or structural components in

electrical and l&C systems that were determined to be within the scope of the Rule were

categorized as "active" or "passive" based on the determinations documented in NEI 95-10.

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2.1.3 Staff Evaluation

The staff evaluated the LRA scoping and screening methodology in accordance with the

guidance contained in Section 2.1, 'Scoping and Screening Methodology," of NUREG-1800,

"Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants."

(SRP-LR). The acceptance criteria for the scoping and screening methodology review are

based on the following regulations:

* 10 CFR 54.4(a), as it relates to the identification of plant SSCs within the scope of the

Rule

* 10 CFR 54.4(b), as it relates to the identification of the intended functions of plant SSCs

determined to be within the scope of the Rule

* 10 CFR 54.21(a)(1) and (a)(2), as they relate to the methods utilized by the applicant to

identify plant structures and components subject to an AMR

As part of the review of the applicant's scoping and screening methodology, the NRC staff

reviewed the activities described in the following sections of the LRA using the guidance

contained in NUREG-1 800:

* Section 2.1 ("Scoping and Screening Methodology") to ensure that the applicant described

a process for identifying SSCs that are within the scope of license renewal in accordance

with the requirements of 10 CFR 54.4(a)(1), (a)(2), and (a)(3)

* Section 2.2 ("Plant-Level Scoping Results"), Section 2.3 ("Scoping and Screening Results:

Mechanical Systems"), Section 2.4 ("Scoping and Screening Results: Structures"), and

Section 2.5 ("Scoping and Screening Results: Electrical and Instrumentation and Control

Systems") to ensure that the applicant described a process for determining structural,

mechanical, and electrical components at the Dresden and Quad Cities Nuclear Power

Stations that are subject to an AMR in accordance with the requirements of 10 CFR

54.21 (a)(1) and (a)(2)

In addition, the staff conducted a scoping and screening methodology audit at Exelon corporate

offices in Warrenville, Illinois, from May 20-23, 2003. The focus of the audit was to ensure that

the applicant had developed and implemented adequate guidance to conduct the scoping and

screening of SSCs in accordance with the methodologies described in the application and the

requirements of the Rule. The audit team reviewed implementation procedures and

engineering reports which describe the scoping and screening methodology implemented by

the applicant. In addition, the audit team conducted detailed discussions with the applicant on

the implementation and control of the license renewal program and reviewed administrative

control documentation and selected design documentation used by the applicant during the

scoping and screening process. The audit team further reviewed a sample of system scoping

and screening results reports for the core spray (CS) system, reactor core isolation cooling

(RCIC) system (Quad Cities only), isolation condenser (Dresden only), reactor building closed

cooling water system, and main feedwater system to ensure that the methodology outlined in

the administrative controls was appropriately implemented and the results were consistent with

the CLB.

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2.1.3.1 Scoping Methodology

: The staff reviewed the scoping process to verify that the applicant's methodology was

consistent with NUREG-1800 and other documented staff positions and that the scoping

methodology adequately identified SSCs within the scope of license renewal in accordance with

the requirements of 10 CFR 54.4(a).

2.1.3.1.1 Implementation Procedures and Documentation Sources Used for Scoping and

Screening

The staff reviewed the applicant's scoping and screening implementation procedures to verify

that the process used to identify structures and components subject to an AMR was consistent

with the LRA and NUREG-1 800 and that the applicant appropriately implemented the

procedural guidance. Additionally, the staff reviewed the scope of CLB documentation sources

used to support the LRA development and the process used by the applicant to ensure that

CLB commitments were appropriately considered during the scoping and screening process.

Review of Methodology Implementation Procedures. The staff reviewed the following scoping

and screening methodology implementation procedures and engineering reports:

* GE-NE-LRTI-2000, "Scoping and Screening of Systems, Structures, and Components for

License Renewal"

* LRTI-16, "Identification of Non Safety-related Structures and Components Which Spatially

or Structurally Interact With Safety-related Systems"

* PP-QDC-DRE Revision 00 IN, "Treatment of Pipe/Equipment Insulation During Scoping and

Screening Systems for License Renewal"

* PP-DRE&QDC Revision 02-AP, "Active/Passive Classification and Intended Function

Determination of Structures and Components"

* PP-DRE-QDC Revision 01 SPACES, "Scoping and Screening Position Paper for Electrical

Components Based on Electrical Spaces Approach for Aging Management Review"

* Desktop Guide, "Scoping & Screening of Systems, Structures and Components"

In reviewing these procedures, the staff focused on the consistency of the detailed procedural

guidance with information in the LRA and the various NRC staff positions documented in

NUREG-1 800 and ISG documents. The team found that the scopinig and screening

methodology instructions were generally consistent with Section 2.1 of the LRA and were of

sufficient detail to provide the applicant's staff with concise guidance on the scoping and

screening implementation process to be followed during the LRA activities.

During the scoping and screening methodology audit, the audit team identified that some of the

applicant's implementation procedures were based on a version of NEI 95-10 that was not

endorsed by the NRC. Specifically, the staff noted that the applicant used guidance from

Revision 2 to NEI 95-10, dated August 2000, to develop certain portions of the scoping and

screening procedures. For example, procedure PP-DRE&QDC Revision 02-AP,

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"Active/Passive Classification and Intended Function Determination of Structures and

Components," Section 3, stated that the classification of components was performed in

conformance and consistent with the guidelines provided in NEI 95-10, Revision 2. In

Regulatory Guide 1 .188, "Standard Format and Content for Application to Renew Nuclear

Power Plant Operating Licenses," issued July 2001, the NRC endorsed Revision 3 to

NEI 95-10, dated March 2001, as providing an acceptable method for complying with the

license renewal rule. Because the applicant utilized a version of NEI 95-10 that has not been

endorsed by the NRC staff for LRA development, in Request for Additional Information

(RAI) 2.1-5, the staff asked the applicant to identify the differences that exist between Revisions

2 and 3 of NEI 95-10 and the potential impact on the LRA.

In its October 3, 2003, response to RAI 2.1-5, the applicant stated that, based on a comparison

between NEI 95-10 Revision 2 and Revision 3, the major substantive changes involved the new

LRA format; some changes to Appendix B, "Typical Structure, Component and Commodity

Groupings and Active/Passive Determinations for the Integrated Plant Assessment"; and

additional guidance on the treatment of consumables. The applicant stated that (1) there were

no changes in Revision 3 of NEl 95-10 Appendix B tables for active/passive determinations for

components that impacted the conclusions or methodology implemented for the Dresden/Quad

Cities component screening and (2) the Exelon evaluation process for evaluating consumables

was consistent with the screening guidance provided in Table 2.1-3 of NUREG- 1 800. The staff

reviewed the changes between Revisions 2 and 3 of NEI 95-10, the applicant's guidance for

active/passive screening determinations, and the applicant's treatment of consumable items.

Based on these reviews, the staff concluded that the applicant's response to RAI 2.1-5 was

reasonable and the use of NEI 95-10, Revision 2, for LRA development did not adversely

impact the scoping and screening methodology. Therefore, RAI 2.1-5 has been resolved.

Methods Used to Review the Current Licensing Basis. The staff reviewed the scope and depth

of the applicant's CLB review to verify that the methodology was sufficiently comprehensive to

identify SSCs within the scope of license renewal and structures and components requiring an

AMR. As defined in 10 CFR 54.3(a), the CLB is the set of NRC requirements applicable to a

specific plant and a licensee's written commitments for ensuring compliance with and operation

within applicable NRC requirements and the plant-specific design basis that are docketed and

in effect. The CLB includes certain NRC regulations, orders, license conditions, exemptions,

technical specifications, design-basis information documented in the most recent updated final

safety analysis report (UFSAR), and licensee commitments remaining in effect that were made

in docketed licensing correspondence such as licensee responses to NRC bulletins, generic

letters, and enforcement actions, as well as licensee commitments documented in NRC safety

evaluations or licensee event reports.

The staff determined that LRA Section 2.1.3, "Documentation Sources Used for Scoping and

Screening," provides a description of the CLB and related documents used during the scoping

and screening process that is consistent with the guidance contained in NUREG-1 800 and

NEI 95-10. However, the applicant's methodology implementation procedures do not describe

the process used to review certain CLB and design-basis documents such as safety evaluation

reports (SERs), license event reports, and responses to NRC bulletins, generic letters, and

enforcement actions in a manner that ensured that all system and structure functions were

identified for the purposes of license renewal scoping. Because the staff was unable to fully

evaluate the process used to review CLB documents, the staff requested in RAI 2.1-8 that the

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applicant describe the method(s) used to review the CLB documents identified in Section 2.1.3

of the LRA for the purposes of identifying all applicable SSCs functions.

In its October 3, 2003, response to RAI 2.1-8, the applicant stated that the first level of

documents reviewed included the UFSARs, the Maintenance Rule databases, the

system/structure design-basis documents, and the system/structure operational description

documents. Based on references contained in the initially reviewed documents, the applicant

stated that additional CLB documents such as SERs, license event reports, and responses to

NRC bulletins, generic letters, and enforcement actions were identified for review. In addition,

the applicant noted that electronic searches based upon key words or document numbers were

also conducted. The staff concluded that the identification of CLB documents such as SERs,

license event reports, and responses to NRC bulletins, generic letters, and enforcement actions

using reference information from other parent CLB documents, in combination with electronic

document searches, provides reasonable assurance that the applicant considered a broad

scope of CLB document sources during scoping and screening. The staff determined that the

applicant's response to RAI 2.1-8 was reasonable; therefore, RAI 2.1-8 is resolved.

Based on a review of information provided in Section 2.1 of the LRA, a review of the applicant's

detailed scoping and screening implementation procedures, and the results from the scoping

and screening audit, the staff concluded that the applicant's scoping and screening

methodology considered a sufficient scope and depth of CLB information. The staff determined

that the CLB documentation review methodology was capable of identifying SSCs intended

functions in a manner consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21.

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

The staff evaluated the applicant's methodology for scoping SSCs pursuant to the requirements

of 10 CFR 54.4(a). The results of this staff evaluation are described below.

Application of the Scooina Criteria in 10 CFR 54.4(a)(1). In part, 10 CFR 54.4(a)(1) requires

that the applicant consider all safety-related SSCs that are relied upon to remain functional

during and following design-basis events to ensure (1) the integrity of the reactor coolant

pressure boundary, (2) the ability to shut down the reactor and maintain it in a safe shutdown

condition, or (3) the capability to prevent or mitigate the consequences of accidents which could

result in potential offsite exposures comparable to those referred to in 10 CFR 50.34(a)(1),

10 CFR 50.67(b)(2), or 10 CFR 100.11, to be within the scope of the license renewal.

The applicant performed scoping of safety-related SSCs in accordance with implementation

procedure GE-NE-LRTI-2000 and the Scoping and Screening Desktop Guide. Section 4.1.4 of

procedure GE-NE-LRTI-2000 includes a checklist used to determine if a structure or system

meets the safety-related scoping criteria of 10 CFR 54.4(a)(1). Although the applicant's safetyrelated checklist items were similar to the criteria contained in 10 CFR 54.4(a)(1), the staff

identified some differences. Specifically, the checklist items associated with safety-related

scoping did not specifically address the full scope of potential offsite exposure limits referenced

in 10 CFR 54.4(a)(1)(iii) and the spectrum of design-basis events to be considered for safetyrelated scoping. The staff requested additional information to clarify the use of the safetyrelated scoping questions. The staff's evaluation of these two issues is described below:

Scope of Potential Offsite Exposure Limits Considered for Safety-Related Scoping

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Although the wording in LRA Section 2.1.2.1, "Title 10 CFR 54.4(a)(1)-Safety-Related," is

consistent with the scoping requirements of 10 CFR 54.4(a)(1)(iii), the safety-related

scoping checklist items contained in Section 4.1.4 of procedure GE-NE-LRTI-2000 do not

include all the exposure limitations referenced in 10 CFR 54.4(a)(1)(iii). Specifically,

GE-NE-LRTI-2000 does not include a reference to offsite exposures limits comparable to

those referred to in 10 CFR 50.34(a)(1) and 10 CFR 50.67(b)(2). Because the failure to

consider exposure limitations contained in 10 CFR 50.34(a)(1) and 10 CFR 50.67(b)(2)

could result in the omission of safety-related SSCs from the scope of license renewal, in

RAI 2.1-1, the staff requested the applicant to describe how these exposure limitations, as

applicable, were factored into the license renewal scoping and screening process.

In its October 3, 2003, response to RAI 2.1-1, the applicant clarified how the exposure

limitations of Section 50.34(a)(1) and Section 50.67(b)(2) were factored into the scoping

methodology. The applicant noted that 10 CFR 50.34 applies to applications for a

construction permit and that Exelon has not applied for a construction permit for either the

Dresden or Quad Cities stations. However, the applicant stated that it has submitted

license amendment requests for the Dresden and Quad Cities stations to support

application of an alternate source term methodology pursuant to 10 CFR 50.67(b)(2). To

support the alternate source term submittal, the applicant evaluated the radiological

consequence analyses of the four design-basis accidents (DBAs) that result in offsite

exposure and identified proposed changes to the CLB. The applicant stated that none of

the proposed CLB changes would result in changes to system or equipment license renewal

intended functions. Based on this response, the staff concluded that the applicant

adequately considered the exposure limitations associated with 10 CFR 50.34 and

10 CFR 50.67 in performing safety-related scoping. Therefore, RAI 2.1-1 is resolved.

Spectrum of Design-Basis Events Considered for Safety-Related Scoping

In part, 10 CFR 54.4(a)(1) states that SSCs within the scope of license renewal include

safety-related SSCs that are relied upon to remain functional during and following designbasis events (as defined in 10 CFR 50.49(b)(1)). As defined in 10 CFR 50.49, design-basis

events are conditions of normal operation, including anticipated operational occurrences,

design-basis accidents, external events, and natural phenomena for which the plant must

be designed. In regard to identification of design-basis events, Section 2.1.3, "Review

Procedures," of NUREG-1 800 states the following:

The set of design basis events as defined in the rule is not limited to Chapter 15 (or equivalent)

of the UFSAR. Examples of design basis events that may not be described in this chapter

include external events, such as floods, storms, earthquakes, tornadoes, or hurricanes, and

internal events, such as a high-energy-line break.

During the scoping and screening methodology audit, the NRC staff questioned how

nonaccident design-basis events, particularly design-basis events that may not be

described in the UFSAR, were considered during scoping. The staff noted that, although

GE-NE-LRTI-2000, Section 4.1.4, includes safety-related scoping criteria similar to

10 CFR 54.4(a)(1), the procedure did not appear to clearly define the scope of design-basis

events that were to be considered during scoping. During the scoping and screening

methodology audit, the applicant was unable to provide sufficient information to

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demonstrate that design-basis events not included in the UFSAR Chapter 15 accident

analyses were adequately considered during scoping. The staff determined that limiting the

review of design-basis events to design-basis accidents described in Chapter 15 of the

UFSAR could result in omission of safety-related functions described elsewhere in the CLB.

For example, the Dresden UFSAR, Section 3.4.1.1, "External Flood Protection Measures,"

indicates that the isolation condenser has a safety-related function during a design-basis

flooding event to provide core cooling. However,' during the methodology audit, the team

noted that the isolation condenser system-level intended functions did not include a safetyrelated function for providing capability to shut down the reactor and maintain it in a safe

shutdown condition. Therefore, in RAI 2.1-7, the staff requested the applicant to explain the

basis for the determination that the safety-related intended functions of the isolation

condenser system did not include shutting down the reactor and maintaining it in a safe

shutdown condition. Additionally, in RAI 2.1-7, the staff requested the applicant to describe

the methodology used to ensure that all design-basis events (including conditions of normal

operation, anticipated operational occurrences, design-basis accidents, external events, and

natural phenomena) were addressed during license renewal scoping.

In its October 3, 2003, response to RAI 2.1-7, the applicant stated that the Dresden and

Quad Cities site safety classifications were based on a definition of 'safety-related" that did

not incorporate the 10 CFR 50.49(b)(1) definition of design-basis events. Consequently,

the applicant indicated that the CLB definition of 'safety-related" for the Dresden and Quad

Cities sites is not the same as that given in 10 CFR 54.4(a)(1). Specifically, the applicant

noted that its CLB definition of "safety-related" does not include SSCs used to mitigate

nonaccident design-basis events (e.g., such as tornados, external flooding, internal

flooding, high-energy line breaks, dam failures, and earthquakes).

In preparation for responding to RAI 2.1-7, the applicant reviewed the SSCs credited for

safe shutdown during nonaccident events to ensure that the intent of 10 CFR 54.4(a) was

met. As a result of this review, the applicant identified additional components associated

with high-energy line break nonaccident events that were within the scope of license'

renewal but had not been previously identified. The specific components added to the LR

scope were associated with the applicant's scoping of non-safety-related high-energy

systems and are described in 'Application of the Scoping Criteria in 10 CFR 54.4(a)(2),"

below. The applicant noted that the additional components included within the scope of

license renewal as a result of nonaccident events were not classified as "safety-related" as

defined in the licensing basis for each site. To remain consistent with the existing licensing

basis for each site, these SSCs were included within the scope of license renewal under the

criteria of 10 CFR 54.4(a)(2). Therefore, for the Dresden and Quad Cities sites, SSCs

meeting the scoping criteria of 10 CFR 54.4(a)(1) were identified during the applicant's

Section 54.4(a)(1) and Section 54.4(a)(2) scoping efforts.

With regard to the scoping of the safety-related function of the isolation condenser during a

flooding event, the applicant stated that the'CLB search for intended functions for the

isolation condenser inadvertently missed the statement in Section 3.4.1.1 of the UFSAR

crediting the core cooling function of the isolation condenser. Although inadvertentlyomitting SSCs intended functions described in the CLB could result in the failure to include

appropriate equipment within the scope of license renewal, the staff determined that the

additional reviews conducted by the applicant in response to RAI 2.1-7 provide additional

assurance that intended functions have been identified. The staff concluded that the

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applicant's scoping efforts conducted pursuant to 10 CFR 54.4(a)(1) and 10 CFR 54.4(a)(2),

in addition to the scoping evaluations performed for RAI 2.1-7, ensured that SSCs meeting

the scoping criteria of 10 CFR 54.4(1) were included within the scope of the rule and

evaluated for aging management. Therefore, RAI 2.1-7 has been resolved.

Following scoping of structures and systems, the applicant performed safety-related component

scoping. During the scoping and screening methodology audit, the applicant stated that the

EWCS database included safety classification data for certain SSCs. The applicant stated that

the safety classification obtained from the EWCS database was initially used to scope safetyrelated components. During the methodology audit, the staff identified that the EWCS safety

classification field for several components was blank in the license renewal database. The

applicant stated that a blank safety classification field indicated that a safety classification

review of the component had not been performed, and therefore, the EWCS database did not

have safety classification data for the component. The applicant stated that GE License

Renewal Instruction Letter GE LR 002, Revision 3, related to GE-NE-LRTI-2000, provided

guidance for handling EWCS component data deficiencies, including blank safety classification

fields. The guidance stated that, if the component with a blank safety-related classification field

was a daughter component to a safety-related parent component, then the daughter component

should be classified as safety-related. If the component was not a daughter to a safety-related

component, the guidance specified that further evaluation was needed. During the audit, the

applicant stated that P&lDs and other controlled documents would be used in these cases to

determine the proper safety classification. The staff determined that the applicant's utilization

of EWCS safety classification data, including the resolution of data deficiencies, was

reasonable.

The audit team reviewed a sample of the license renewal database 10 CFR 54.4(a)(1) scoping

results and discussed the methodology and results with the applicant's license renewal project

personnel. The team verified that the applicant had identified and used pertinent engineering

and licensing information in order to determine the SSCs required to be in scope in accordance

with the 10 CFR 54.4(a)(1) criteria. On the basis of this sample review, discussions with the

applicant, and review of the applicant's scoping process, the staff determined that the

applicant's methodology for identifying systems and structures meeting the scoping criteria of

10 CFR 54.4(a)(1) was adequate.

Application of the Scoping Criteria in 10 CFR 54.4(a)(2). As required by 10 CFR 54.4(a)(2) all

non-safety-related SSCs whose failure could prevent satisfactory accomplishment of any of the

functions identified in 10 CFR 54.4(a)(1) must be within the scope of the license renewal.

Guidance for the staff review of non-safety-related scoping is provided in NUREG-1 800,

Section 2.1.3.1.2, 'Non-safety-Related." The staff provided further expectations for determining

what SSCs met the 10 CFR 54.4(a)(2) criterion in letters dated December 3, 2001, and March

15, 2002. In the December 3rd letter (ADAMS Accession No. ML013380013) the staff described

the expectation that both seismic 11/I piping segments and their supports should be included

within the scope of license renewal under the 10 CFR 54.4(a)(2) criterion. Additionally, the

letter provided specific examples of operating experience which identified pipe failure events

(summarized in Information Notice (IN) 2001-09, "Main Feedwater System Degradation in

Safety-Related ASME Code Class 2 Piping Inside the Containment of a Pressurized Water

Reactor") and the approaches the NRC considers acceptable to determine which piping

systems should be included in scope based on the 54.4(a)(2) criterion. The March 15'" letter

(ADAMS Accession No. ML020770026) further described the staff's expectations for the

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evaluation used to determine which non-safety-related SSCs are in scope due to the potential

to adversely impact safety-related intended functions. The position states that applicants

should not consider hypothetical failures, but rather should base their evaluation on the plant's

current licensing basis, engineerinrg judgement and analyses, and relevant operating

experience. The paper further describes operating experience as all documented plant-specific

and industry wide experience which can be used to determine the plausibility of a failure.

Documentation would include NRC generic communications and event reports, plant-specific

condition reports, industry reports such as significant operating event reports (SOERs), and

engineering evaluations.

The applicant's methodology for performing 10 CFR 54.4(a)(2) scoping of non-safety-related

SSCs was documented in implementation procedure GE-NE-LRTI-2000, the Scoping and

Screening Desktop Guide, and license renewal technical instruction (LRTI)-1 6, "Identification of

Non Safety-related Structures and Components Which Spatially or Structurally Interact With

Safety-related Systems." The applicant performed the initial scoping of non-safety-related

structures and systems using a checklist item contained in Section 4.1.4 of procedure

GE-NE-LRTI-2000 to identify if a structure or system met the non-safety-related scoping criteria

of 10 CFR 54.4(a)(2). During the scoping and screening methodology audit, the applicant

stated that the checklist item applicable to 10 CFR 54.4(a)(2) was initially interpreted to apply

only to non-safety-related structures and components that provided support functions to safetyrelated equipment. Following issuance of the staff's March 15, 2002, letter on scoping SSCs

per 10 CFR 54.4(a)(2), the applicant revised the non-safety-related scoping methodology to

consider non-safety-related SSCs seismic and spatial interactions that could adversely impact

safety-related intended functions. Consequently, the applicant added Attachment 2, "Guidance

for Identification and Documentation of Structures, Systems, and Components (SSCs) which

Meet 10 CFR 54.4(a)(2)," to GE-NE-LRTI-2000 to provide guidance for the revised scoping of

non-safety-related SSCs. Technical instruction LRTI-1 6 provided the detailed methodology for

identifying non-safety-related SSCs that could spatially interact with safety-related SSCs: The

LRTI-16 scoping process included the following steps:

* An inventory was taken to identify all systems that contain equipment located in each plant

area that contained at least one safety-related component.

* The applicant completed a spatial interaction checklist to identify non-safety-related systems

that could spatially interact with safety-related equipment. The checklist was completed

based on the results of walkdowns and spatial interaction screening criteria contained in

LRTI-16. The LRTI-16 screening criteria identified specific seismic and spatial interactions

that the applicant considered to be credible means for non-safety-related SSCs to adversely

interact with safety-related equipment.

* In situations where non-safety-related piping physically connected to a safety-related

system, the portion of the non-safety-related system providing structural support to the

safety-related system was included within the scope of the rule up to the point where the

non-safety-related system was anchored in three dimensions.

The staff reviewed the applicant's scoping methodology, as described in the LRA and

; associated implementation procedures, to verify that it was consistent with the guidance

provided in NUREG-1 800 and related staff positions. Additionally, during the scoping

methodology audit, the staff reviewed a sampling of scoping results to determine if the

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methodology adequately identified non-safety-related SSCs meeting the scoping criteria of

10 CFR 54.4(a)(2). Based on a review of the LRA, the applicant's scoping and screening

implementation procedures, and discussions with the applicant, the staff determined that

additional information was required to assess certain aspects of the applicant's scoping

methodology for the 10 CFR 54.4(a)(2) criteria. In RAI 2.1-2, the staff requested the applicant

to address the following five issues:

(a) In LRA Section 2.1.2.2, "Title 10 CFR 54.4(a)(2) - Non-safety-related affecting safetyrelated," the applicant stated that plant walkdowns were performed to identify those areas

containing safety-related SSCs. The applicant further stated in LRA Section 2.1.2.2 that, in

those instances where a plant walkdown could not be performed, plant drawings were used

to identify those areas containing safety-related SSCs and to identify component

interactions. For areas where walkdowns could not be performed to identify non-safetyrelated SSCs that could affect safety-related SSCs, the staff requested the applicant to

describe the methodology and documentation sources used to perform scoping pursuant to

10 CFR 54.4(a)(2).

In its October 3, 2003, response to RAI 2.1-2.a, the applicant provided a listing of plant

areas where plant drawings were used to identify spatial interactions rather than a physical

area walkdown. Controlled plant piping layout drawings for the various elevations of the

plant were used to identify those areas containing safety-related SSCs and to identify

component interactions. Controlled electrical/instrumentation physical layout drawings were

also used to aid in the identification of safety-related components in the areas. The

applicant stated that this review of controlled plant drawings was only performed for highradiation areas where personnel entry at power operation would have resulted in an

unnecessary accumulation of dose. The staff determined that the applicant provided a

reasonable basis for not performing physical walkdowns for the identified areas of the plant.

Further, the use of controlled plant piping layout and electrical/instrumentation plant

drawings was a reasonable method for identifying potential spatial interactions for these

areas. On this basis, the staff concluded that RAI 2.1-2.a is resolved.

(b) Instruction LRTI-16, "Identification of Non Safety-related Structures and Components Which

Spatially or Structurally Interact With Safety-related Systems," describes the process used

to identify non-safety-related systems and components which meet the scoping criteria

specified in 10 CFR 54.4(a)(2) due to spatial or structural interaction with safety-related

systems. Section 4.3 of LRTI-16 states that non-safety-related systems were evaluated

using the screening criteria provided in LRTI-16, Table 2, "Spatial Interaction Screening

Criteria." The staff requested the applicant to describe the basis and/or provide justification

for the use of the following spatial interaction screening criteria contained in LFRTI-1 6,

Table 2:

Pipe whip and jet impingement apply only to high-energy systems containing fluids with

temperatures greater than or equal to 200 0F and a pressure greater than or equal to

275 psig (LRTI-16, Table 2, Item 5). The staff noted that this definition of high-energy

systems appeared to be inconsistent with the CLB definition of a high-energy system as

described in the Dresden UFSAR, Section 3.6.1.1.1.1, which indicated that a fluid was

high energy when the temperature exceeds 200 OF or the pressure exceeds 275 psig.

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* Spray from high-energy systems can affect equipment up to 25 feet (LRTI-16, Table 2,

Item 10).

* Cables in conduit or trays are not affected by water spray as long as the spray does not

target a cable termination area (LRTI-1 6, Table 2, Item 4).

* Spray from medium-/low-energy systems can affect equipment up to 20 feet (LRTI-1 6,

Table 2, Item 1 1). The applicant defined medium-/low-energy systems as any system

that did not meet the definition of a high-energy system.

* Early detection of leaks (sumps and floor drain systems) is given credit in the scope of

the rule for preventing long-term degradation of passive equipment and flooding beyond

the lowest elevation of the building (LRTI-16, Table 2, Item 8).

* Fluid spray can affect only active components (LRTI-16, Table 2, Item 6).

In its October 3, 2003, response to RAI 2.1-2.b, the applicant provided additional

information relating to each of the above spatial interaction screening criteria.

High-Energy System Definition and Scoping

The applicant stated that the definition of a high-energy system used during scoping and

screening evaluations was consistent with the specific licensing basis at each site.

Consequently, Quad Cities defined a high-energy system as a system where the

temperature and pressure conditions of fluid exceed 200 IF and 275 psig, respectively,

while Dresden defined a high-energy system as one where the temperature or pressure

conditions of fluid exceed 200 'F and 275 psig, respectively. The applicant indicated that all

systems meeting the plant-specific licensing basis definition of a high-energy system at

each site were evaluated for spatial interactions.

In its response to the RAI, the applicant did not justify the use of the 25-foot separation

criterion but instead revised the scoping methodology to consider potential spatial

interactions between high-energy systems and safety-related SSCs separated by more than

25 feet. The applicant stated that all high energy piping located inside the primary

containment was safety-related and included within the scope of license renewal under

10 CFR 54.4(a)(1) scoping criteria. For high energy piping located outside the primary

containment, the applicant re-evaluated the scoping boundaries for the following highenergy systems to account for potential spatial interactions:

* main steam -

* feedwater

* high pressure coolant injection

* reactor water cleanup

* reactor core isolation cooling (Quad Cities only)

* isolation condenser (Dresden only)

* extraction steam to heaters A, B, C, or D

* heater drain from heater C or D

* condensate booster lines

* moisture separator drain

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* control rod drive hydraulic system

As a result of this re-evaluation, the applicant expanded the scoping boundaries of the main

steam, feedwater, reactor water cleanup (RWCU), and control rod drive (CRD) systems.

The applicant stated that the expanded boundaries are now consistent with the scope of

high-energy line breaks analyzed in the CLB and described in Appendix 3A of the UFSAR

for both sites. The staff evaluation mechanical system scoping results and aging

management programs (AMPs) associated with these expanded boundaries are described

in Sections 2.3.1 and 3.1 of this report. The staff concluded that the applicant's scoping

methodology for high-energy systems was consistent with the plant-specific licensing bases

for the Dresden and Quad Cities sites and considered an adequate scope of potential

spatial interactions.

Fluid Spray Interactions with Cables

In its October 3, 2003, response to RAI 2.1-2.b, the applicant stated that the technical

justification for the assumption that cables in conduit or trays are not affected by water

spray is that the cables are protected by the cable insulation and jacketing. The applicant

also noted that cable pan covers and conduit provide additional protection of cable from

water spray. The staff concluded that the applicant provided a reasonable basis for its

approach to the scoping of cables in conduit or trays.

Fluid Spray Interactions and Flooding

In its October 3, 2003, response to RAI 2.1-2.b, the applicant stated that the only spatial

interactions attributed to moderate-/low-energy systems were water spray, flooding, and

falling of piping components onto safety-related components. Furthermore, the applicant

stated that portions of low-/moderate-energy pipe located directly over a safety-related

component (active or passive) were included within the scope of license renewal regardless

of the distance separating the two systems. However, the applicant used a separation

criterion of 20 feet when evaluating the potential effects of spray. Therefore, spatial

interactions were considered only for those portions of low- or moderate-energy non-safetyrelated systems separated by less than 20 feet from an active safety-related component. In

reviewing the RAI response, the staff determined that the applicant's primary basis for this

position was the assumption that fluid sprays dissipate over distance, and degradation of

low-or moderate-energy systems would occur gradually over time. The applicant stated that

any early leakage would be detected and corrected by plant personnel through rounds,

inspections, and monitoring of sumps before the aging mechanisms such as corrosion can

have an adverse effect. The applicant used a similar basis for the assumption that early

detection of leakage would prevent long-term degradation of passive components.

Consequently, the applicant assumed that fluid sprays could affect only active components.

The staff concluded that the applicant's basis relied on the assumption that the exposure

duration of a non-safety SSC failure would be limited by early detection of leakage through

operator actions. However, as discussed in a March 21, 2003, letter to NEI regarding staff

comments to proposed industry guidance on 10 CFR 54.4(a)(2) scoping, neither the license

renewal rule nor the associated statements of consideration examine duration of the failure

as a factor in determining whether a non-safety-related SSC should be in scope. Therefore,

the staff determined that the applicant did not provide a sufficient basis for limiting

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consideration of fluid spray interactions to only those non-safety-related SSCs located within

20 feet of an active safety-related SSC. In particular, the staff requires additional

clarification regarding the capability of active and passive safety-related SSCs located

greater than 20 feet from a potehtial spray source to tolerate wetting, the specific operating

experience that was relied upon to determine that it was not credible for fluid sprays to

affect equipment greater than 20 feet from a failure location, specific methods to detect

leakage in normally accessible and inaccessible areas, and justification for use of exposure

duration in limiting the scope of potential failure mechanisms considered during scoping.

This issue was identified as Open Item 2.1-1.

The applicant responded to Open Item 2.1-1 by letters dated April 9,2004 and May 18,

2004 (ADAMS Accession Nos. ML041070456, and ML041480178). In addressing this open

item, the applicant revised the scoping methodology for non-safety-related moderate energy

piping systems that have the potential to interact spatially with safety-related systems.

Specifically, the applicant eliminated the 20 foot separation criterion and credit for the early

detection of leakage that was previously used to exclude certain moderate energy nonsafety-related piping and components from the scope of license renewal. The revised

methodology assumes that all safety-related components, active as well as passive, could

be adversely affected by spray or wetting from a non-safety moderate energy system

located in the same general area of the plant. Therefore, the applicant stated that all

components from moderate energy non-safety-related systems located in the same general

area as a safety-related component (active or passive) would be included within the scope

of license renewal. The applicant defined "General area' as the same floor (elevation) of a

major building with no barrier walls between the fluid source and the safety-related

component. Barrier walls were defined as barriers that form the boundary of a room on the

same elevation of a major building separating the safety-related components from a spray

or leak generated by a non-safety-related component located on the other side of the barrier

wall. The applicant stated that all barrier walls credited for protection of safety-related

components were previously included within the scope of license renewal during structural

scoping and subject to aging management review.

In accordance with the revised methodology, the applicant expanded the license renewal

boundaries of 17 systems previously determined to be within the scope of license renewal

and identified an additional intended function for the main condenser at Quad Cities.

Additionally, the applicant added the following five non-safety-related systems to the scope

of license renewal that were previously excluded from the scope of license renewal:

circulating water (Dresden and Quad Cities), laundry (Dresden), zinc addition (Dresden and

Quad Cities), extraction steam (Quad Cities), and feedwater heater vents and drains (Quad

Cities) . In its May 18, 2004 response to Open Item 2.1-1, the applicant identified LRA

revisions, scoping results changes, and aging management program changes required as a

result of the scoping methodology revision. The staff review of these revised scoping

results and associated aging management programs are described in Sections 2.3 and 3.1

of this report.

On the basis of the above, the staff concludes that the applicant adequately resolved the

issues identified in Open Item 2.1-1. Specifically, the elimination of the 20-foot limitation on

spray interactions, consideration of potential adverse effects for both active and passive

safety-related equipment, and elimination of credit for early detection of leakage adequately

addressed the staff's methodology concerns. Furthermore, the staff determined that the

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applicant's revised methodology considered a reasonable spectrum of potential non-safetyrelated spatial interactions with safety-related equipment. Therefore, the staff concludes

that the revised methodology for scoping non-safety-related equipment provides reasonable

assurance that the applicant considered non-safety-related SSCs whose failure could

prevent satisfactory accomplishment of a safety-related intended function within the scope

of license renewal. On this basis, Open Item 2.1-1 is resolved. Furthermore. the applicant

adequately resolved the staff concerns raised in RAI 2.1-2.b; therefore, RAI 2.1-2.b is

resolved.

(c) Section 2.1.2.2 of the LRA states that pipe whip, jet impingement, general flooding, or spray

of a gas were not considered credible interactions for gas systems to adversely affect

safety-related SSCs. In LRTI-16, Table 2, Item 3 states, "while falling equipment from gas

systems can spatially impact safety-related components located below them, the only

credible manner in which equipment can fall is through failure of the attached supports."

The staff position described in the letter dated March 15, 2003 is that applicant should not

consider hypothetical failures, but rather should base their evaluation on the plant's CLB,

engineering judgment and analyses, and relevant operating experience. The staff

requested that the applicant describe the scoping methodology implemented for the

evaluation of the 10 CFR 54.4(a)(2) criteria, including a description of the site and industry

operating experience used, as it relates to the non-fluid-filled SSCs of interest and its

consistency with the staff position documented in the staff's letter dated March 15, 2003.

In its October 3, 2003, response to RAI 2.1-2.c, the applicant stated that pipe whip, jet

impingement, general flooding, or spray of a gas were not considered credible interactions

for non-safety-related gas systems to adversely affect safety-related SSCs. The applicant's

basis for this assumption was that gas systems contain no fluids that could spray or leak

onto safety-related systems causing shorts or other malfunctions and gas systems do not

contain sufficient energy to cause pipe whip or jet impingement. Additionally, the applicant

considered that the falling of gas-filled pipe components onto safety-related equipment was

not a credible spatial interaction unless the attached piping supports were to fail. This latter

assumption was based on an operating experience review that included a review of NRC

information notices, NRC Office of Inspection and Enforcement (IE) bulletins, generic

letters, and plant-specific condition reports, work order history, and self assessments. The

applicant stated that no instances of gas-filled piping or component degradation resulting in

the falling of components were identified. For this reason, the applicant stated that the pipe

supports for gas systems were included within the scope of license renewal, but the gas

system piping and valves were not included in the scope of license renewal. The staff

determined that the applicant performed a sufficient operating experience review to

determine credible spatial effects between non-safety-related gas-filled systems and safetyrelated SSCs. Therefore, the staff concluded that the applicant's scoping approach for gasfilled systems was reasonable and RAI 2.1-2.c is resolved.

(d) As described in the staff's letter dated March 15, 2003, if an applicant uses a mitigative

option when performing the scoping of non-safety-related SSCs under 10 CFR 54.4(a)(2),

the applicant should demonstrate that plant mitigative features are adequate to protect

safety-related SSCs from non-safety-related SSC failures, regardless of failure location. If

an applicant cannot demonstrate that the mitigative features are adequate to protect safetyrelated SSCs from the consequences of non-safety-related SSC failures, then the entire

non-safety-related SSCs is required to be brought into the scope of license renewal.

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In reviewing the LRA, the NRC staff was unable to determine if the 10 CFR 54.4(a)(2)

scoping methodology considered failures at all piping locations where age-related

degradation is possible. The staff requested the applicant to clarify how the scoping

methodology of non-safety-related piping was performed relative to the guidance contained

in the staff's letter dated March 15, 2003.

In its October 3, 2003, response to RAI 2.1-2.d, the applicant stated that plant mitigative

features were not credited with protecting safety-related SSCs from failures of non-safetyrelated SSCs. Those portions of non-safety-related SSCs that could spatially or structurally

interact with a safety-related SSCs in such a manner that would prevent the

accomplishment of a safety-related SSCs intended function were included within the scope

of license renewal. Based on this response, the staff concluded that the applicant

considered an adequate scope of non-safety-related SSC failure locations during license

renewal scoping and RAI 2.1-2.d is resolved.

(e) In discussions with the applicant's license renewal project team,- the NRC staff noted some

cases where non-safety-related plant equipment was credited with 'providing anchorage for

non-safety-related piping that was attached to safety-related piping. In these cases,' the

non-safety-related piping was placed within the scope of license renewal, but the plant

equipment providing structural support was not considered to be within scope. For cases in

which an entire pipe run including both safety- and non-safety-related piping was analyzed

as part of the CLB to establish that it could withstand design-basis event loads,

NUREG-1 800, Section 2.1.3.1.2, indicates that the scoping'methodology includes (1) the

non-safety-related piping up to its anchors and (2) the associated piping anchors as being

within the scope of license renewal under 10 CFR 54.4(a)(2). Because the plant equipment

credited with providing support to non-safety-related piping within the scope of license

renewal appears to be equivalent to an associated piping anchor as described in

NUREG-1 800, the staff requested the applicant to provide justification for not including this

plant equipment within the scope of license renewal in RAI 2.1-2.e.

In its October 3, 2003, response to RAI 2.1-2.e, the applicant stated that it conservatively

included those portions of non-safety-related pipe up to the point where the pipe was

restrained in three orthogonal directions. The scoping boundary was determined through a

review of isometric pipe drawings. In those instances where isometric drawings of nonsafety-related pipe did not exist (typically small bore pipe less than 2.5 in. in diameter), the

applicant either included the entire line up to the end of the pipe run (e.g., no more pipe

existed) or ended the boundary where the line attached to a larger piping header or a major

component (i.e., pump or heat exchanger). The larger piping header or major component

was treated as an anchor. However, the applicant stated that the major component was

excluded from the scope of license renewal because all pipe supports installed in the plant

were included within the scope of license renewal. '

The staff determined that the applicant did not provide a sufficient basis for excluding major

components credited with providing a pipe support function from the scope of license

renewal. The staff concluded that major components that ensure satisfactory

accomplishment of a safety-related function by providing support to non-safety-related

piping attached to safety-related systems should be included within the scope of license

renewal. The staff noted that the intended function performed by these major components

is similar to that performed by pipe supports. In a supplement to their RAI 2.1-2.e response

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dated December 22, 2003, the applicant stated that, as a result of further review, these

major components have been added into the scope of license renewal as non-structural

components that provide non-safety-related anchorage. In this supplemental RAI response,

the applicant also provided a listing of specific components added to the scope of license

renewal and identified a new component group for non-structural components providing

non-safety-related anchorage. The staff evaluations of the mechanical system scoping

results and aging management programs associated with the component scoping additions

are described in Sections 2.3.1 and 3.1, of this report. Based on inclusion of non-safetyrelated components credited with providing support to non-safety-related piping attached to

safety-related systems within the scope of license renewal, RAI 2.1-2.e is resolved.

A related non-safety-related piping anchorage issue was identified during the Regional

scoping and screening inspection documented in NRC Inspection Report Nos. 50-237/03-

04(DRS), 50-249/03-04(DRS), 50-254/03-04(DRS), 50-265/03-04 (DRS), dated September

15, 2003. During that inspection, the inspectors questioned the applicant's definition of an

equivalent anchor as used to determine the extent of non-safety-related attached to safetyrelated systems that were included within the scope of the license renewal. Specifically, the

applicant included non-safety-related piping attached to safety-related pipe up to the point

where the non-safety-related piping was restrained in three orthogonal directions. In a letter

dated October 20, 2003, the staff requested the applicant to clarify whether 1his

methodology was consistent with the applicable plant's CLB. Additionally, the staff

requested justification that would demonstrate that failure of the non-safety-related piping

that was potentially excluded from the scope of license renewal would not adversely impact

the safety-related portion of the piping system in accordance with 10 CFR 54.4(a)(2). This

issue is identified as Open Item (50-237/03-04-01; 50-249/03-04-01; 50-254103-04-01; 50-

265/03-04-01).

By a letter dated March 25, 2004 (ADAMS Accession No. ML040900466), the applicant

responded to Open Item 50-237/03-04(DRS); 50-249/03-04(DRS); 50-254/03-04(DRS); 50-

265/03-04 (DRS). In its response, the applicant stated that piping at Dresden and Quad Cities

was designed in accordance with United States of American Standard (USAS) B31.1 Code,

1967 Edition. The applicant noted that the CLB for Dresden and Quad Cities states that the

boundaries of the piping system model used in the original seismic analysis extended well

beyond the stress analysis boundaries set by the first normally closed valves. However, the

CLB does not provide any detail concerning how much of the non-safety-related piping beyond

the first normally closed valve was included in the analysis. The applicant stated that it

performed an additional review of CLB documents to determine the criteria used for these

piping analyses. During this review, the applicant identified several isometric drawings used in

response to IE Bulletin No. 79-14, "Seismic Analyses for As-Built Safety-Related Piping

Systems," which indicated the extent to which the piping analyses included non-safety-related

piping. The applicant determined that the isometric drawings imply that the piping analyses

most likely included two levels of support in each orthogonal direction on the non-safety-related

portion of the piping.

Based on the CLB information supporting the Bulletin 79-14 evaluations, the applicant

indicated that the scoping boundary for non-safety-related piping attached to safety-related

equipment should have been extended up to and including two levels of support in each of

the three orthogonal directions. Therefore, the applicant reviewed license renewal system

boundary diagrams and piping isometrics to determine which non-safety-related piping

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license renewal boundaries needed to be expanded to encompass this degree of restraint.

For non-safety-related piping attached to large bore (10 in. or larger) safety-related pipe, the

applicant license renewal boundary expanded for several systems, including: condensate

and condensate storage (Dresden), high pressure coolant injection (Dresden and Quad

Cities), reactor building closed water cooling (Quad Cities), residual heat removal (Quad

Cities), service water (Quad Cities), and reactor recirculation (Quad Cities). For small bore

* pipe, the applicant stated that the original scoping of piping less than 10 inches in diameter

typically included the entire line. However, the applicant identified some additional nonsafety-related small bore piping which needed to be added to the scope of license renewal

as a result of this effort, including piping in the following systems: reactor building closed

cooling water (Dresden), isolation condenser (Dresden), nuclear boiler instrumentation

(Dresden), control rod drive hydraulic (Dresden and Quad Cities) , high pressure coolant

: injection (Dresden), containment isolation (Dresden and Quad), condensate and

condensate storage (Quad Cities) , diesel generator cooling (Quad Cities), reactor

recirculation (Quad Cities), residual heat removal (Quad Cities), and standby liquid control

(Quad Cities). The applicant determined that the components added to the scope of license

renewal as a result of these additional reviews were comprised of the same material and

environmental combinations as other components previously assessed for aging

management. Consequently, the applicant concluded that no new aging management

programs were required. However, because the applicant identified certain component

types that had not been previously identified in the scoping results described in the LRA, the

applicant revised certain LRA Chapter 2 aging management review tables. In their

response, the applicant provided a summary of the necessary revisions to the affected

tables. The staff review of the additional equipment added to the scope of license renewal

and the associated aging management programs are discussed in Sections 2.1 and 3.1 of

this report.

On the basis of its review, the staff finds that the applicant's method as described above is

reasonable and acceptable because the applicant's response to IE Bulletin 79-14 verified

that the actual configuration of the piping systems meets the design requirements, and the

staff has previously reviewed the response and found it acceptable. As documented in

NRC Inspection Report 50-237/83-23; 50-249/83-20; 50-254/83-22; 50-265/83-21, dated

September 9, 1983 (ADAMS Accession No. 8309210296), the NRC staff previously

concluded that all pertinent issues and findings relative to IE Bulletin 79-14 had been

resolved. Therefore, the staff concludes that the extension of the license renewal scoping

boundary to two levels of support in each orthogonal direction beyond the safety-non-safety

interface provides reasonable assurance that the safety-related portion of piping could

withstand design basis event loads. As such, the staff concludes that the applicant's

revised scoping methodology for non-safety-related piping attached to safety-related

systems is consistent with NUREG-1800 and the staff expectations of the December 3< and

March 15i letters. Therefore, Open Item (50-237/03-04-01; 50-249/03-04-01; 50-254/03-

04-01; 50-265/03-04-01) is resolved.

In reviewing the LRA description of non-safety-related scoping, the staff noted that the

subsection entitled "Hypothetical Failures and Cascading," located within LRA Section 2.1.6,

indicates that only hypothetical failures described in the CLB were considered during SSCs

scoping. With regard to failures that should be considered during 10 CFR 54.4(a)(2) scoping,

NUREG-1800, Section 2.1.3.1.2, "Non-safety-Related," states the following:

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The applicant must identify those non-safely-related SSCs (including certain second-, third-, or

fourth-level support systems) whose failures are considered in the CLB and could prevent the

satisfactory accomplishment of the safety-related function identified under 10 CFR 54.4(a)( 1). In order

to identify such systems, the applicant should consider those failures identified in (1) the

documentation that makes up its CLB, (2) plant-specific operating experience, and (3) industry wide

operating experience that is specifically applicable to its facility.

The NRC staff noted that consideration of only hypothetical failures described in the CLB may

result in the failure to consider failures identified in plant-specific and industry wide operating

experience. Therefore, in RAI 2.1-11, the staff requested the applicant to describe the intent of

this statement in the LRA and to discuss how the scoping process considered failures identified

in the CLB and plant-specific and industry wide operating experience that is applicable to the

Dresden and Quad Cities facilities in a manner consistent with the guidance contained in

NUREG-1 800.

In its October 3, 2003, response to RAI 2.1-11, the applicant provided additional information

regarding its treatment of hypothetical failures during scoping. The applicant stated that

instruction GE-NE-LRTI-2000 requires the person performing the scoping review for each

system or structure to identify information found in CLB documents and to list this information

on the system or structure scoping form. The applicant stated that this process provides

reasonable assurance that any CLB requirements dealing with the scoping criteria in

10 CFR 54.4(a)(2) are identified in the scoping process. With respect to credible failures

identified in plant-specific and industry wide operating experience, the applicant stated that

plant-specific and industry wide operating experience was not specifically reviewed during the

scoping process in preparation of the Dresden and Quad Cities LRA. The applicant based this

position on the existence of routine Exelon practices for review of operating experience which

include an assessment to determine if non-safety-related equipment failures prevented a

safety-related function from occurring. The applicant stated these practices would identify

appropriate corrective actions to prevent recurrence of any failure of non-safety-related SSCs

identified through the routine operating experience reviews. Although the staff agrees that the

applicant's scoping methodology would reasonably identify failures considered in the CLB, the

staff lacked sufficient information to conclude that the applicant adequately considered

operating experience in identifying credible failures. In particular, the staff determined that

corrective actions arising from routine operating experience reviews would not necessarily be

effective in preventing recurrence of failures identified in site-specific or industry-wide operating

experience. Further, the corrective actions arising from these reviews may not address the

aging management aspects of the previously experienced failures.

In a supplement to the RAI 2.1-11 response dated December 17, 2003, the applicant clarified

their use of operating experience during the scoping of non-safety-related SSCs. The applicant

stated that an explicit review of operating experience was not conducted during the initial phase

of non-safety-related scoping. However, during the revised non-safety-related scoping phase

conducted following the issuance of additional NRC guidance pertaining to the identification and

the treatment of SSCs which meet 10 CFR 54.4(a)(2), the applicant stated that operating

experience was considered. Specifically, the applicant stated that operating experience items

such as NRC documents (information notices, generic letters, violations, and bulletins), 10 CFR

Part 21 reports, vendor bulletins, and site operating experience reports were considered during

the scoping of non-safety-related SSCs. Based on this supplemental response, the staff

concluded that the applicant considered an adequate scope of operating experience when

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identifying failures that could prevent the satisfactory accomplishment of the safety-related

intended functions. Based on the above, RAI 2.1-11 is resolved.

Based on a review of the LRA and related scoping implementation procedures, discussions with

the applicant, and a sampling of scoping results, the staff determined that the applicant's

methodology for scoping non-safety-related equipment under 10 CFR 54.4(a)(2) adequately

identified those non-safety-related SSCs whose failures could prevent the satisfactory

accomplishment of the safety-related functions identified under 10 CFR 54.4(a)(1). Therefore,

the staff determined that the applicant's methodology for identifying systems and structures

meeting the scoping criteria of 10 CFR 54.4(a)(2) was adequate.

Application of the Scoping Criteria in 10 CFR 54.4(a)(3). In part, 10 CFR 54.4(a)(3) requires

that the applicant consider all SSCs relied on in safety analyses or plant evaluations to perform

a function that demonstrates compliance with the Commission's regulations for fire protection

(10 CFR 50.48), environmental qualification (10 CFR 50.49), pressurized thermal shock

(10 CFR 50.61), anticipated transients without scram (10 CFR 50.62), and station blackout

(10 CFR 50.63) to be within the scope of the license renewal. Because the pressurized thermal

shock requirements of 10 CFR 50.61 apply only to pressurized water reactors, the

10 CFR 54.4(a)(3) scoping criteria related to 10 CFR 50.61 are not applicable to the Quad

Cities and Dresden Nuclear Power Stations, which are boiling water reactors.

The applicant's methodology for performing the scoping of SSCs in accordance with

10 CFR 54.4(a)(3) was documented in implementation procedures GE-NE-LRTI-2000 and the

Scoping and Screening Desktop Guide. Additionally, the applicant prepared technical position

papers for each regulated event applicable to the Dresden and Quad Cities Nuclear Power

Stations to support the scoping process.

The applicant performed the initial scoping for regulated events using general screening

checklist questions in Section 4.1.4 of procedure GE-NE-LRTI-2000 to identify if the structure or

system met the scoping criteria of 10 CFR 54.4(a)(3). Section 3 of the Scoping and Screening

Desktop Guide indicated that the GE-NE-LRTI-2000 checklist questions could be answered by

reviewing the technical position papers to determine if a system or structure was relied on to

demonstrate compliance with any of the regulated events listed in 10 CFR 54.4(a)(3). During

the scoping and screening methodology audit, the applicant stated that use of the position

papers ensured consistent scoping results and eliminated the need to review CLB documents

when evaluating each plant structure or system against the 10 CFR 54.4(a)(3) scoping criteria.

The staff noted that Section 2.1.3.5 of the LRA identified technical position papers as a

documentation source for license renewal scoping under 10 CFR 54.4(a)(3). However, in

reviewing the LRA and scoping and screening implementation procedures, the NRC staff was

unable to determine the extent that the CLB was reviewed during position paper development.

NUREG-1800, Section 2.1.3.1.3, "Regulated Events," states that all SSCs that are relied upon

in the plant's CLB, plant-specific experience, industry wide experience (as appropriate), and

safety analyses or plant evaluations to perform a function that demonstrates compliance with

NRC regulations identified under 10 CFR 54.4(a)(3), are required to be included within the

scope of the rule. Therefore, in RAI 2.1-6, the staff requested the applicant to provide a

description of the methodology used to develop technical position papers and clarification

regarding the process used to identify the SSCs intended functions related to the mitigation of

regulated events.

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In its October 3, 2003, response, the applicant stated that the regulated event position papers

were prepared by engineers who had previous experience with BWR systems and operations.

The preparer reviewed applicable CLB documents to identify systems required in each

regulated event. The applicant noted that position papers also identified system functions

explicitly credited for regulated events. A reviewer, who had not been directly involved in the

preparation of the paper, checked the position paper for accuracy and completeness. After

preparation and review, the position papers were approved by license renewal project

management and issued for use. Position papers were revised using a similar preparationreview-approval process. In its RAI response, the applicant identified supporting CLB

documentation and described an electronic document database used in the development of the

position papers. The staff determined that the scope of documentation reviewed for the

development of the position papers and the control of the position paper development process

were adequate to provide reasonable assurance that the applicant identified SSCs and

associated intended functions for regulated events. Therefore, based on the above, the staff

resolved RAI 2.1-6.

In Section 2.1.6 of the LRA, the applicant stated that when a supporting system or structure

was identified for an intended function that satisfies only criterion 10 CFR 54.4(a) (3), the

scoping process did not require that the supporting function be classified as an intended

function unless a requirement in a CLB document explicitly identifies a requirement for the

supporting function. Per 10 CFR 54.4(a)(3), all SSCs relied on in safety analyses or plant

evaluations to perform a function that demonstrates compliance with specific regulated events

must be within the scope of license renewal. In reviewing the LRA and supporting

implementation procedures, the staff was unable to determine how the applicant's guidance for

scoping support systems to equipment credited for demonstrating compliance with the Section

54.4(a)(3) regulated events was implemented. In particular, the staff questioned if support

functions that were not explicitly identified by a CLB requirement but still required to

demonstrate compliance with a regulated event were considered within the scope of license

renewal. Therefore, in RAI 2.1-9, the staff asked the applicant to describe the intent and basis

for the support function scoping guidance in Section 2.1.6 of the LRA and the extent of CLB

reviews conducted to identify support functions to structures and systems meeting the scoping

criteria of 10 CFR 54.4(a)(3).

In its October 3, 2003, response, the applicant stated that the discussion in LRA Section 2.1.6

should have been written as follows:

When a supporting system or structure was identified for an intended function that satisfies only criterion 10 CFR 54.4(a)(3), the scoping process did not require that the supporting function be

classified as an intended function unless (1) failure of the supporting system or structure is expected

to cause failure of the intended function satisfying criterion 10 CFR 54.4(a)(3), or (2) a requirement

in a current licensing basis documented explicitly identifies a requirement for the supporting function.

The applicant also noted that the scoping process for systems and structures satisfying

10 CFR 54.4(a)(1) through (3) required that any supporting system function be identified as a

license renewal "intended function" if its failure would prevent the supported system from

performing any of its intended functions. The review to identify support functions of SSCs

within the scope of license renewal consisted of reviewing the UFSARs, system design-basis

documents, system operating description documents (operator lesson plans and procedures),

and, where necessary, engineering drawings related to the system to identify interfaces with

2-28
other systems and any required support provided by the interfacing system. Based on this

review, the applicant stated that critical supporting functions, such as those provided by power

supplies or required cooling water subsystems, were identified. The supporting functions were

classified as license renewal intended functions if their failure was expected to cause failure of

a supported intended function. The staff determined that the applicant's approach to scoping of

support systems adequately ensured that all SSCs relied on in safety analyses or plant

evaluations to perform a function that demonstrates compliance with regulated events would be

included within the scope of license renewal. Therefore, the staff resolved RAI 2.1-9.

In an April 1, 2002, letter from Mr. D. Matthews to Mr. A. Nelson and Mr. D. Lochbaum, the staff

provided guidance on the scoping of equipment relied on to meet the requirements off the

station blackout (SBO) rule, 10 CFR 50.63. In this letter, the staff noted that, consistent with

the requirements specified in 10 CFR 54.4(a)(3) and 10 CFR 50.63(a)(1), the plant system

portion of the offsite power system that is used to connect the plant to the offsite power source

should be included within the scope of the rule. In Section 2.1.3.5 of the LRA, the applicant

stated that the SBO technical position papers include structures and components of the offsite

power system for each plant required to restore power from the onsite switchyard down to the

safety-related busses in the plant. Furthermore, the applicant stated that the plant offsite power

system and these structures and components were classified as satisfying criteria

10 CFR 54.4(a)(3) and were included within the scope of license renewal. The staff determined

that the applicant's approach to scoping SSCs relied on to demonstrate compliance with the

SBO rule (10 CFR 50.63) was consistent with the staff's April 1,2002, interim guidance.

As part of the evaluation of the applicant's scoping methodology, the audit team reviewed a

sample of the LR database 10 CFR 54.4(a)(3) scoping results to assess the adequacy of the

applicant's scoping methodology. The staff verified that the applicant's scoping methodology

identified and used pertinent engineering and licensing information in order to determine the

SSCs required to be in scope in accordance with the 10 CFR 54.4(a)(3) criteria. Therefore, the

staff determined that the applicant's methodology for identifying systems and structures

meeting the scoping criteria of 10 CFR 54.4(a)(3) was adequate.

2.1.3.1.3 Plant-Level Scoping of Systems and Structures

The applicant performed the scoping of systems and structures in accordance with

implementation procedures GE-NE-LRTI-2000 and the Scoping and Screening Desktop Guide.

Procedure GE-NE-LRTI-2000 specified that the personnel performing scoping use CLB

documents and list all functions that the system or structure is required to accomplish. System

or structure functions were then compared to a list of scoping screening questions contained in

Section 4.1.4 of GE-NE-LRTI-2000 to determine whether the functions met the scoping criteria

of 10 CFR 54.4(a). Systems or structures with functions meeting one or more of the screening

criteria were considered to be within the scope of license renewal. The staff reviewed the

screening questions and concluded that the screening questions were consistent with the

requirements of 10 CFR 54.4(a).

The applicant documented the results of the plant-level scoping process in accordance with

GE-NE-LRTI-2000, Exhibit A, 'License Renewal System and Structure Scoping Form." The

scoping form included a description of the structure or system, a listing of functions performed

by the system or structure, information pertaining to system realignment (as applicable),

identification of intended functions, the 10 CFR 54.4(a) scoping criteria met by the system or

2-29
. I

structure, references, and identification of support systems. During the scoping methodology

audit, the staff reviewed a sampling of scoping reports and concluded that the applicant's

scoping forms contained an appropriate level of detail to document the scoping process.

Based on a review of the LRA, the scoping and screening implementation procedures, and a

sampling review of system and structure scoping results during the methodology audit, the staff

concluded that the applicant's scoping methodology for systems and structures was adequate.

In particular, the staff determined that the applicant's methodology reasonably identified

systems and structures within the scope of license renewal and their associated intended

functions. Additionally, the applicant's approach to system and structure scoping was

consistent with the methodology described in Section 2.1.4 of the LRA.

2.1.3.1.4 Component-Level Scoping

After the applicant identified systems and structures within the scope of licensee renewal and

their associated intended functions, a review was performed to identify the components of each

in-scope system and structure that supported an intended function. As described in

Section 2.1.4.1 of the LRA, a component was determined to be in scope if it was safety-related,

meeting the criteria of 10 CFR 54.4(a)(1); if it was determined that the component was needed

to fulfill a system intended function; if the component met the criteria of 10 CFR 54.4(a)(2); or if

the component was needed to demonstrate compliance with a regulated event.

To facilitate the scoping and screening process and AMRs, the applicant realigned certain

components from their actual parent system to a different LR system. Attachment 1 of

GE-NE-LRTI-2000 described the process used by the applicant to realign components from one

system to another for the purposes of LR scoping. This guidance allowed alignment of

components to a system more closely associated with their intended functions when all but a

few components in the parent system were outside the scope of license renewal. Component

realignment was intended to allow components to be evaluated as a coherent functional group

within an appropriate system or commodity group. The implementation procedure included

documentation requirements to permit traceability of components that were realigned from one

parent system to a different LR system. During the scoping and screening methodology audit,

the staff reviewed the implementation of this component realignment guidance and determined

that the realignment process did not adversely impact component-level scoping and screening.

Mechanical Component Scovina. Section 4.3, "Scoping and Screening of System

Components," of GE-NE-LRTI-2000 provided the applicant's proceduralized guidance for

scoping mechanical system components. The applicant initially generated a listing of

mechanical system components based on information contained in the EWCS database. This

information was augmented by a review of the system LR boundary diagram to identify system

components not included in the EWCS database or generic components such as piping and

tubing that were applicable to the system. Following identification of all system components,

the applicant used the LR boundary diagrams as an aid to evaluate each component against

the scoping criteria of 10 CFR 54.4(a). System components meeting the criteria of

10 CFR 54.4(a) were classified as within the scope of license renewal.

The applicant provided guidance for the scoping of equipment insulation in Section 9.7 of the

Scoping and Screening Desktop Guide and position paper PP-QDC-DRE- Revision 00 IN.

Based on information contained in the insulated line list specification for each plant site, the

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applicant determined which piping system had insulation installed.%. For each pipe system with

installed insulation, the applicant created a generic insulation component in the system

component list. The generic insulation component was then realigned to the generic insulation

system, which is described in LRA Section 2.4.16, Insulation Commodity Group." The

applicant stated that all insulation was initially considered within the scope of license renewal

but that the scoping classification could be revised based on further evaluation of its design

function during an aging management review.

During the scoping and screening methodology audit, the staff reviewed a sampling of scoping

results to verify that the applicant's proceduralized methodology was adequately implemented.

In performing this review, the staff noted a potential inconsistency in the scoping results for the

refueling equipment system and the applicant's mechanical system scoping methodology. LRA

Section 2.3.3.1, "Refueling Equipment," identified two system-level intended functions for the

refueling equipment system-(1) maintain structural integrity to prevent collapse of the platform

onto the spent fuel storage racks or the reactor core and (2) provide interlocks to preclude

inadvertent criticality. LRA Table 2.3.3-1, "Component Groups Requiring Aging Management

Review-Refueling Equipment System," identified the spent fuel gates as requiring aging

management to maintain a 'pressure boundary" component-level intended function. Based on

a review of LRA Section 2.3.3.1, the NRC staff was unable to determine how the pressure

boundary component-level function for the spent fuel pool gates supported either of the

refueling equipment system-level intended functions in a manner consistent with the component

scoping methodology described in Section 2.1.4.1 of the LRA. In RAI 2.1-10, the staff

requested that the applicant describe how the scoping methodology was implemented to

identify the need for spent fuel gate pressure boundary integrity to support the specified

refueling equipment system intended functions. The staff did not identify additional

inconsistencies during the mechanical scoping results review.

In its October 3, 2003, response to RAI 2.1-10, the applicant stated that component intended

function for the spent fuel pool gates was properly classified as pressure boundary and properly

evaluated for aging management. The gates were included in the refueling equipment system

because the original equipment supplier included them in the list of refueling equipment

provided to the station. After further review, the applicant has stated that it would have been

more appropriate to place the fuel pool gates, with pressure boundary intended function, into

the Reactor Building system, along with the fuel pool structure. However, the staff concluded

that the appropriate intended function of the spent fuel pool gates was identified by the

applicant's scoping process, and evaluation of the spent fuel pool gate with the refueling

equipment system rather than the reactor building system was an isolated example and did not

indicate a significant deficiency in the implementation of the scoping methodology.

Consequently, the staff resolved RAI 2.1-10.

The staff determined that the applicant's proceduralized methodology was consistent with the

description provided in Section 2.1.4.1 of the LRA and the guidance contained in NUREG-1 800,

Section 2.1, and was adequately implemented. After reviewing the applicant's detailed scoping

implementation procedures and a sample of the mechanical components scoping results, the

staff concluded the applicant's methodology for identifying mechanical components within the

scope of license renewal met the requirements of 10 CFR 54.4(a).

Structural Component Scoping. Section 4.2, "Scoping and Screening of Structural

Components," of GE-NE-LRTI-2000 provided the applicant's proceduralized guidance for

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scoping structural components. For all structures within the scope of license renewal, the

applicant stated that an initial listing of structural components was generated based on

information derived from the EWCS database. Because the EWCS does not identify all

components within a given structure, the applicant augmented the component list with generic

component types applicable to the structure. In Section 2.1.4.3 of the LRA, the applicant stated

that detailed structural drawings and, where needed, walkdowns were performed to identify

structural elements. Generic structural component types were selected from Table 5, "Generic

Structural and Mechanical System Components," of GE-NE-LRTI-2000. The staff compared

the applicant's generic structural component listing to the typical structural commodity groups

identified in Table 2.1-5 of NUREG-1800 and concluded that the applicant's general structural

component list was reasonable. Following identification of all system components, the applicant

evaluated each component against the scoping criteria of 10 CFR 54.4(a). Structural

components meeting the criteria of 10 CFR 54.4(a) were classified as within the scope of

license renewal.

The staff determined that the applicant's proceduralized methodology was consistent with the

description provided in Section 2.1.4.3 of the LRA and the guidance contained in NUREG-1 800,

Section 2.1. Based on review of information contained in the LRA, the applicant's detailed

scoping implementation procedures, and a sample of the structural component scoping results,

the staff concluded that the applicant's methodology for identifying structural components within

the scope of license renewal met the requirements of 10 CFR 54.4(a).

Electrical and l&C Component Scopina. The applicant's methodology for scoping electrical and

l&C components was described in technical position paper PP-DRE-QDC Revision 01

SPACES, "Scoping and Screening Position Paper for Electrical Components based on

Electrical Spaces Approach for Aging Management Review." The electrical scoping

methodology initially identified every electrical component as within the scope of license

renewal. However, Section 3.0.3 of PP-DRE-QDC Revision 01 SPACES allowed exclusion of

electrical components "which are clearly in systems which are not in the license renewal scope,

or which are determined by other means to be outside license renewal scope" from the scope of

license renewal. During the scoping and screening methodology audit, the applicant's LR

project team indicated that electrical components located within certain plant spaces were

excluded from LR scope, in addition to some electrical components that did not perform an

intended function. Based on a review of the LRA and scoping implementation procedure

PP-DRE-QDC Revision 01 SPACES, the NRC staff was unable to determine the applicant's

basis for generically excluding electrical and l&C components in certain plant spaces from the

scope of license renewal or the specific methods used to determine that an electrical or l&C

component was otherwise not within the scope of license renewal.

Section 2.5.3.1, "Components Within the Scope of License Renewal," of NUREG-1800 states

that an applicant may use the plant spaces approach in scoping electrical and l&C components.

In the plant spaces approach, an applicant may indicate that all electrical and l&C components

located within a particular area are either within or not within the scope of license renewal. In

NUREG-1800, Table 2.5-1, "Examples of 'Plant Spaces' Approach for Electrical and l&C

Scoping and Corresponding Review Procedures," provides guidance for the review of scoping

performed in accordance with the plant spaces approach. In particular, if the applicant limits

the scope of electrical and l&C components considered within the scope of license renewal by

excluding components in certain plant spaces, Table 2.5-1 indicates that this approach should

not result in failing to place electrical and l&C components that perform intended functions

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within the scope of license renewaI. Because the staff was unabie to determine the applicant's

specific basis for excluding certain electrical and l&C components from the scope of license

renewal, the staff was unable to evaluate the applicant's electrical spaces approach against the

guidance in NUREG-1800. Therefore, to support the staff review of the implementation of the

electrical spaces approach, in RAI 2.1-13, the staff requested the applicant to describe the

methodology used to exclude electrical equipment located within certain plant spaces from the

scope of license renewal.

In its October 3, 2003, response, the applicant stated that all electrical cables and components

were considered in the scope of license renewal. The radwaste building, which did not contain

any electrical components within the scope of license renewal, was the only space where the

electrical components were generically excluded based on location. All electrical systems were

evaluated to determine if the system intended functions met the requirements of 10 CFR

54.4(a)(1) through (a)(3). Electrical components, except for cables, that were clearly in

systems not in the scope of 10 CFR 54.4(a)(1) through (a)(3) were flagged as not in the scope

of license renewal. The remaining electrical components and all of the cables were flagged as

being in the scope of license renewal and assigned component intended functions. During the

AMR process, the applicant determined that certain cables and components were not safetyrelated; that failure of these cables or components would not prevent satisfactory

accomplishment of any of the intended functions identified in 10 CFR 54.4(a)(1)(i), (ii), or (iii);

and that these cables and components performed no functions that demonstrates compliance

with fire protection, environmental qualification, anticipated transients without scram, or SBO.

Therefore, these cables and components were removed from the scope of license renewal. In

reviewing the response to RAI 2.1-13, the staff concluded that the applicant identified an

appropriate basis for excluding certain electrical and l&C components from the scope of license

renewal. In particular, the staff concluded that the applicant's implementation of the electrical

spaces approach provided reasonable assurance that electrical and l&C components that

perform intended functions were within the scope of license renewal. Therefore, the staff

resolved RAI 2.1-13.

The staff determined that the implementation of the electrical spaces method for scoping of

electrical and l&C components was consistent with the guidance contained in NUREG-1800.

Because the applicant's use of the electrical spaces approach integrated the scoping and

screening phases of the methodology, additional conclusions regarding the use of this method

are discussed in Section 2.1.3.2.3 of this report.

2.1.3.2 Screening Methodology

The staff reviewed the screening methodology used by the applicant to determine if

mechanical, structural, and electrical components within the scope of license renewal would be

subject to further aging management evaluation. The applicant described its screening process

in Section 2.1.5 of the LRA. In general, the applicant's screening approach consisted of

evaluations to determine which in-scope structures and components were passive and longlived. Passive, long-lived structures and components were then subject to an AMR.

The staff evaluated the applicant's screening methodology against the criteria contained in

10 CFR 54.21(a)(1) and (a)(2) using the review guidance contained in NUREG-1800,

Section 2.1.3.2, "Screening." According to 10 CFR 54.21(a)(1), the applicant's integrated plant

assessment must identify and list those structures and components subject to an AMR.

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Further, 10 CFR 54.21 (a)(1) requires that structures and components subject to an AMR shall

encompass those structures and components that (1) perform an intended function, as

described in Section 54.4, without moving parts or a change in configuration or properties and

(2) are not subject to replacement based on a qualified life or specified time period. Per

10 CFR 54.21 (a)(2), the applicant must describe and justify the methods used to meet the

requirements of 10 CFR 54.21 (a)(1). In the LRA, the applicant described screening

methodologies that were unique to the mechanical, structural, and electrical disciplines. The

staff evaluation of the applicant's screening approach for each of these disciplines is described

below.

2.1.3.2.1 Mechanical Component Screening

The applicant provided procedural guidance for the conduct of mechanical component

screening in Section 4.3 of procedure GE-NE-LRTI-2000, position paper

PP-DRE-QDC Revision 02-AP, and the Scoping and Screening Desktop Guide. For each

mechanical system component determined to be within the scope of license renewal, the

applicant identified if the component was active or passive. The classification of a component

as either active or passive was based on an active/passive classification component table

provided in position paper PP-DRE-QDC Revision 02-AP. In discussions with the applicant

during the scoping and screening methodology audit, the staff determined that the component

types and active/passive classifications provided in PP-DRE-QDC Revision 02-AP were based

on Revision 2 to NEI 95-10, rather than the NRC-endorsed Revision 3. As discussed in Section

2.1.3.1.1 of this SER, the staff evaluated the applicant's use of Revision 2 to NEI 95-10 and

determined that the use of the earlier revision did not adversely impact the screening process.

After a component was classified as passive, the applicant identified the associated passive

component intended functions. The applicant selected component passive intended functions

from Table 6, "Passive Component Intended Functions," of GE-NE-LRTI-2000. The staff

reviewed the passive intended functions described in Table 6 and determined that the functions

were consistent with those described in NUREG-1 800, Table 2.1-3, "Typical 'Passive' Structure

and Component Intended Functions."

Following classification of an in-scope mechanical system component as passive and

identification of the component intended functions, the applicant determined if the component

was long-lived. Scoping and screening procedure GE-NE-LRTI-2000, Section 4.3.8, and

Table 7, "Short Lived Components Not Requiring Aging Management," provided guidance for

determining if a component was long-lived. Specifically, GE-NE-LRTI-2000 Table 7 listed

general component types, including consumable items, that did not require an AMR because

they were considered to be short-lived. Section 4.3.9 of GE-NE-LRTI-2000 required that all

passive, long-lived mechanical system components within the scope of license renewal be

subject to an AMR.

In reviewing the LRA and GE-NE-LRTI-2000, the staff was unable to determine the basis for

considering some of the components listed in Table 7 to be short-lived and therefore not

subject to an AMR. As discussed in NUREG-1800, Table 2.1-3, 'Specific Staff Guidance on

Screening," states that the applicant should identify the standards that are relied on for

replacement of consumables that are not subject to an AMR as part of the methodology

description. For consumables such as packing, gaskets, component seals, and O-rings, Table

2.1-3 of NUREG-1800 states that these components may be excluded from an AMR using a

clear basis. For consumables such as system filters, fire extinguishers, fire hoses, and air

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packs, the applicant should identify the standards relied on for replacement as part of the

methodology description. Therefore, in RAI 2.1-12, the staff asked the applicant to justify its

determination that the component is not subject to an AMR for each of the component types

listed in Table 7.

In its October 3, 2003, response to RAI 2.1-12, the applicant provided a justification for each

component type listed in Table 7 of GE-NE-LRTI-2000 that is not subject to an AMR.

Additionally, the applicant noted that flexible hoses should not have been listed in Table 7.

Flexible hoses may be either short-lived or long-lived, depending on whether they are

periodically replaced as part of preventative maintenance. The applicant stated that it had

recognized the need to revise Table 7 during the transition from the scoping and screening

phase to the AMR phase of the integrated plant evaluation. At that time, any in-scope flexible

hoses that had been categorized as "short-lived" were re-screened as 'long-lived" and were

carried forward for AMR. During AMR, flexible hoses screened as long-lived" could be

re-categorized as ushort-lived" and excluded from further evaluation provided that a basis for

re-categorizing them as Tshort-lived" was identified and documented in the component

comment field of the LR database. In its response, the applicant also identified the AMPs

credited with managing the effects of aging for long-lived flexible hoses. The staff determined

that the applicant provided a sufficient justification for excluding the component types listed in

Table 7 of GE-NE-LRTI-2000, other than flexible hoses, from an AMR. Additionally, the

applicant described a reasonable process for the classification of flexible hoses as either shortlived and subject to periodic replacement or long-lived and subject to an AMP. Therefore, on

this basis, the staff resolved RAI 2.1-12.

In a May 1, 2002, letter from Dr. P.T. Kuo to Mr. A; Nelson and Mr. D. Lochbaum, the staff

provided guidance on the identification and treatment of housings for active components for LR

scoping and screening. As discussed in this letter, the staff expects applicants for license

renewal to identify active component housings (e.g., housings for fans, dampers, and heating

and cooling coils) which require an AMR. This determination should consider whether failure of

the housing would result in a failure of the associated active component to perform its function,

and whether the housing meets the long-lived and passive criteria as defined in the Rule.

During the scoping and screening methodology audit, the applicant stated that this guidance

was incorporated into the AMR process. Additionally, the applicant provided several examples

where housings of active components were identified as requiring an AMR. These include

housings located in the standby gas treatment system (SBGTS); emergency diesel generator

(EDG) and auxiliaries; and heating, ventilation, and air conditioning (HVAC)-reactor building.

Based on this information, the staff concluded that the applicant appropriately considered the

housings of active components in its scoping and screening methodology.

Based on the preceding, the staff determined that the applicant's screening methodology was

consistent with the guidance contained in NUREG-1 800 and was capable of identifying passive,

long-lived components within the scope of license renewal that are subject to an AMR.

2.1.3.2.2 Structural Component Screening

The applicant provided procedural guidance for the conduct of structural component screening

in Section 4.2 of procedure GE-NE-LRTI-2000, position paper PP-DRE-QDC Revision 02-AP,

and the Scoping and Screening Desktop Guide. For each structural component determined to

be within the scope of license renewal, the applicant identified if the component was active or

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passive. The classification of a component as either active or passive was based on an

active/passive classification component table provided in position paper

PP-DRE-QDC Revision 02-AP. In addition to the use of the active/passive classification table,

Section 4.2.5 of GE-NE-LRTI-2000 stated that the distinct structural features (components) that

constitute a structure were considered passive. After a structural component was classified as

passive, the applicant identified the related passive structure intended functions. The applicant

selected component passive intended functions from Table 6, "Passive Component Intended

Functions," of GE-NE-LRTI-2000. The staff reviewed the passive intended functions described

in Table 6 and determined that the functions were consistent with those described in NUREG1800, Table 2.1-3, "Typical 'Passive' Structure and Component Intended Functions."

Following classification of an in-scope structural component as passive and identification of the

component intended functions, the applicant determined if the component was long-lived.

Scoping and screening procedure GE-NE-LRTI-2000, Section 4.2.7 and Table 7, provided

guidance for determining if a structural component was long-lived. Specifically,

GE-NE-LRTI-2000 Table 7 listed general component types, including consumable items, that

did not require an AMR because they were considered to be short-lived. As discussed in

Section 2.1.3.2.1 above, the staff evaluated the applicant's classification of certain generic

component types in GE-NE-LRTI-2000 and concluded that the applicant's approach was

adequate. Section 4.2.8 of GE-NE-LRTI-2000 required that all passive, long-lived structural

components within the scope of license renewal be subject to an AMR.

The staff determined that the applicant's structural component screening methodology was

consistent with the guidance contained in NUREG-1800 and was capable of identifying those

passive, long-lived components within the scope of license renewal that are subject to an AMR.

2.1.3.2.3 Electrical and l&C Component Screening

As described in Section 2.1.3.1.3 of this SER, the applicant used a plant spaces approach for

electrical and l&C scoping and screening. Therefore, the applicant screened electrical and l&C

components on a plant-wide basis rather than on a system basis. The applicant described the

electrical and l&C screening methodology in Section 2.1.4.2 of the LRA and position paper

PP-DRE-QDC Revision 01-SPACES. Although the applicant initially considered all electrical

components to be within the scope of license renewal, the scoping and screening methodology

allowed electrical and l&C components to be removed from scope. As described in Section

2.1.3.1.3 of this report, the staff requested the applicant to provide additional information

regarding the application of the electrical spaces approach with regard to removing electrical

equipment from scope. For each electrical component within the scope of license renewal, the

applicant determined if the component was active or passive based on component

classifications listed in Attachment 1 to position paper PP-DRE-QDC Revision 01-SPACES. In

discussions with the applicant during the scoping and screening methodology audit, the staff

determined that the component types and active/passive classifications provided in

PP-DRE-QDC Revision 01-SPACES were based on Revision 2 to NEI 95-10, rather than on the

NRC-endorsed Revision 3. As discussed in SER Section 2.1.3.1.1 above, the staff evaluated

the applicant's use of Revision 2 to NEI 95-10 and determined that the use of the earlier

revision did not adversely impact the screening process. Following identification of passive

electrical and l&C electrical components, for each component the applicant identified if the

component was long-lived. Passive, long-lived electrical and l&C components within the scope

of license renewal were then subject to an AMR. In Section 2.5 of the LRA, the applicant

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identified electrical and l&C commodity groups subject to an AMR, including (1) cables and

connections (splices, connectors, fuse blocks, and terminal blocks), (2) bus ducts, (3) highvoltage transmission conductors and insulators, and (4) electrical penetrations. The staff

determined that the applicant's selection of electrical and l&C commodity groupings was

consistent with NUREG-1800.

The staff also reviewed the applicant's approach to scoping and screening of electrical fuse

holders. In license renewal ISG-5, 'Identification and Treatment of Electrical Fuse Holders for

License Renewal," dated March 10, 2003, the staff stated that, consistent with the requirements

specified in 10 CFR 54.4(a), fuse holders (including fuse clips and fuse blocks) are considered

to be passive electrical components. Fuse holders would be scoped, screened, and included in

the AMR in the same manner as terminal blocks and other types of electrical connections that

are currently being treated in the process. This staff position applies only to fuse holders that

are not part of a larger assembly, but support safety-related and non-safety-related functions in

which the failure of a fuse holder precludes an intended function from being accomplished. As

described in LRA Section 2.5.1.1, "Cables and Connections," all electrical insulated cables and

connections, including fuse blocks, were evaluated for aging management using the uspaces"

approach. The staff noted that technical position paper PP-DRE-QDC Revision 02-AP

identified fuse holders and fuse blocks as passive components supporting the intended function

of providing electrical connections to specified sections of an electrical circuit to deliver system

voltage and current. However, the inspectors found that the applicant's electrical spaces

position paper, PP-DRE-QDC-Revision 01-SPACES, was inconsistent with the active/passive

position paper in that it identified fuse holders and fuse blocks as active components. During

the scoping methodology audit, the applicant stated that the active classification for fuse

holders and blocks in the PP-DRE-QDC Revision 01-SPACES was incorrect and would be

revised to match the passive classification in PP-DRE-QDC-Revision 02-AP. Despite the

discrepancy in procedure PP-DRE-QDC Rev 01-SPACES, the applicant appropriately classified

fuse holders and blocks as passive components. The staff concluded that the applicant's

scoping and screening methodology addressed the treatment of fuse holders in a manner

consistent with the staff's guidance contained in ISG-5.

The staff determined that the applicant's electrical and l&C screening methodology was

consistent with the guidance contained in NUREG-1 800 and was capable of identifying passive,

long-lived components within the scope of license renewal that are subject to an AMR.

2.1.4 Conclusions

The staff review of the information presented in Section 2.1 of the LRA, the supporting

information in the scoping and screening implementation procedures and reports, the

information presented during the scoping and screening methodology audit, and the applicant's

responses to the staff's RAls formed the basis of the staff's safety determination. The staff

verified that the applicant's scoping and screening methodology, including its supplemental

10 CFR 54.4(a)(2) review which brought additional non-safety-related piping segments and

associated components into the scope of license renewal, was consistent with the requirements

of the Rule and the staff's position on the treatment of non-safety-related SSCs. On the basis

of this review, the staff concluded that, there is reasonable assurance that the applicant's

methodology for identifying the SSCs within the scope of license renewal and the SCs requiring

an AMR is consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

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2.1.5 References

1. NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for

Nuclear Power Plants," April 2001

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

Part 54-The License Renewal Rule," August 2001

3. Letter from the NRC to Exelon Generation Company, LLC, "Request For Additional

Information for the Review of the Dresden Nuclear Power Station, Units 2 and 3, and Quad

Cities Nuclear Power Station, Units 1 and 2, License Renewal Application," July 21, 2003

(ADAMS Accession No. ML0320200800)

4. Letter from Exelon Generation Company, LLC, to the NRC, "Additional Information for the

Review of the License Renewal Applications for Quad Cities Nuclear Power Station, Units 1

and 2 and Dresden Nuclear Power Station, Units 2 and 3," RS-03-178, October 3, 2003

5. Desktop Guide, Revision 2, "Scoping & Screening of Systems, Structures and Components"

6. GE-NE-LRTI-2000, Revision 6, "Technical Instruction for Exelon Dresden/Quad Cities

License Renewal Project-Scoping and Screening of Systems, Structures and Components

for License Renewal"

7. PP-QDC-DRE Revision 00 IN, "Treatment of Pipe/Equipment Insulation During Scoping and

Screening Systems for License Renewal"

8. PP-DRE Revision 03 SBO, "Systems and Structures Relied Upon to Demonstrate

Compliance with 10 CFR 50.63 (Station Blackout) Dresden Station-Units 2 and 3"

9. PP-QDC Revision 03 SBO, "Systems and Structures Relied Upon to Demonstrate

Compliance with 10 CFR 50.63 (Station Blackout) Quad Cities Station-Units 1 and 2"

10. PP-DRE-QDC Revision 02-AP, "Active/Passive Classification and Intended Function

Determination of Structures and Components"

11. PP-DRE-QDC Revision 01 SPACES, "Scoping and Screening Position Paper for Electrical

Components Based on Electrical Spaces Approach for Aging Management Review"

12. LRTI-1 6, Revision 0, "Identification of Non Safety-related Structures and Components

Which Spatially or Structurally Interact With Safety-related Systems"

13. NRC Inspection Report 50-237/03-04(DRS), 50-249/03-04(DRS), 50-254/03-04(DRS), 50-

265/03-04(DRS), "Dresden Nuclear Power Station, Quad Cities Nuclear Power Station,

NRC License Renewal Scoping/Screening Inspection," September 15, 2003

14. Letter from the NRC to Exelon Generation Company, LLC, "Follow-Up of an Inspection

Open Item Related to the Dresden Nuclear Power Station, Units 2 and 3, and Quad Cities

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Nuclear Power Station, Units 1 And 2, License Renewal Application," October 20, 2003

(ADAMS Accession No. ML032940056)

15. Letter from Exelon Generation Company, LLC, to the NRC, "Additional Information for the

Review of the License Renewal Applications for Dresden Nuclear Power Station, Units 2

and 3 and Quad Cities Nuclear Power Station, Units 1 and 2," RS-03-328, December 22,

2003

16. Letter from Exelon Generation Company, LLC, to the NRC, 'Additional Information for the

Review of the License Renewal Applications for Dresden Nuclear Power Station, Units 2

and 3, and Quad Cities Nuclear Power Station, Units 1 and 2," RS-03-325, December 17,

2003

17. Letter from Exelon Generation Company, LLC, to the NRC, "Additional Information for the

Review of the License Renewal Applications for Dresden Nuclear Power Station', Units 2

and 3 and Quad Cities Nuclear Power Station, Units 1 and 2," RS 04-046, March 25, 2004

18. Letter from Exelon Generation Company, LLC, to the NRC, "Response to License Renewal

Safety Evaluation Report for the Dresden and Quad Cities Nuclear Power Stations,"

RS 04-057, April 9, 2004

19. Letter from Exelon Generation Company, LLC, to NRC, "Follow-up Response to License

Renewal Safety Evaluation Report for the Dresden and Quad Cities Nuclear Power

Stations," RS 04-073, May 18, 2004

2.2 Plant-Level Scoping Results

2.2.1 Summary of Technical Information in the Application

This section addresses the plant-level scoping results for license renewal. Per 10 CFR

54.21 (a)(1), the applicant must identify and list SCs subject to an AMR. These are passive and

long-lived SCs that are within the scope of license renewal.

In LRA Tables 2.2-1 and 2.2-2, the applicant provided a list of the plant systems and structures,

respectively, identifying those that are within the scope of license renewal and those that are

not within the scope of license renewal. Systems and structures that exist only at one station

are marked in the tables as "Dresden only" or "Quad Cities only," as appropriate. The Rule

does not require the identification of all plant systems and structures. However, providing such

lists allows for a more efficient staff review. Based on the design-basis events considered in

the plant's CLB and other CLB information relating to non-safety-related systems and structures

and certain regulated events, the applicant identified those plant-level systems and structures

within the scope of license renewal, as defined in 10 CFR 54.4. To verify that the applicant has

properly implemented its methodology, the staff focuses its review on the implementation

results to confirm that there is no omission of plant-level systems and structures within the

scope of license renewal.

The staff performed the following two-step evaluation:

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(1) The staff determined whether the applicant properly identified the SSCs within the scope of

license renewal, in accordance with 10 CFR 54.4. The staff reviewed selected SSCs

identified by the applicant as not falling within the scope of license renewal to determine

whether they have any intended functions that do fall within the scope of license renewal.

(2) The staff then determined, in accordance with 10 CFR 54.21 (a)(1), whether the applicant

properly identified the SCs that are subject to an AMR from among the SSCs that were

identified as being within the scope of license renewal in accordance with 10 CFR 54.4.

The staff reviewed selected SCs that the applicant identified as being within the scope of

license renewal to verify whether they perform their intended functions, as described in

10 CFR 54.4, without moving parts or without a change in configuration or properties and

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

In LRA Section 2.3, "Scoping and Screening Results: Mechanical Systems," Section 2.4,

"Scoping and Screening Results: Structures," and Section 2.5, "Scoping and Screening Results:

Electrical and Instrumentation and Controls Systems," the applicant describes the SSCs that

are within the scope of license renewal and subject to an AMR in accordance with

10 CFR 54.4 and 10 CFR 54.21 (a)(1), respectively. The staff evaluated components and

commodities associated with all systems and structures within LRA Sections 2.3 through 2.5.

In LRA Sections 2.3.1 ("Reactor Coolant System"), 2.3.2 ("Engineered Safety Features

Systems"), 2.3.3 ('Auxiliary Systems"), and 2.3.4 ("Steam and Power Conversion Systems"),

the applicant described the mechanical systems and components within the scope of LR and

subject to an AMR based on the applicant's license renewal scoping and screening

methodology as described in Section 2.1 of this SER.

Structures that support or provide shelter and protection for the operation of other systems are

presented in LRA Section 2.4. Some structural components were treated as bulk commodity

items common to various systems and structures. These commodity items are described in

LRA Section 2.4.15, "Component Supports Commodity Group," and LRA Section 2.4.16,

"Insulation Commodity Group."

Electrical systems and l&C systems that support the operation of both safety and non-safetyrelated systems are presented in LRA Section 2.5. Electrical and l&C components are all

treated using a bulk commodity approach.

2.2.2 Staff Evaluation

In LRA Section 2.1, the applicant describes its methodology for identifying the SCs that are

within the scope of license renewal and subject to an AMR. This methodology typically consists

of a review of all plant SSCs to identify those that are within the scope of license renewal in

accordance with the requirements of 10 CFR 54.4. From those SSCs that are within the scope

of license renewal, an applicant will identify and list those SCs that are passive (i.e., that

perform their intended function(s) without moving parts, or without a change in configuration or

properties) and are long-lived (i.e., that are not replaced based on a qualified life or specified

time period). The staff reviewed the scoping and screening methodology and provided its

evaluation in Section 2.1 of this SER. The applicant documented the implementation of the

methodology in LRA Sections 2.3 through 2.5. The staff's review of the applicant's

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implementation was conducted in accordance with Section 2.3 of the SRP-LR and is described

in Sections 2.3 through 2.5 of this SER.

To ensure that the scoping and screening methodology described in LRA Section 2.1 was

properly implemented, and that the SCs that are subject to an AMR were properly identified, the

staff performed an additional review. The staff sampled the contents of the UFSAR based on

the listing of systems and structures in LRA Tables 2.2-1 and 2.2-2 to determine whether there

were systems or structures that may have intended functions as defined by 10 CFR 54.4 but

were not included within the scope of license renewal. The staff did not identify any omissions.

In LRA Section 1.4, the applicant stated that Dresden Unit 1 has been placed in a safe storage

condition until Units 2 and 3 are ready for decommissioning. Although Dresden Unit 1 has been

left intact, the fuel has been removed from the reactor vessel, and radioactive liquids have been

drained from the systems and components and have been processed. However, the dieseldriven fire pump and the crib house in Dresden Unit 1 provide support for operation of Units 2

and 3 that satisfy the criteria of 10 CFR 54.4(a). The staff's evaluation of this Unit 1 dieseldriven fire pump and the crib house SCs is provided in Section 2.3.3.5 of this SER.

In the Dresden and Quad Cities LRA, Sections 2.3 through 2.5, the applicant identified and

listed the SCs that are subject to an AMR in accordance with 10 CFR 54.21(a)(1). The

applicant identified the mechanical systems components and structural components that are

subject to an AMR in LRA Sections 2.3 and Section 2.4, respectively. The staff documents the

findings from its review and evaluation of the applicant's mechanical systems and plant

structural components screening results in Sections 2.3 and 2.4 of this SER, respectively.

2.2.3 Conclusions

The staff reviewed LRA Section 2.2 and the supporting information in the Dresden and Quad

Cities UFSARs to determine whether any SSCs within the scope of license renewal had not

been identified by the-applicant. As a result of this review, the staff did not identify any

omissions. On the basis of this review, the staff concludes that the applicant has appropriately

identified the SSCs that are within the scope of license renewal in accordance with

10 CFR 54.4. The NRC staff's detailed review of the SSCs that are subject to an AMR is

provided in Sections 2.3 through 2.5 of this SER.

2.3 Scoping and Screening Results: Mechanical Systems

This section addresses the scoping and screening results of the following mechanical systems

for the license renewal.

Reactor Systems

* reactor vessel

* reactor internals

* reactor coolant system

* reactor recirculation system

* reactor vessel head vent system

* nuclear boiler instrumentation system

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* head spray system

* RC pressure boundary components in other systems

Engineered Safety Feature Systems

* high-pressure coolant injection system

* core spray system

* containment isolation components and primary containment piping system

* reactor core isolation cooling system (Quad Cities only)

* isolation condenser (Dresden Only)

* residual heat removal system (Quad Cities only)

* low-pressure coolant injection system (Dresden only)

* standby liquid control system

* standby gas treatment system

* automatic depressurization system

* anticipated transient without scram system

Auxiliary Systems

* refueling equipment

* shutdown cooling system (Dresden only)

* control rod drive hydraulic system

* reactor water cleanup system

* fire protection system

* emergency diesel generator and auxiliaries

* HVAC-main control room

* HVAC-reactor building

* ECCS corner room HVAC

* station blackout building HVAC

* station blackout system (diesel and auxiliaries)

* diesel generator cooling water system

* diesel fuel oil system

* process sampling system

* carbon dioxide system

* service water system

* reactor building closed cooling water system

* turbine building closed cooling water system

* demineralizer water makeup system

* residual heat removal service water system (Quad Cities only)

* containment cooling service water (Dresden only)

* ultimate heat sink

* fuel pool cooling system and filter demineralizer system

* plant heating system

* containment atmosphere monitoring system

* nitrogen containment atmosphere dilution system

* drywell nitrogen inerting system

* safe shutdown makeup pump system (Quad Cities only)

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Steam and Power Conversion Systems

* main steam system

* feedwater

* condensate and condensate storage system

* main condenser

* main turbine and auxiliaries

* turbine oil system (Quad Cities only)

* main generator and auxiliaries (Quad Cities only)

As a result of the revised methodology described in the May 18, 2004 response to the draft

SER Open Item 2.1-1, the applicant added the following non-safety-related systems previously

excluded from the scope of license renewal to the scope for the first time at one or both sites.

* circulating water

* laundry treatment system (Dresden only)

* zinc injection system

* extraction steam system (Quad Cities only)

* feedwater heater drains and vents (Quad Cities only)

According to 10 CFR 54.21 (a)(1), an applicant must identify and list SCs subject to an AMR.

These are passive, long-lived SCs that are within the scope of license renewal. To verify that

the applicant has properly implemented its methodology, the staff focuses its review on the

implementation results. Such a focus allows the staff to confirm that there is no omission of

mechanical system components that are subject to an AMR. If the review identifies no

omission, the staff has the basis to find that there is reasonable assurance that the applicant

has identified the mechanical system components that are subject to an AMR.

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System

2.3.1.1 Reactor Vessel

2.3.1.1.1 Summary of Technical Information in the Application

The applicant described the reactor vessel in License Renewal Application (LRA) Section

2.3.1.1 and provided a list of components subject to an aging management review (AMR) in

LRA Table 2.3.1-1.

The reactor vessel contains the reactor core, the reactor internals, and the reactor core coolantmoderator. It serves as a high-intensity barrier against leakage of radioactive materials to the

drywell.

The reactor vessel is a vertical, cylindrical pressure vessel with hemispherical heads. The

cylindrical shell and bottom hemispherical head of the reactor vessel are of welded construction

and are fabricated of low alloy steel plate. The removable top head is attached to the cylindrical

shell flange by bolting. The major safety function for the reactor vessel is to provide a

radioactive material barrier. The vessel also provides a floodable core volume, contains the

moderator, and provides support for the reactor vessel internals.

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Intended Functions within the Scope of License Renewal include the following:

Pressure Boundary-Maintains the integrity of the reactor coolant pressure boundary

Containment-Provides a fission product containment barrier

Physical Support-Provides vertical and horizontal support for the core and other reactor vessel

internals

Core Cooling-The reactor vessel and the reactor vessel internals provide a means to distribute

coolant to the fuel assemblies located in the core and provides a floodable volume to at least

two-thirds core height following design basis accidents

Table 2.3.1-1 of the LRA identified the component groups requiring AMR. The component

groups which were identified for the reactor vessel include:

* Closure Bolting

* Nozzle Safe Ends

* Nozzles

* Penetrations

* Bottom Head Drain

- Control Rod Drive Stub Tubes

- Incore Instrument Housings

- Instrumentation and Jet Pump Instrumentation

- Standby Liquid Control

* Penetrations (Control Rod Drive Stub Tubes)

* Support Skirts and Attachment Welds

* Top Head Enclosure (Closure Studs and Nuts)

* Top Head Enclosure (Head Flanges)

* Top Head Enclosure (Top Heads and Nozzles)

* Vessel Bottom Heads

* Vessel Shell Attachment Welds

* Vessel Shells

- Beltline Welds

- Flange

- Intermediate Beltline Shell

- Intermediate Nozzle Shell

- Lower Shell

- Upper Shell

2.3.1.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.1, Dresden UFSAR Section 5.3, and Quad Cities UFSAR

Section 5.3 to determine whether there is reasonable assurance that the reactor vessel

components within the scope of license renewal and subject to an AMR have been identified in

accordance with 10 CFR 54.4 and 54.21 (a)(1). The staff's review was conducted in accordance

with Section 2.3 of the SRP-LR and is described as below.

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

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omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As part of

the evaluation, the staff determined whether the applicant had properly identified the systems,

structures, and components (SSCs) within the scope of license renewal and subject to an AMR,

pursuant to 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1). The staff reviewed the relevant portions

of the UFSAR for the reactor vessel and associated components and compared the information

in the UFSAR with the information in the LRA to identify those portions that the LRA did not

identify as being within the scope of license renewal and subject to an AMR. The staff then

reviewed the structures and components that were identified as not being within the scope of

license renewal to verify the following:

* these structures and components do not have any of the intended functions delineated

under 10 CFR 54.4(a)

* for those structures and components that have applicable intended function(s), verify that

they either perform these function(s) with moving parts or a change in configuration or

properties, or they are subject to replacement based on a qualified life or specified time

period, as described in 10 CFR 54.21 (a)(1).

The staff also reviewed the UFSAR for any function(s) delineated under 10 CFR 54.4(a) that

were not identified as intended function(s) in the LRA, to verify that the SSCs with such

function(s) will be adequately managed so that the function(s) will be maintained consistent with

the CLB for the extended period of operation.

After completing the initial review, the staff requested the applicant to provide additional

information on the reactor vessel. By letter dated October 3, 2003 (Ref. 1), the applicant

responded to the staff's request for additional information (RAI) as discussed below.

In RAI 2.3.1.1-1, the staff requested the applicant to verify whether the plant is equipped with a

thermal shield, whose intended function is to provide shielding for the safety-related SSCs,

such as the reactor vessel and the internals,-from gamma and neutron radiation, and thereby, it

may be relied upon to minimize irradiation induced embrittlement of the vessel and/or the

internals. If the component exists at Quad Cities and/or Dresden, the staff requested the

applicant to justify its exclusion from aging management; otherwise, to submit an AMR for the

subject component. In response, the applicant stated that the reactor vessels at Dresden and

Quad Cities do not contain any thermal shield to protect safety-related SSCs such as the

reactor vessel and the vessel internals from radiation. Further, no boiling water reactors

manufactured by General Electric contain such a design feature. Therefore, there is no need to

identify such a component in the LRA. Based on the above discussion, the staff finds the

applicant's assessment acceptable.

In RAI 2.3.1.1-2, the staff requested the applicant to clarify whether the vessel head spray

nozzle is included in LRA Table 2.3.1-1 as part of the component group "Nozzles." If the

component was not included in LRA Table 2.3.1-1, the staff requested the applicant to justify its

exclusion from aging management; otherwise, to submit an AMR for the subject component. In

response, the applicant stated that the vessel head spray nozzles for Dresden are included in

LRA Table 2.3.1-1 as part of the component group "Top Head Enclosure (Top Head Nozzles)"

and are subject to aging management. Based on the above discussion, the staff finds the

applicant's assessment acceptable.

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In RAI 2.3.1.1-3, the staff requested the applicant to indicate whether (1) thermal sleeves for

core spray and recirculation inlet nozzles, (2) standby liquid control and core differential

pressure line, and (3) low-pressure coolant injection (LPCI) coupling are considered part of the

reactor pressure vessel nozzles, safe ends, attachments and instrument penetrations requiring

an AMR. If so, the staff requested the applicant to provide an AMR for the subject components

and include them in LRA Table 2.3.1-1. Also, the staff requested that the applicant indicate

whether the nozzles connecting the reactor recirculation system to the connecting piping should

be identified as reactor recirculation system components requiring AMR. In response, the

applicant stated the follwoing:

* The thermal sleeves for core spray are considered to be part of the core spray lines and

spargers. They are addressed in LRA Section 2.3.1.2.1, Table 2.3.1-2, Component Group, - Core Spray Lines and Spargers. The recirculation inlet nozzles thermal sleeves are

considered an integral part of the recirculation nozzles. They are addressed in LRA Section

2.3.1.1, Table 2.3.1-2, Component Group - Nozzle Safe Ends.

* LRA Section 2.3.2.8 Standby Liquid Control, Table 2.3.2-8, Component Group - Piping and

Fittings, addresses the standby liquid control line (not including the vessel nozzle).

* LRA Section 2.3.1.1 Reactor Vessel, Table 2.3.1-1, Component Group - Nozzle Safe Ends,

addresses the standby liquid control nozzle.

* LRA Section 2.3.1.3.3 Nuclear Boiler Instrumentation, Table 2.3.1-7, Component Group - Piping and Fittings (small bore) addresses the core differential pressure line. These system

evaluation breaks are depicted on Boundary Diagrams LR-DRE-M-26-1 (E/6), LR-DRE-M357-1 (B1/5), LR-QDC-M-35-1 (G/4), and LR-QDC-M-77-1 (G/4).

Those portions of the standby liquid control and core differential pressure piping located

inside the reactor vessel were determined to be not in the scope of the Rule. They do not

perform a safety-related function and their failure would not prevent a safety-related SSC

from performing a safety-related function. This evaluation is supported by BWRVIP-27,

BWR Standby Liquid Control System/Core Plate AP Inspection and Flaw Evaluation

Guidelines. BWRVIP-27 has been evaluated and accepted by the NRC staff. Paragraph

2.2.1 of BWRVIP-27 provides a safety assessment stating that the standby liquid control

and core differential pressure internals are not essential and therefore concluded in

paragraph 3.1.1 of BWRVIP-27 that no inspections are recommended.

* As stated in LRA Table 3.1-1, Ref. No. 3.1.1.17 low-pressure coolant injection (LPCI)

couplings are not used at Dresden or Quad Cities. The low-pressure coolant injection

(LPCI) coupling identified in BWRVIP-06, Safety Assessment of BWR Reactor Internals,

applies to BWR/4, BWR/5 and BWR/6 reactors (Ref. Section 2.7, BWRVIP-06). The

Dresden and Quad Cities reactors are a BWR/3 design. Neither site has a LPCI coupling

as described in BWRVIP-06.

* LRA Section 2.3.1.1 Reactor Vessel, Table 2.3.1-1, Component Group - Nozzle Safe Ends,

includes the nozzles connecting the reactor recirculation system to the connecting piping.

They are considered to be part of the reactor vessel and should not be identified as reactor

recirculation system components.

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Based on the above discussion, tkb staff finds the applicant's assessment acceptable. There is

no need to identify those portions of the standby liquid control and core differential pressure

piping located inside the reactor vessel in LRA Table 2.3.1-1. As stated in LRA Table 3.1-1,

Reference 3.1.1.17, LPCI couplings are not used at Dresden or Quad Cities, and therefore,

there is no need to identify the LPCI couplings in LRA Table 2.3.1-1.

The staff did not identify any omissions.

2.3.1.1.3 Conclusions

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether any SSCs that should be within the'scope of license renewal were not identified by the

applicant. No omissions were found. In addition, the staff performed an independent

assessment to determine whether any components that should be subject to an AMR were not

identified by the applicant. The staff did not identify any omissions. On the basis of its review,

the staff concludes there is reasonable assurance that the applicant has adequately identified

the reactor vessel components that are within the scope of license renewal, as required by 10

CFR 54.4(a), and that the applicant has adequately identified the reactor vessel components

that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.1.2 Reactor Vessel Intemals

2.3.1.2.1 Summary of Technical Information in the Application

The applicant describes the reactor vessel internals in LRA Section 2.3.1.2 and provides a list

of components subject to an AMR in LRA Table 2.3.1-2.

The reactor internals are installed to properly'distribute the flow of coolant delivered to the

vessel, to locate and support the fuel assemblies and control blades, and to provide an inner

volume containing the core that can be flooded following a break in the nuclear system process

barrier external to the reactor vessel.

The shroud is a stainless steel cylinder which surrounds the reactor core and provides a barrier

to separate the upward flow of the coolant through the reactor core from the downward

recirculation flow. Bolted on top of the shroud is the steam separator assembly which forms the

top of the core discharge plenum. This provides a mixing chamber before the steam-water

mixture enters the steam separator. The recirculation outlet and inlet plenum are separated by

the baffle plate (part of the shroud support structure) joining the bottom of the shroud to the

vessel wall. The jet pump diffuser sits on and is welded to the baffle plate, making the jet pump

diffuser section an integral part of the baffle plate. The baffle plate supports all of the vertical

weight of the shroud, steam separator and dryer assembly, top guide and bottom core plate

(core grids), peripheral fuel assemblies, and jet pump components carried on the shroud. The

control rod guide tubes extend up from the control rod drive housing through holes in the core

plate. Each tube is designed as a lateral guide for the control rod and as the vertical support for

the fuel support piece which holds the four assemblies surrounding the control rod.

Intended Functions within the Scope of License Renewal:

Reactivity Control - The control rod drive mechanisms insert negative reactivity for normal

shutdown and for mitigation of operational transients and accidents. Reactor vessel internals,

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not directly involved with reactivity insertion, support reactivity insertion by maintaining

appropriate geometry to permit proper functioning of the control rod drive mechanism. Standby

liquid control system flow supports an alternate method for reactivity control.

Core Cooling - Distributes emergency cooling system flow to the core and maintains coolable

core geometry.

Support Safety-Related Function(s) - Reactor vessel internals which do not perform a safetyrelated function are required not to fail in a way that would cause a safety-related function to

fail.

Physical Support - Provides vertical and horizontal support for the core and other reactor vessel

internals.

Table 2.3.1-2 of the LRA identified the component groups requiring AMR. The component

groups which were identified for the reactor internals include:

* Access Hole Covers (Mechanical)

* Access Hole Covers (Welded) (Dresden only)

* Control Rod Drive Housings [Pressure Boundary]

* Control Rod Drive Housings [Structural Support]

* Control Rod Guide Tubes

* Core Plates

* Core Plates and Bolts

* Core Shrouds (Upper, Central, Lower)

* Core Spray Lines and Spargers [pressure boundary]

* Core Spray Lines and Spargers [Spray]

* Core Spray Lines and Spargers [Structural Support]

* Incore Instrumentation Dry Tubes and Guide Tubes

* Jet Pump Assemblies (Does not include Sensing Lines) [pressure boundary]

* Jet pump Assemblies (Does not include Sensing Lines) [structural support]

* Orificed Fuel Support Pieces

* Orificed Fuel Supports

* Reactor Internals Modification/Repair Hardware

- Core Spray Clamp

- Jet Pump Riser Clamp (Quad Cities only)

- Jet Pump Riser Brace Clamp (Quad Cities only)

- Shroud Repair

* Shroud Support Structures

* Top Guides

2.3.1.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.2, Dresden UFSAR Section 3.9.5, and Quad Cities

UFSAR Section 3.9.5 to determine whether there is reasonable assurance that the reactor

vessel internals components within the scope of license renewal and subject to an AMR have

been identified in accordance with 10 CFR 54.4 and 54.21 (a)(1). The staff's review was

conducted in accordance with Section 2.3 of the SRP for License Renewal (NUREG-1800) and

is described as below.

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In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As part of

the evaluation, the staff determined whether the applicant had properly identified the SSCs

within the scope of license renewal and subject to an AMR, pursuant to 10 CFR 54.4(a) and

10 CFR 54.21 (a)(1). The staff reviewed the relevant portions of the UFSAR for the reactor

vessel internals and associated components and compared the information in the UFSAR with

the information in the LRA to identify those portions that the LRA did not identify as being within

the scope of license renewal and subject to an AMR. The staff then reviewed the structures

and components that were identified as not being within the scope of license renewal to verify

that:

1. these structures and components do not have any of the intended functions delineated

under 10 CFR 54.4(a), and

2. for those structures and components that have an applicable intended function(s), verify

that they either perform this function(s) with moving parts or a change in configuration or

properties, or that they are subject to replacement based on a qualified life or specified

time period, as described in 10 CFR 54.21 (a)(1).

The staff also reviewed the UFSAR for any function(s) delineated under 10 CFR 54.4(a) that

were not identified as intended function(s) in the LRA, to verify that the SSCs with such

function(s) will be adequately managed so that the function(s) will be maintained consistent with

the CLB for the extended period of operation.

After completing the initial review, the staff requested the applicant to provide additional

information on reactor internals. By letter dated October 3, 2003 (Ref. 1), the applicant

responded to the staff's request for additional information (RAI) as discussed below:

In Drawing LR-QDC-FSAR-3.9 of the LRA, the steam separator and standpipe assembly are

both in scope at Quad Cities. In RAI 2.3.1.2-1,-the staff requested the applicant to explain why,

per LR-DRE-FSAR-3.9, the steam separator assembly, including the steam separator, steam

separator standpipe and steam plenum head, are not also in scope at Dresden. In response,

the applicant stated that LR-QDC-FSAR-3.9 incorrectly shows the steam separator and

standpipe assembly as in scope at Quad Cities. The steam separator and standpipe

assemblies are not safety-related, nor would their failure cause another safety-related SSC

from performing its safety-related function, as discussed in BWRVIP-06, BWR Vessel and

Internals Project, Section 3.2.2. Therefore, the steam separator and standpipe assemblies at

both Dresden and Quad Cities are not in the scope of the rule and not subject to AMR. The

steam plenum head depicted on LR-DRE-FSAR-3.9 is the area between the core shroud head

and the bottom of the steam separator standpipe. It is not a component. Based on the above

discussion, the staff finds the applicant's assessment acceptable.

In drawing LR-DRE-FSAR-3.9, steam dryer lifting lugs are in scope at Dresden. In

RAI 2.3.1.2-2, the staff requested the applicant to identify if Quad Cities has steam dryer lifting

lugs and if so, to explain why the steam dryer lifting lugs are in scope at Dresden but not Quad

Cities. In response, the applicant stated the steam dryer lifting lugs are not identified on LRDRE-FSAR-3.9, however, these lugs are out of scope at both Dresden and Quad Cities. This is

consistent with boundary diagram LR-QDC-FSAR-3.9 which does show the steam dryer lifting

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lugs as out of scope. Based on the above discussion, the staff finds the applicant's

assessment acceptable.

As noted in NRC Information Notice 2002-26, "Failure of Steam Dryer Cover Plate After a

Recent Power Uprate," dated September 11, 2002, Quad Cities Unit 2 experienced a failure of

the steam dryer cover plate in March 2002 following implementation of the 17.8% power uprate

of the unit. One piece of the dryer cover plate had fallen onto the separator; another piece was

found in the dryer; a third piece had lodged in the A main steam line flow venturi (upstream of

the main steam isolation valves); and several other pieces had been swept down the A main

steam line downstream of the MSIVs into a turbine stop valve strainer. It was reported by the

applicant however, that there was no apparent damage other than minor scratches and gouges

to the main steam nozzle and piping.

On June 12, 2003, inspections of the steam dryer at Quad Cities Unit 2 identified the following:

(1) through-wall cracking (about 90 inches in length) in the vertical and horizontal outer hood

plate, (2) one vertical and two diagonal internal braces detached on the outer hood, (3) one

severed vertical internal brace on the outer hood, and (4) three cracked tie bars on top of the

dryer.

Following up on this recent issue, the staff issued RAI 4.3.0. In RAI 4.3.0(a), the staff is

concerned that while components such as the steam dryer and steam separator are non-safetyrelated, the failure of these components (as experienced at Quad Cities Unit 2) could potentially

impact other safety-related components. This issue was also discussed during the Advisory

Committee on Reactor Safeguards (ACRS) subcommittee meeting on April 14, 2004, and then

during the full committee meeting on September 9, 2004. In a letter dated

September 16, 2004, the ACRS recommended that for Dresden Units 2 and 3 and Quad Cities

Units 1 and 2, the steam dryers should be included in the scope of license renewal. By letter

dated October 8, 2004, Exelon has committed to include the steam dryers within the scope of

license renewal for Dresden and Quad Cities for 10 CFR 54.4(a)(2). The aging effect that

needs to be managed is cracking. The aging management program will be the NRC approved

Boiling Water Reactor Vessel Internals Program (BWRVIP) Steam Dryer Inspection and

Evaluation Guideline. If the BWRVIP Steam Dryer Inspection and Evaluation Guideline is not

approved by the NRC then a plant specific aging management program will be submitted to the

NRC for review and approval by December 22, 2007, which is two years before the first

Dresden unit enters the period of extended operation. This is part of Commitment #9 in

Appendix A of this SER.

Also in response, the applicant stated additional information regarding the steam dryer failure

was provided to the NRC in report GENE-0000-0018-3359-P, 'Technical Assessment, Quad

Cities Unit 2 Steam Dryer Failure - Determination of Root Cause and Extent of Condition,"

Revision 1, dated August 2003, which was transmitted by letter from Mr. P.R. Simpson (Exelon

Generation Company) to the NRC, "Transmittal of General Electric Technical Assessment

Regarding Quad Cities Nuclear Power Station Unit 2 Steam Dryer Failure," dated August 11,

2003. The failure of the steam dryer as described in the above technical assessment was

attributed to high cycle fatigue resulting from low frequency pressure loading on the outer

hoods during normal operation. The failure did not prevent satisfactory accomplishment of any

of the functions identified in 10 CFR 54.4(a)(1)(i), (ii) or (iii). Those portions of non-safetyrelated SSCs that could spatially or structurally interact with a safety-related SSC in a manner

that would prevent the accomplishment of a safety-related SSC intended function were included

within the scope of License Renewal as described in LRA Section 2.1.2.2 and in response to

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RAI 2.1-2: CFR 54.4(a)(2), Scoping Criteria for non-safety-related SSCs. Based on the above

discussion and the applicant's commitment, the staff finds the applicant's assessment

acceptable.

In RAI 4.3.0(b), the staff requested the applicant to explain how they have considered or

examined the potential synergistic effects of large power uprates and plant aging (for those

SSCs within scope of license renewal). In response, the applicant stated the Dresden/Quad

Cities extended power uprate (EPU) evaluations that explicitly included an assumption of 60

years operation (54 effective full power years [EFPY]) were the Reactor Fracture Toughness

Evaluation and the Reactor Internals Flow Induced Vibration Evaluation. The Reactor Fracture

Toughness Evaluation determined that there is an increase in the ART (adjusted reference

temperature) of the limiting beltline material, and a corresponding increase in the beltline

portion of the pressure-temperature (P-T) curves is required to include the increase in fluence

and licensed EFPY for the P-T curves for 54 EFPY. Exelon will submit revised Dresden P-T

curves to the NRC for 54 EFPY. The Reactor Internals Flow Induced Vibration Evaluation

concluded that, except for the Dresden Unit 2 jet pump riser braces, the Dresden and Quad

Cities units can operate at the increased flow associated with EPU conditions for a 60-year

plant life without exciting the safety-related reactor internal components above their established

vibration criteria limits during balanced (dual loop) recirculation flow operation and without

developing resonance problems due to vane passing frequency excitation. Additionally, the

EPU analyses considered single recirculation loop operation and concluded that with the

existing flow restrictions that apply for single recirculation loop operation, there is no resonance

problem due to vane passing frequency excitation at EPU conditions. The exception involving

the Dresden Unit 2 jet pump riser braces occurs because these riser braces are designed

differently from the Dresden Unit 3 and the Quad Cities Units 1 and 2 jet pump riser braces.

LRA Section 4.3.2.2 includes a commitment to repair or replace the Dresden Unit 2 jet pump

riser braces prior to the period of extended operation. The Dresden/Quad Cities license

renewal evaluations were based upon the plant environmental conditions associated with EPU

implementation. Prior to the period of extended operation, the Environmental Qualification (EQ)

Binders for components within the scope of 10 CFR 50.49 will be updated to include

environmental conditions associated with EPU implementation together with an extended

operating period of 60 years. No other synergistic effects of large power uprates and plant

aging were considered for those SSCs within the scope of license renewal. Based on this

discussion, the staff finds the applicant's assessment acceptable.

In RAI 2.3.1.2-3, the staff requested the applicant to explain why feedwater spargers are not in

scope. In response, the applicant stated the feedwater spargers are not in scope because their

failure would not prevent the injection of coolant makeup and they are not required to safely

shutdown the reactor. They were therefore classified as non-safety-related. Also, the sparging

function is not credited in delivery of Emergency Core Cooling System (EECS) flow to the

vessel and no failure that could result in consequential failure of safety-related components has

been identified. Therefore, there is no need to identify such a component in the LRA. Based

on the above discussion, the staff finds the applicant's assessment acceptable.

In accordance with 10 CFR 54.4(a) criteria, sump screens and vortex suppressors/breakers are

in scope of license renewal requiring AMR. In RAI 2.3.1.2-4, the staff requests the applicant to

identify if sump screens and vortex suppressors/breakers are in scope at Dresden and Quad

Cities. If they are in scope, the applicant was asked to submit the AMR results to the staff. If

they are not within scope, the applicant was asked to explain the reason for their exclusion. In

response, the applicant stated that Sump (ECCS) screens and vortex suppressors/breakers are

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installed in pressurized-water reactors (PWR). The equivalent boiling-water reactor equipment

is the suppression chamber ECCS suction strainers. At Dresden and Quad Cities, these

ECCS suction strainers are in the scope of license renewal and are managed for aging. The

suppression chamber ECCS suction strainers are included in LRA Section 2.3.2.7, Table 2.3.2-

7 under the Component Group "filters/strainers (Dresden only)" with "filter" as the component

intended function, and in LRA Section 2.3.2.6, Table 2.3.2-6, under the Component Group

"Filters/Strainers (Quad Cities only)" with 'Filter" as the component intended function. The

aging management results of the strainer (stainless steel) components that are exposed to 25 -

288 OC demineralized water environment are provided in Aging Management Reference

3.2.1.13, LRA Table 3.2-1. The aging mechanism of blockage, as it applies to strainers, is

managed by the "Protective Coating Monitoring and Maintenance" aging management program,

B.1.32, which provides for aging management of service level I coatings inside the primary

containment. Based on the above discussion, the staff finds the applicant's assessment

acceptable.

The applicant has identified most of the reactor internals requiring AMR. However, there are a

few items that normally would be considered part of reactor pressure vessel internals requiring

AMR that have not been included in the submitted LRA. In RAI 2.3.1.2-5, the staff requested

the applicant to justify the following exclusions from aging management; otherwise, submit an

AMR for the subject component:

* Thermal sleeves for core spray and recirculation inlet nozzles. These sleeves represent

pressure boundary and direct flow to core spray spargers and jet pumps, respectively

* Standby liquid control and core differential pressure line (SLC/core delta P line, pressure

boundary PB)

* Please identify all the components that are included in Component Group "Jet pump

assemblies," and also explaining why sensing lines are not included in jet pump assemblies

* Low pressure coolant injection coupling

In response to RAI 2.3.1.2-5, the applicant provides the following clarification of either where to

find the components in the LRA or the justification for excluding the component from AMR.

* The thermal sleeves for core spray are considered to be part of the core spray lines and

spargers. They are addressed in LRA Section 2.3.1.2.1, Table 2.3.1-2, Component Group -

Core Spray Lines and Spargers. The recirculation inlet nozzle thermal sleeves are

considered an integral part of the recirculation nozzles. They are addressed in LRA 2.3.1.1,

Table 2.3.1-2, Component Group - Nozzle Safe Ends.

* The portions of the standby liquid control and core differential pressure piping located inside

the reactor vessel were determined to be not in the scope of license renewal. They do not

perform a safety-related function and their failure would not prevent a safety-related SSC

from performing a safety-related function. This evaluation is supported by BWRVIP-27,

BWR Standby Liquid Control System/Core Plate AP Inspection and Flaw Evaluation

Guidelines. BWRVIP-27 has been evaluated and accepted by the NRC staff. Paragraph

2.2.1 of BWRVIP-27 provides a safety assessment stating that the standby liquid control

and core differential pressure internals are not essential, and therefore concluded in

paragraph 3.1.1 of BWRVIP-27 that no inspections are recommended.

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* The Jet Pump Assemblies group is comprised of the following components:

- a. Thermal Sleeve

- b. Inlet Header

- c. Riser Brace Arm

- d. Hold Down Beams

- e. Inlet Elbow

- f. Mixing Assembly

- g. Diffuser

BWRVIP-41, BWR Jet Assembly Inspection and Flaw Evaluation Guidelines

(Section 2.3.12.7) concludes that inspection of sensing lines is essentially occurring

continuously by plant operations. If a sensing line were to fail, the ability to monitor jet

pump integrity would be lost. Plant Technical Specifications would require either a plant

shutdown or safety assessment to justify continued operation if a failure were to occur.

Therefore, sensing line failure has no adverse safety consequences and no inspection is

required.

* As stated in LRA Table 3.1-1, Ref No. 3.1.1.17 LPCI couplings are not used at Dresden or

Quad Cities. The LPCI coupling identified in BWRVIP-06, Safety Assessment of BWR

Reactor Internals, applies to BWR/4, BWR/5, and BWR/6 reactors (see Section 2.7 of

BWRVIP-06). The Dresden and Quad Cities reactors are a BWR/3 design. Neither site

has a LPCI coupling as described in BWRVIP-06.

Based on the above discussion, the staff finds the applicant's assessment acceptable. The staff

did not identify any omissions.

2.3.1.2.3 Conclusions

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether any systems, structures, or components that should be within the scope of license

renewal were not identified by the applicant. The staff did not identify any omissions. In

addition, the staff performed an independent assessment to determine whether any

components that should be subject to an AMR were not identified by the applicant. The staff

did not identify any omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the reactor vessel internals

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

that the applicant has adequately identified the reactor vessel internals components that are

subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.1.3 Reactor Coolant System

2.3.1.3.1 Summary of Technical Information in the Application

The applicant described the reactor coolant system in LRA Section 2.3.1.3 and provided a list of

components subject to an AMR in LRA Tables 2.3.1-5 through 2.3.1-9.

The reactor coolant system for BWRs as described in NUREG-1 800 includes the reactor

coolant recirculation system and portions of other systems connected to the pressure vessel

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extending to the first isolation valve outside of containment or to the first anchor point. For

Dresden and Quad Cities, the reactor coolant system comprises the following plant systems:

* Reactor recirculation system, recirculation flow control, and M/G sets

* Reactor vessel head vent system

* Nuclear boiler instrumentation system

* Head spray system (Dresden only)

* Reactor coolant pressure boundary components in other systems

- High-pressure coolant injection system

- Core spray system

- Reactor core isolation cooling system (Quad Cities only)

- Isolation condenser (Dresden only)

- Residual heat removal system (Quad Cities only)

- Low-pressure coolant injection system (Dresden only)

- Standby liquid control system

- Shutdown cooling system (Dresden only)

- Control rod drive hydraulic system

- Reactor water cleanup system

- Main steam system

- Feedwater system

In RAI 2.1-2, the staff stated that by letters dated December 3, 2001, and March 15, 2002, the

NRC issued a staff position to the Nuclear Energy Institute (NEI) which described areas to be

considered and options it expects licensees to use to determine what SSCs meet the 10 CFR

54.4(a)(2) criterion (i.e., all non-safety-related SSCs whose failure could prevent satisfactory

accomplishment of any safety-related functions identified in paragraphs (a)(1 )(i),(ii),(iii) of this

section.)

The December 3rd letter provided specific examples of operating experience which identified

pipe failure events (summarized in Information Notice 2001-09, "Main Feedwater System

Degradation in Safety-Related ASME Code Class 2 Piping Inside the Containment of a

Pressurized Water Reactor") and the approaches that the NRC considers acceptable to

determine which piping systems should be included in the scope based on 10 CFR 54.4(a)(2).

The March 1 5 ' letter further described the staff's expectations for the evaluation of non-piping

SSCs to determine which additional non-safety-related SSCs are within scope. The position

states that applicants should not consider hypothetical failures, but rather should base their

evaluation on the plant's current licensing basis (CLB), engineering judgement and analyses,

and relevant operating experience. The letter further describes operating experience as all

documented plant-specific and industry-wide experience which can be used to determine the

plausibility of a failure. Operating experience documentation sources would include NRC

generic communications and event reports, plant-specific condition reports, industry reports

such as SOERs, and engineering evaluations.

Based on a review of the LRA, the applicant's scoping and screening implementation

procedures, and discussions with the applicant, the staff determined that additional information

is required with respect to certain aspects of the applicant's evaluation of the 10 CFR 54.4(a)(2)

criteria. The staff asked the applicant to address the following issues:

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* LRA Section 2.1.2.2, "Title 10 CFR 54.4(a)(2) - Non-safety-related affecting safetyrelated,N stated that the applicant performed plant walkdowns to identify those areas

containing safety-related SSCs. The applicant further stated in LRA Section 2.1.2.2

that, in those instances where a plant walkdown could not be performed, it used plant

drawings to identify those areas containing safety-related SSCs and identify component

interactions. For areas where walkdowns could not be performed to identify non-safetyrelated SSCs that could affect safety-related SSCs, the staff asked the applicant to

describe the methodology and documentation sources used to perform scoping

pursuant to 10 CFR 54.4(a)(2). In its response, the NRC asked the applicant to list the

areas where walkdowns were not performed and the basis for not performing the

walkdowns.

* Instruction LRTI-16, Identification of Non Safety-related Structures and Components

Which Spatially or Structurally Interact With Safety-related Systems," describes the

process used to identify non-safety-related systems and components which meet the

scoping criteria specified in 10 CFR 54.4(a)(2) due to spatial or structural interaction

with safety-related systems. Section 4.3 of LRTI-1 6 states that non-safety-related

systems are evaluated using the criteria provided in LRTI-16, Table 2, "Spatial

Interaction Screening Criteria." The staff asked the applicant to describe the basis

and/or justification for the use of the following spatial interaction screening criteria

contained in LRTI-1 6, Table 2:

* Cables in conduit or trays are not affected by water sprays as long as the spray does

not target a cable termination area. Nor is it credible that water would be channeled

to a termination area (LRTI-16, Table 2, Item 4).

* Pipe whip and jet impingement only apply to high energy systems containing fluids

with temperatures greater than or equal to 200 OF and a pressure greater than or

equal to 275 psig (LRTI-16, Table 2, Item 5). The staff noted that this definition of

high energy systems appeared to be inconsistent with the current licensing basis

definition of a high energy system (for example, see Dresden UFSAR, Section

3.6.1.1.1.1).

* Fluid sprays can only affect active components (LRTI-1 6, Table 2, Item 6).

* Early detection of leaks (sumps and floor drain systems) is taken credit in the scope

of the rule to prevent long term degradation of passive equipment and flooding

beyond the lowest elevation of the building (LRTI-1 6, Table 2, Item 8).

* Spray from high energy systems can affect equipment up to 25 feet (LRTI-16,

Table 2, Item 10).

* Spray from medium/low energy systems can affect equipment up to 20 feet (LRTI16, Table 2, Item 11).

* Section 2.1.2.2 of the LRA states that pipe whip, jet impingement, general flooding, or

spray of a gas were not considered credible interactions for gas systems to adversely

affect safety-related SSCs. LRTI-16, Table 2, Item 3, states, "while falling equipment

from gas systems can spatially impact safety-related components located below them,

the only credible manner in which equipment can fall is through failure of the attached

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supports.' Consistent with the staff position described in the March 15h letter, please

describe your scoping methodology implemented for the evaluation of the 10 CFR

54.4(a)(2) criteria as it relates to the non-fluid-filled SSCs of interest. As part of your

response please indicate the non-fluid-filled SSCs evaluated and describe the site and

industry operating experience relied on to determine the potential for failures of such

non-fluid-filled SSCs which could impact safety-related SSCs within scope.

As described in the letter dated March 15, 2003, if an applicant uses a mitigative option

when performing the scoping of non-safety-related SSCs under 10 CFR 54.4(a)(2), the

applicant should demonstrate that plant mitigative features are adequate to protect

safety-related SSCs from non-safety-related SSC failures, regardless of failure location.

If an applicant cannot demonstrate that the mitigative features are adequate to protect

safety-related SSCs from the consequences of non-safety-related SSC failures, then the

entire non-safety-related SSC is required to be brought into scope of license renewal. In

reviewing the LRA, the NRC staff was unable to determine if the 10 CFR 54.4(a)(2)

scoping methodology considered failures at all piping locations where age-related

degradation is possible. Please clarify how the scoping methodology of non-safetyrelated piping was performed relative to the guidance contained in the staff's March 15,

2003 letter.

* In discussions with the Exelon license renewal project team, the NRC staff noted some

cases where non-safety-related plant equipment was credited with providing anchorage

for non-safety-related piping that was attached to safety-related piping. In these cases,

the non-safety-related piping was placed within the scope of license renewal, but the

plant equipment (such as a heat exchanger) was not considered to be within scope. For

cases where an entire pipe run including both safety and non-safety-related piping was

analyzed as part of the current licensing basis to establish that it could withstand design

basis event loads, NUREG-1800, Section 2.1.3.1.2 indicates that the scoping

methodology includes: (1) the non-safety-related piping up to its anchors and (2) the

associated piping anchors as being within the scope of license renewal under 10 CFR

54.4(a)(2). Because the plant equipment credited with providing support to non-safetyrelated piping within the scope of license renewal appears to be equivalent to an

associated piping anchor as described in NUREG-1800, provide justification for not

including this plant equipment within the scope of license renewal.

In addressing each of the above issues, if your review indicates that use of the scoping

methodology screened out potential non-safety-related SSCs that could spatially interact with

safety-related SSCs, describe any additional scoping evaluations performed to address the

10 CFR 54.4(a)(2) criteria. As part of your response, list any additional SSCs included within

scope as a result of your efforts, and list those SCs for which aging management reviews were

conducted, and for each SC describe the aging management programs, as applicable, to be

credited for managing the identified aging effects.

Based on the applicant's response to RAI 2.1-2 in Reference 2, the staff determined that the

applicant did not provide a sufficient basis for limiting consideration of fluid spray interactions to

only those non-safety-related SSCs located within 20 feet of an active safety-related SSC. This

issue is now identified as Open Item 2.1-1. The staff required additional clarification regarding

the capability of active and passive safety-related SSCs located greater than 20 feet from a

potential spray source to tolerate wetting, the specific operating experience that was relied upon

to determine that it was not credible for fluid sprays to affect equipment greater than 20 feet

2-56
from a failure location, specific methods to detect leakage in normially accessible and

inaccessible areas, and justification for use of exposure duration in limiting the scope of

potential failure mechanisms considered during scoping.

In response to Open Item 2.1-1 (Ref. 3), Exelon has revised the methodology utilized in the

scoping of non-safety-related moderate energy piping systems that have the potential to

spatially interact with safety-related systems. Specifically, Exelon has eliminated the 20 foot

separation criterion previously utilized to exclude moderate energy systems from the scope of

License Renewal. The revised methodology assumes that all safety-related components, active

as well as passive, could be adversely affected by spray or wetting from a non-safety moderate

energy system located in the same general area of the plant. As such, early detection of

leakage was also eliminated from the revised scoping methodology.

Under the revised scoping methodology, all components from moderate energy non-safetyrelated systems located in the same general area as a safety-related component (active or

passive) will be included within the scope of license renewal. "General area" is defined as the

same floor (elevation) of a major building with no barrier walls between the fluid source and the

safety-related component. Barrier walls were defined as barriers that form the boundary of a

room on the same elevation of a major building separating the safety-related components from

a spray or leak generated by a non-safety-related component located on the other side of the

barrier wall. All barrier walls credited for protection of safety-related components were

previously included within the scope of license renewal during the scoping of structures and are

included in the structures monitoring aging management program described in section B.1.30 of

the license renewal application and the masonry wall aging management program described in

section B.1.29 of the license renewal application.

While both sites contain similar systems and equipment, the location of specific systems and

equipment varies between sites. For example, the safety-related standby gas treatment system

at Dresden Station is located in the Turbine Building while the same system is located in the

Reactor Building at Quad Cities. Because this system resides in two different physical locations

at each site, it will spatially interact with different non-safety-related piping systems. This

explains why the scoping boundaries for the same non-safety-related system can vary between

sites.

Following the revised methodology described above, the boundaries of several non-safetyrelated systems previously included within scope of license renewal were expanded. Likewise,

several non-safety-related systems previously excluded from the scope of license renewal were

added to the scope for the first time at one or both sites.

Because of the revised methodology, additional piping and components from the reactor

recirculation system were added to the scope of license renewal at Quad Cities due to the

potential for spatial interaction with safety-related components. Specifically, the recirculation

motor generator oil subsystem was added to the scope of license renewal at Quad Cities. All of

the components shown on revised boundary diagrams LR-QDC-M-35-4 and LR-QDC-M-77-4

have been included within the scope of license renewal. The system did not require a boundary

expansion at Dresden because the physical plant layout is different than Quad Cities at this

location. The resulting changes to LRA Table 2.3.1-5 include the following:

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Component Component Intended LRA Aging Management

Function Reference

Pumps (spatial interaction) Leakage Boundary (spatial) 3.1.2.66, 3.1.2.67

(Quad Cities only)

Tanks (spatial interaction) Leakage Boundary (spatial) 3.1.2.3, 3.1.2.68

(Quad Cities only)

Based on the above discussion, the staff finds the applicant's response and revised

methodology changes for the reactor recirculation system acceptable.

Intended Functions within the Scope of License Renewal:

The following intended functions are for the reactor coolant system as a whole as comprised

above by the licensee in LRA Sections 2.3.1.3.1 through 2.3.1.3.5.

Pressure Boundary - Maintains integrity for the reactor coolant pressure boundary.

Flow Path - Provides an integral flow path for low pressure core injection (LPCI) flow into

the reactor vessel. It also provides a flow path for establishing the shutdown cooling

mode of operation.

Support ESF Function(s) - Provides signals and performs actions during a design basis

loss of coolant accident for correct selection of the unbroken recirculation loop and

closure of the recirculation system valves.

Credited in Regulated Event(s) - Required to enable hot shutdown and cold shutdown

during an Appendix R fire event and to provide trips of recirculation pumps to mitigate the

ATWS event. The system also contains components that are relied upon for

compliance with 10 CFR 50.49 (EQ).

Credited in Regulated Event(s) - Provides trip and initiation signals and process

information and indications credited in mitigation of the Appendix R fire, ATWS, and SBO

events. The system also contains components that are relied upon for compliance with 10 CFR

50.49, (EQ).

Preclude Adverse Effects on Safety-Related SSCs - Non-safety-related components that

could be a hazard to safety-related SSCs maintain sufficient integrity so that the

intended function of safety-related SSCs is not adversely affected.

Primary Containment Isolation - Provides containment isolation for those portions of the

system that interface with the primary containment.

Table 2.3.1-5 of the LRA identified the component groups requiring AMR. The component

groups which were identified for reactor recirculation system, recirculation flow control and M/G

sets include:

* Closure Bolting (includes flanges)

* Dampeners (Quad Cities only)

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* Dampeners (spatial interaction) (Quad Cities only)

* Filters/Strainers (spatial interaction) (Quad Cities only)

* Flow Elements

* NSR Vents or Drains, Piping and Valves (attached support) (Dresden only)

* Piping and Fittings

* Piping and Fittings (spatial interaction)

* Piping and Fittings (attached support)

* Piping and Fittings (small bore)

* Pumps

* Pumps (spatial interaction) (Quad Cities only)'

* Restricting Orifices (spatial interaction) (Quad Cities only)

* Sight Glasses (attached support)

* Sight Glasses (spatial interaction) (Quad Cities only)

* Tanks (spatial interaction) Quad Cities only)'

* Thermowells

* Tubing

* Tubing (spatial interaction) (Quad Cities only)

* Valves

* Valves (attached support)

* Valves (spatial interaction) (Quad Cities only)

Table 2.3.1-6 of the LRA identified the component groups requiring AMR. The component

groups identified for the reactor vessel head vent system include the following:

* closure bolting (includes flanges)

* NSR vents or drains, piping, and valves (attached support)

* piping and fittings

* piping and fittings (small bore)

* sight glasses (attached support, Dresden Ionly)

* tubing

* valves

Table 2.3.1-7 of the LRA identified the component groups requiring AMR. The component

groups which were identified for nuclear boiler instrumentation system include:

* Closure Bolting (includes flanges)

* Dampeners (Quad Cities only)

* Filters/Strainers (spatial interaction) (Dresden only)

* NSR Vents or Drains, Piping and Valves (attached support) (Dresden only)

* Pipes

* Piping and Fittings (attached support)

* Piping and Fittings (spatial interaction) (Dresden only)

* Piping and Fittings (Quad Cities only)

* Piping and Fittings (small bore)

'This component has been added to LRA Table 2.3.1-5 because of the applicant's revised methodology in

response to Open Item 2.1-1. Additional piping and components from the reactor recirculation system were added to

the scope of license renewal at Quad Cities due to the potential for spatial interaction with safety-related

components. This component is physically located in another location at Dresden, therefore, it is not in scope of

license renewal at the Dresden Station.

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* Tanks

* Thermowells

* Tubing

* Tubing (spatial interaction) (Quad Cities only)

* Tubing (attached support) (Quad Cities only)

* Valves

* Valves (spatial interaction)

* Valves (attached support)

Table 2.3.1-8 of the LRA identified the component groups requiring AMR. The component

groups which were identified for head spray system (Dresden only) include:

* Closure Bolting (includes flanges) (Dresden only)

* Flow Elements (attached support) (Dresden only)

* NSR Vents or Drains, Piping and Valves (attached support) (Dresden only)

* Piping and Fittings (Dresden only)

* Piping and Fittings (attached support) (Dresden only)

* Piping and Fittings (small bore) (Dresden only)

* Valves (Dresden only)

* Valves (attached support) (Dresden only)

Table 2.3.1-9 of the LRA identified the application sections where the additional reactor coolant

pressure boundary components were evaluated. The reactor coolant boundary components

evaluated in separate sections of the LRA include:

System Name Other Application Section That Contain

Reactor Coolant Pressure Boundary Components

High Pressure Coolant Injection System 2.3.2.1

Core Spray System 2.3.2.2

Reactor Core Isolation Cooling System (Quad Cities 2.3.2.4

only)

Isolation Condenser (Dresden only) 2.3.2.5

Residual Heat Removal System (Quad Cities 2.3.2.6

only)

Low Pressure Coolant Injection System 2.3.2.7

(Dresden only)

Standby Liquid Control System 2.3.2.8

Shutdown Cooling System (Dresden only) 2.3.3.2

Control Rod Drive Hydraulic System 2.3.3.3

Reactor Water Cleanup System 2.3.3.4

Main Steam System 2.3.4.1

Feedwater System 2.3.4.2

2.3.1.3.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.3, Dresden UFSAR Sections 5.4.1, 7.6.2, and 5.4.15, and

Quad Cities UFSAR Sections 5.4.1 and 7.6.2 to determine whether there is reasonable

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assurance that the reactor coolant system components within the scope of license renewal and

subject to an AMR have been identified in accordance with 10 CFR 54.4 and 54.21 (a)(1). The

staff's review was conducted in accordance with Section 2.3 of the SRP for License Renewal

(NUREG-1800) and is described as below.

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As part of

the evaluation, the staff determined whether the applicant had properly identified the SSCs

within the scope of license renewal and subject to an AMR, pursuant to 10 CFR 54.4(a) and 10

CFR 54.21 (a)(1). The staff reviewed the relevant portions of the UFSAR for the reactor vessel

internals and associated components and compared the information in the UFSAR with the

information in the LRA to identify those portions that the LRA did not identify as being within the

scope of license renewal and subject to an AMR. The staff then reviewed the structures and

components that were identified as not being within the scope of license renewal to verify that:

1. these structures and components do not have any of the intended functions delineated

under 10 CFR 54.4(a), and

2. for those structures and components that have an applicable intended function(s), verify

that they either perform this function(s) with moving parts or a change in configuration or

properties, or that they are subject to replacement based on a qualified life or specified

time period, as described in 10 CFR 54.21(a)(1).

The staff also reviewed the UFSAR for any function(s) delineated under 10 CFR 54.4(a) that

were not identified as intended function(s) in the LRA, to verify that the SSCs with such

function(s) will be adequately managed so that the function(s) will be maintained consistent with

the CLB for the extended period of operation.

After completing the initial review, the staff requested the applicant to provide additional

information on the reactor coolant system. By letter dated October 3, 2003 (Ref. 1), the

applicant responded to the staff's request for additional information (RAI) as discussed below:

In RAI 2.3.1.3-1, the staff requested the applicant to verify whether the pumps at Quad Cities

and/or Dresden, such as the recirculation pumps, are designed with lube motor-oil collection

systems, as required under 10 CFR 50, App. R, 1I1 0. If they are, please justify its exclusion

from aging management; otherwise, submit an AMR for the subject component. In response,

the applicant stated the reactor recirculation pumps at Quad Cities and Dresden are not

equipped with oil collection systems and do not need such systems to comply with 10 CFR 50,

App. R, III 0. 10 CFR 50, App. R, III 0 requires that the reactor coolant pump (reactor

recirculation pump at Quad Cities and Dresden) be equipped with an oil collection system if the

containment is not inerted during normal operation. The reactor recirculation pumps at Quad

Cities and Dresden are located in the drywell portions of the primary containment, which are

inerted during normal operation. The Quad Cities and Dresden Fire Hazards Analysis Reports

sections for Fire Zones 1.2.1 and 1.2.2 state that there is no design-basis fire postulated for the

drywell since the drywell atmosphere is inerted during normal reactor operation. Therefore,

there is no need to identify such a component in the LRA. Based on the above discussion, the

staff finds the applicant's assessment acceptable.

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Updated Final Safety Analysis Reports (UFSARs) for Dresden and Quad Cities do identify the

reactor vessel nozzles, safe ends, vessel shell attachments, and instrumentation penetrations

at these plants, but it is not clear whether all of these components are included in Table 2.3.1-1

of the LRA. In RAI 2.3.1.3-2, the staff requested the applicant to explicitly identify all of the

nozzles, safe ends, vessel shell attachments and instrumentation penetrations included in

Component Groups "Nozzles," "Nozzle Safe Ends' (including core delta P/SLC nozzle safe

end), "Vessel Shell attachment welds," and "Penetrations" (bottom head drain, CRD stub tubes,

incore instrument housings, jet pump instrumentation, other instrumentation, standby liquid

control), respectively. In response, the applicant identifies the individual components included

in the LRA Table 2.3.1-1. The following list Industry Component Type line items are as shown

in bolded and underlined text. In some cases generic components were created to represent a

population of components, as for example the CRD stub tubes. Also, there are nozzles

included in the component group, "Top Head Enclosure (Top Head Nozzles)." Therefore,

although not requested, the individual components for this group are also provided.

All the nozzles identified on page 3 of Quad Cities UFSAR Section 5, Appendix 5A, "Reactor

Vessel Report," and on page 11 of Dresden UFSAR Section 5, Appendix 5A, "Dresden 2

Reactor Vessel," are included in LRA Table 2.3.1-1 in the Component Groups of "Nozzles" and

"Penetrations."

Nozzles (Component Intended Function of Pressure Boundary)

Unit

01

Q1

Q1

Q1

Q1

Q1

Q2

Q2

Q2

02

Q2

Q2

D2

D2

D2

D2

D2

D2

D2

D3

D3

D3

D3

D3

D3

D3

Equip No.

1-0201-Ni

1-0201-N2

1-0201-N3

1-0201 -N4

1-0201-N5

1-0201 -N9

2-0201-Ni

2-0201 -N2

2-0201 -N3

2-0201 -N4

2-0201 -N5

2-0201 -N9

2-0201 -N1

2-0201 -N2

2-0201 -N3

2-0201 -N4

2-0201 -N5

2-0201 -N9

2-0201-N17

3-0201-Ni

3-0201 -N2

3-0201 -N3

3-0201-N4

3-0201-N5

3-0201 -N9

3-0201 -N 17

Equipment Name

Recirculation Outlet Nozzles

Recirculation Discharge Nozzles

Main Steam Nozzles

Feedwater Nozzles

Core Spray Nozzles

CRD Return Line Nozzles

Recirculation Nozzles

Recirculation Discharge Nozzles

Main Steam Nozzles

Feedwater Nozzles

Core Spray Nozzles

CRD Return Line Nozzles

Recirculation Nozzles

Recirculation Discharge Nozzles

Main Steam Nozzles

Feedwater Nozzles

Core Spray Nozzles

CRD Return Line Nozzles

Isolation Condenser Nozzles

Recirculation Suction Nozzles

Recirculation Discharge Nozzles

Main Steam Nozzles

Feedwater Nozzles

Core Spray Nozzles

CRD Return Line Nozzles

Isolation Condenser Nozzles

2-62
Nozzle Safe Ends (Component Intended Function of Pressure Boundary)

Unit

Q1

Q1

Q1

Q1

Q1

01

01

01

Q1

Q1

01

01

02

02

02

02

02

02

02

02

02

02

02

02

D2

D2

D2

D2

D2

D2

D2

D2

D2

D2

D2

D2

D2

D3

D3

D3

D3

D3

D3

D3

D3

D3

D3

Eauip No.

1-0201-Nl-SE

1-0201-N2-SE

1-0201 -N3-SE

1-0201-N4-SE

1-0201-N5-SE

1-0201 -N5-SEEXT

1-0201-N6B-SE

1-0201-N7-SE

2-0201 -N8-SE

1-0201 -N9-SE

1-0201-Ni 0-SE

1-0201-N11/12-SE

2-0201 -Ni -SE

2-0201 -N2-SE

2-0201-N3-SE

2-0201 -N4-SE

2-0201 -N5-SE

2-0201 -N5-SEEXT

2-0201 -N6B-SE

2-0201-N7-SE

2-0201 -N8-SE

2-0201-N9-SE

2-0201-Ni0-SE

2-0201-N1 1/12-SE

2-0201 -N1 -SE

2-0201 -N2-SE

2-0201 -N3-SE

2-0201-N4-SE

2-0201 -N5-SE

2-0201 -N5-SEEXT

2-0201 -N6B-SE

2-0201-N7-SE

2-0201-N8-SE

2-0201-N9-SE

2-0201-Ni0-SE

2-0201-N11/12-SE

2-0201-N17-SE

3-0201 -Ni -SE

3-0201-N2-SE

3-0201-N3-SE

3-0201-N4-SE

3-0201-N5-SE

3-0201-N5-SEEXT

3-0201 -N6B-SE

3-0201 -N7-SE

3-0201-N8-SE

3-0201 -N9-SE

Equipment Name

Recirculation Suction Nozzle Safe Ends

Recirculation Discharge Nozzle Safe Ends

Main Steam Nozzle Safe Ends

Feedwater Nozzle Safe Ends

Core Spray Nozzle Safe Ends

Core Spray Nozzle Safe End Extension

Vessel Head Instrumentation Nozzle Safe End

Vent Nozzle N7 Safe End

Jet Pump Instrumentation Nozzle Safe Ends

CRD Return Line Nozzle Safe End

Core Delta P & SLC Nozzle Safe Ends

Instrumentation Nozzle Safe Ends

Recirculation Suction Nozzle Safe Ends

Recirculation Discharge Nozzle Safe Ends

Main Steam Nozzle Safe Ends

Feedwater Nozzle Safe Ends

Core Spray Nozzle Safe Ends

Core Spray Nozzle Safe End Extension

Vessel Head Instrumentation Nozzle Safe End

Vent Nozzle N7 Safe End

Jet Pump Instrumentation Nozzle Safe Ends

CRD Return Line Nozzle Safe End

Core Delta P & SLC Nozzle Safe Ends

Instrumentation Nozzle Safe Ends

Recirculation Suction Nozzle Safe Ends

Recirculation Discharge Nozzle Safe Ends

Main Steam Nozzle Safe Ends

Feedwater Nozzle Safe Ends

Core Spray Nozzle Safe Ends

Core Spray Nozzle Safe End Extension

Vessel Head Instrumentation Nozzle Safe End

Vent Nozzle Safe End

Jet Pump Instrumentation Nozzle Safe Ends

CRD Return Line Nozzle Safe End

Core Delta P & SLC Nozzle Safe End

Instrumentation Nozzle Safe Ends

Isolation Condenser Nozzle Safe End

Recirculation Suction Nozzle Safe Ends

Recirculation Discharge Nozzle Safe Ends

Main Steam Nozzle Safe Ends

Feedwater Nozzle Safe Ends

Core Spray Nozzle Safe Ends

Core Spray Nozzle Safe End Extension

Vessel Head Instrumentation Nozzle Safe End

Vent Nozzle Safe End

Jet Pump Instrumentation Nozzle Safe Ends

CRD Return Line Nozzle Safe End

2-63
D3 3-0201-N1O-SE

D3 3-0201-Ni 1/12-SE

D3 3-0201-N17-SE

Core Delta P & SLC Nozzle Safe End

Instrumentation Nozzle Safe Ends

Isolation Condenser Nozzle Safe End

Vessel Shell Attachment Welds (Component Intended Function of Structural Support)

Generic Components were created for the attachment welds on each unit at each site:

Unit

Q1

Q2

D2

D3

Equip No.

1-0201 -LR037

2-0201 -LR037

2-0201 -LR037

3-0201 -LR037

Equipment Name

Attachment Welds

Attachment Welds

Attachment Welds

Attachment Welds

Penetrations (Component Intended Function of Pressure Boundary)

Unit Equip No.

Q1 1-0201-12

Q1 1-0201-LR038

Q1 1-0201-N8

Q1 1-0201-Nl0

Q1 1-0201-Ni 1/12

Q1 1-0201-N15

02 2-0201-12

Q2 2-0201 -LR038

02 2-0201-N8

Q2 2-0201-N10

Q2 2-0201-N1 1/12

Q2 2-0201 -N15

D2 2-0201-12

D2 2-0201 -LR038

D2 2-0201-N8

D2 2-0201 -N10

D2 2-0201-N1 1/12

D2 2-0201 -N15

D3 3-0201-12

D3 3-0201 -LR038

D3 3-0201-N8

D3 3-0201-Nl0

D3 3-0201-N11/12

D3 3-0201-N15

Penetrations (Control

Structural Support)

Equipment Name

Housing In-Core Penetrations

CRD Stub Tube Penetrations

Jet Pump Instrumentation Nozzle Penetrations

Core Delta P & SLC Nozzle Penetrations

Instrumentation Nozzle Penetrations

Bottom Head Drain Nozzle Penetrations

Housing In-Core Penetrations

CRD Stub Tube Penetrations

Jet Pump Instrumentation Nozzles Penetrations

Core Delta P & SLC Nozzle Penetrations

Instrumentation Nozzle Penetrations

Bottom Head Drain Nozzle Penetrations

Housing In-Core Penetrations

CRD Stub Tube Penetrations

Jet Pump Instrumentation Nozzle Penetrations

Core Delta P & SLC Nozzle Penetrations

Instrumentation Nozzle Penetrations

Bottom Head Drain Nozzle Penetrations

Housing In-Core Penetrations

CRD stub tube Penetrations

Jet Pump Instrumentation Nozzle Penetrations

Core Delta P & SLC Nozzle Penetrations

Instrumentation Nozzle Penetrations

Bottom Head Drain Nozzle Penetrations

Rod Drive Stub Tubes) (Component Intended Function of

Generic Components were created for the CRD stub tubes on each unit at each site:

Unit

Q1

02

D2

D3

Equip No.

1-0201 -LR038

2-0201 -LR038

2-0201 -LR038

3-0201 -LR038

Equipment Name

CRD Stub Tube Penetrations

CRD Stub Tube Penetrations

CRD Stub Tube Penetrations

CRD Stub Tube Penetrations

2-64
Top Head Enclosure (Top Head Nozzles) (Component Intended Function of Pressure

Boundary)

Unit Equip No. Equipment Name

Q1 1-0201-N6B Vessel Head Instrumentation Nozzle

Q1 1-0201-N7 Vent Nozzle N7

Q2 2-0201 -N6B Vessel Head Instrumentation Nozzle

Q2 2-0201 -N7 Vent Nozzle N7

D2 2-0201 -N6B Vessel Head Instrumentation Nozzle

D2 2-0201 -N7 Vent Nozzle

D3 3-0201-N6B Vessel Head Instrumentation Nozzle

D3 3-0201 -N7 Vent Nozzle

Based on the above discussion, the staff finds the applicant's assessment acceptable.

One of the intended functions of the main steam line flow restrictors is to limit steam line flow

during a steam line rupture outside of primary containment until the MSIVs [main stream

isolation valves] can close, thereby limiting potential radioactive release. Over the extended life

of the plant, it is therefore essential to maintain the flow area of the flow restrictors used in the

CLB [current licensing basis] to calculate the amount of steam released. The staff believes that

erosion/corrosion due to high energy steam flow can eventually increase this flow area beyond

the value used in the CLB. In RAI 2.3.1.3-3, the staff requested the applicant to provide the

following information:

a) Are the main steam line flow restrictors, and their flow restriction function, within scope? If

not, please explain why not.

b) If in scope, how will the applicant determine that the flow area does not exceed more than

the value used in the CLB, so that the intended functions will be maintained consistent with

the CLB for the period of extended operation?

The applicant provided the following response:

a) The main steam line flow restrictors are within the scope of license renewal. They are listed

as components in two line items in LRA Table 2.3.4-1 because they have two intended

functions. They are included in the component group "Flow Elements," with a component

intended function of "Pressure Boundary." They are also included in the component group

"Flow Elements," with a component intend6d function of "Throttle."

b) The main steam line flow restrictors are constructed of an external carbon steel pipe

segment, with an internal venturi-type flow element welded into it. The venturi flow element

is comprised of stainless steel.

The entry in the LRA Table 2.3.4-1 Component Group "Flow Elements," with a component

intended function of 'Pressure Boundary" is for the carbon steel pipe segment that comprises

the pressure boundary. The LRA Chapter 3 Aging Management References are 3.1.1.11 and

3.4.2.6. The internal aging effect/aging mechanism is wall thinning due to flow-accelerated

corrosion, and is managed by the flow-accelerated corrosion program, as described in LRA

Appendix B, Section B.1.1 1. The external environment for the pipe segment is "containment

nitrogen," and there are no identified aging effects/aging mechanisms for this environment.

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The entry in the Component Group 'Flow Elements," with a component intended function of

'Throttle" is for the internal stainless steel venturi-type flow element. The LRA Chapter 3 Aging

Management Reference is 3.1.1.15. The aging effect/aging mechanism is crack initiation and

growth due to SSCS, IGSCC. It is managed by the BWR stress corrosion cracking program as

described in LRA Appendix B, Section B.1.7, and by the water chemistry program as described

LRA Appendix B, Section B.1.2. EPRI 1003056, "Non-Class 1 Mechanical Implementation

Guideline and Mechanical Tools," Appendix A - Treated Water, Section 3.1.6, states that

stainless steels used in treated water environments are resistant to FAC.

Based on this discussion, the staff finds the above applicant's assessment acceptable.

The staff did not identify any omissions.

2.3.1.3.3 Conclusions

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether any structures, systems, or components that should be within the scope of license

renewal were not identified by the applicant. The staff did not identify any omissions. In

addition, the staff performed an independent assessment to determine whether any

components that should be subject to an AMR were not identified by the applicant. The staff

did not identify any omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the reactor coolant system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

that the applicant has adequately identified the reactor coolant system components that are

subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.1.4 Evaluation Findings

On the basis of its review, the staff concludes that there is reasonable assurance that the

applicant has adequately identified the reactor coolant systems and components that are within

the scope of license renewal, in accordance with the requirements of 10 CFR 54.4(a), and that

the applicant has adequately identified the reactor coolant system components that are subject

to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).

2.3.1.5 References

1. Letter from Patrick R. Simpson (Exelon) to the NRC, "Additional Information for the Review

of the License Renewal Applications for Quad Cities Nuclear Power Station, Units 1 and 2

and Dresden Nuclear Power Station, Units 2 and 3," October 3, 2003 (Accession No.

ML032810692).

2. Letter from Patrick R. Simpson (Exelon) to the NRC, 'Additional Information for the Review

of the License Renewal Applications for Quad Cities Nuclear Power Station, Units 1 and 2

and Dresden Nuclear Power Station, Units 2 and 3," October 3, 2003 (Accession No.

ML032810563).

3. Letter from Patrick R. Simpson (Exelon) to the NRC, "Follow-up Response to License

Renewal Safety Evaluation Report for the Dresden and Quad Cities Nuclear Power

Stations," June 6, 2004 (Accession No. ML041820207).

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2.3.2 Engineered Safety Features Systems

2.3.2.1 High-Pressure Coolant Injection System

2.3.2.1.1 Summary of Technical Information in the Application

The applicant described the high-pressure coolant injection (HPCI) system in LRA Section

2.3.2.1 and provided a list of components subject to an AMR in LRA Table 2.3.2-1.

The HPCI system ensures that adequate core cooling takes place for all break sizes less than

those sizes for which the low-pressure coolant injection or core spray subsystems can

adequately protect the core. Operation of the HPCI system in the emergency mode is

completely independent of alternating current (ac) power.

The HPCI system consists of a steam turbine driving a multi-stage high-pressure main pump

and a gear driven single-stage booster pump, piping, auxiliary support systems, and

instrumentation. The turbine is driven by nuclear steam and exhausts to the suppression

chamber (evaluated with the primary containment structure). The preferred water source to the

HPCI booster pump suction is supplied from the condensate storage system (evaluated with the

condensate and condensate storage system), with a backup source from the suppression

chamber. Water from the HPCI main pump is delivered to the reactor vessel (evaluated with the

reactor vessel) through the "B" feedwater line (evaluated with the feedwater system) and

distributed within the reactor vessel through the feedwater sparger (evaluated with reactor

internals). The system is equipped with a test line to the condensate storage system to permit

functional testing and a minimum flow bypass line to the suppression chamber for pump

protection.

Intended functions within the scope of license renewal include the following:

* core cooling-provides cooling water to the reactor vessel during loss of coolant (LOCA)

conditions that do not result in rapid depressurization of the reactor pressure vessel and

provides coolant inventory makeup in non-LOCA events

* pressure control-provides pressure control in events where the main steam isolation

valves are closed

* pressure boundary-maintains the integrity of the reactor coolant pressure boundary

* primary containment isolation-provides containment isolation for those portions of the

system that interface with the primary containment

* credited in regulated event(s)-provides core makeup, cooling, and pressure control

credited in mitigation of the Appendix R fire, ATWS, and SBO events; also contains

components that are relied upon for compliance with 10 CFR 50.49 (EQ)

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected

2-67
Table 2.3.2-1 of the LRA identified the component groups requiring AMR. The component

groups identified for HPCI include:

* closure bolting

* dampeners (Quad Cities only)

* diffusers

* filters/strainers (includes separators, pressure boundary)

* filters/strainers (includes separators, filter)

* flexible hoses

* flow orifices

* heat exchangers (includes condensers, pressure boundary)

* heat exchangers (includes condensers, heat transfer)

* NSR vents or drains, piping, and valves (attached support)

* piping and fittings (includes thermowells)

* piping and fittings (attached support)

* piping and fittings (small bore)

* pumps

* restricting orifices (pressure boundary)

* restricting orifices (throttle)

* restricting orifices (attached support)

* rupture discs

* sight glasses (attached support)

* sight glasses (Quad Cities only)

* tanks

* thermowells

* traps

* tubing

* tubing (attached support)

* turbine casings

* valves

* valves (attached support)

2.3.2.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.1, Dresden UFSAR Sections 6.3.1 and 6.3.2, and Quad

Cities UFSAR Sections 6.3.1 and 6.3.2 to determine whether there is reasonable assurance

that the HPCI system components within the scope of license renewal and subject to an AMR

have been identified in accordance with 10 CFR 54.4 and 54.21 (a)(1). The staff's review was

conducted in accordance with Section 2.3 of the SRP for License Renewal (NUREG-1800) and

is described below.

In performing the review, the staff selected system functions described in the UFSAR that were

set forth in 10 CFR 54.4 to verify that components having intended functions were not omitted

from the scope of the Rule. The staff also focused on components that were not identified as

being subject to an AMR to determine if any components were omitted. As part of the

evaluation, the staff determined whether the applicant had properly identified the SSCs within

the scope of license renewal and subject to an AMR, pursuant to 10 CFR 54.4(a) and 10 CFR

54.21 (a)(1). The staff reviewed the relevant portions of the UFSAR for the reactor vessel and

associated components and compared the information in the UFSAR with the information in the

LRA to identify those portions that the LRA did not identify as being within the scope of license

2-68
renewal and subject to an AMR. The staff then reviewed the SCs that were identified as not

being within the scope of license renewal to verify that (1) these structures and components do

not have any of the intended functions delineated under 10 CFR 54.4(a), and (2) for those

structures and components that have an applicable intended function(s), verify that they either

perform this function(s) with moving parts or a change in configuration or properties, or that

they are subject to replacement based on a qualified life or specified time period, as described

in 10 CFR 54.21 (a)(1).

The staff also reviewed the UFSAR for any functions delineated under 10 CFR 54.4(a) that

were not identified as intended functions in the LRA, to verify that the SSCs with such functions

will be adequately managed so that the functions will be maintained consistent with the CLB for

the extended period of operation.

2.3.2.1.3 Conclusions

The staff reviewed LRA Section 2.3.2.1 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. The

staff did not identify any omissions. On the basis of its review, the staff concludes that the

applicant has adequately identified the components of the HPCI system that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the HPCI system that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.2.2 Core Spray System

2.3.2.2.1 Summary of Technical Information in the Application

The applicant described the core spray (CS) system components in LRA Section 2.3.2.2 and

provides a list of components subject to an AMR in LRA Table 2.3.2-2.

The CS system provided core cooling for intermediate and large line break sizes. Two

independent CS loops are provided to ensure adequate core cooling. Each CS loop is designed

to operate in conjunction with LPCI and either the automatic depressurization system or highpressure coolant injection system to provide adequate core cooling over the entire spectrum of

liquid or steam break sizes.

The CS system consists of two independent loops, each with a motor-driven pump, associated

piping, valves, and instrumentation. The normal water source is supplied from the suppression

chamber (evaluated with the primary containment structure). An alternate water source is the

condensate storage system (evaluated with the condensate and condensate storage system).

The CS system delivers water directly to the reactor vessel (evaluated with the reactor vessel)

onto the top of the fuel assemblies through the CS spargers (evaluated with reactor internals).

Each CS loop is equipped with a test return line to the suppression chamber to permit functional

testing and a minimum flow bypass line to the suppression chamber for pump protection.

Intended functions within the scope of license renewal include the following:

pressure boundary-maintains the integrity of the reactor coolant pressure boundary

2-69
* core cooling-in conjunction with LPCI and either automatic depressurization or highpressure coolant injection, provides emergency core cooling for the entire spectrum of

postulated design-basis LOCAs

* primary containment isolation-provides containment isolation for those portions of the

system that interface with the primary containment

* supports ESF function(s)-provides an ECCS keep fill subsystem which maintains core

spray and LPCI piping full of water to support a condition of standby readiness

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected

* credited in regulated event(s)-contains components that are relied upon for compliance

with 10 CFR 50.49 (EQ)

Table 2.3.2-2 of the LRA identified the component groups requiring AMR. The component

groups identified for CS include the following:

* closure bolting

* flow elements (pressure boundary)

* flow elements (throttle)

* NSR vents or drains, piping, and valves (attached support)

* piping and fittings

* piping and fittings (attached support)

* pumps

* restricting orifices (pressure boundary

* restricting orifices (throttle)

* sight glasses (attached support)

* thermowells

* tubing

* tubing (attached support, Quad Cities only)

* valves

* valves (attached support)

2.3.2.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.2, Dresden UFSAR Sections 6.3.1 and 6.3.2, and Quad

Cities UFSAR Sections 6.3.1 and 6.3.2 to determine whether there is reasonable assurance

that the components of the CS system within the scope of license renewal and subject to an

AMR have been identified in accordance with 10 CFR 54.4 and 54.21 (a)(1). The staff's review

was conducted in accordance with Section 2.3 of the SRP for License Renewal (NUREG-1 800)

and is described below.

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As part of

2-70
the evaluation, the staff determined whether the applicant had properly identified the SSCs

within the scope of license renewal and subject to an AMR, pursuant to 10 CFR 54.4(a) and

10 CFR 54.21 (a)(1). The staff reviewed the relevant portions of the UFSAR for the reactor

vessel and associated components and compared the information in the UFSAR with the

information in the LRA to identify those portions that the LRA did not identify as being within the

scope of license renewal and subject to an AMR. The staff then reviewed the structures and

components that were identified as not being within the scope of license renewal to verify that

(1) these structures and components do not have any of the intended functions delineated

under 10 CFR 54.4(a), and (2) for those structures and components that have an applicable

intended function(s), verify that they either perform this function(s) with moving parts or a

change in configuration or properties, or that they are subject to replacement based on a

qualified life or specified time period, as described in 10 CFR 54.21 (a)(1).

The staff also reviewed the UFSAR for any functions delineated under 10 CFR 54.4(a) that

were not identified as intended functions in the LRA, to verify that the SSCs with such functions

will be adequately managed so that the functions will be maintained consistent with the CLB for

the extended period of operation.

After completing the initial review, the staff requested the applicant to provide additional

information on the CS system. By letter dated October 3, 2003 (Ref. 1), the applicant

responded to the staff's RAI as discussed below.

High-radiation sampling system piping and liquid sampling flow diagram LR-QDC-M-1061-1

does not include check valve 2-1402-71 within the scope of license renewal. This valve

prevents the backf low of water from the ESS fill pump discharge line back to the condensate

transfer pump supply line. Failure of this valve could prevent the ESS fill pump system from

supporting its intended ESF function. In RAI 2.3.2.2-1, the staff requested the applicant to

,explain why this component is not within the scope of the license renewal program. In

response, the applicant stated that valve 2-1402-71 is included within the scope of license

renewal and is subject to AMR. Boundary diagram LR-QDC-M-78 (coordinate E-7) includes

valve 2-1402-71 as within the scope of license renewal requiring AMR. Check Yalve 2-1402-70

(not shown on LR-QDC-M-1061-1) serves as the safety-related pressure boundary that

prevents the backflow of water from the ECCS keep fill pump discharge line from entering the

condensate transfer system. Valve 2-1402-71 is addressed in Table 2.3.2-2 under the

component group "valves (attached support)."

Valve 2-1402-70 is addressed in Table 2.3.2-2, under the component group "valves". Highradiation sampling system piping and liquid sampling boundary diagram, LR-QDC-1 061-1, is a

continuation boundary diagram where valve 2-1402-71 is shown as a dotted line for information

only. The ECCS keep fill pump system intended function is therefore not jeopardized.

Boundary diagram LR-QDC-1 061-1 should have highlighted check valve 2-1402-70 indicating

that it falls within the scope of license renewal. Based on this discussion, the staff finds the

applicant's assessment acceptable.

Demineralized water system flow diagram LR-DRE-M-366 does not include the suction line,

3-3329-A-B-L, and suction isolation valve, 3-3329-A-500, for condensate makeup pump

3-3318-B within the scope of license renewal. Failure of these system boundary components

could prevent the demineralized water system from performing its ESF function. In RAI 2.3.2.2-

2, the staff requested the applicant to explain why these components are not within the scope

of the license renewal program. In response, the applicant stated that Exelon has reviewed the

2-71
demineralized water system boundary diagram LR-DRE-M-366 for Dresden and the following

clarification is provided:

Demineralized water system boundary diagram LR-DRE-M-366 should have highlighted suction line,

3-3329-A-8-L, and suction isolation valve, 3-3329-A-500, forcondensate make-up pump 3-3318-A and

included those components within the scope of license renewal. The suction line and the suction

isolation valve are included in the scope of license renewal and are subject to AMR. The suction

piping and isolation valve are addressed in LRA Section 2.3.4.3, Table 2.3.4-3 under the Component

Groups"Piping and Fittings' and Valves". Aging Management Reference 3.4.1.3 discusses the aging

management of the suction piping and isolation valve external surfaces as a carbon steel component.

Aging Management References 3.4.1.2 and 3.4.1.4 discuss the aging management of the suction

piping and isolation valve internal surfaces.

Based on this discussion, the staff finds the applicant's assessment acceptable.

2.3.2.2.3 Conclusions

The staff reviewed Section 2.3.2.2 of the LRA and the accompanying scoping boundary

drawings to determine whether any SSCs within the scope of license renewal had not been

identified by the applicant. In addition, the staff performed an independent assessment to

determine whether any components that should be subject to an AMR were not identified by the

applicant. The staff did not identify any omissions. On the basis of its review, the staff

concludes that the applicant has adequately identified the components of the CS system that

are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant

has adequately identified the components of the CS system that are subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

2.3.2.3 Containment Isolation Components and Primary Containment Piping System

2.3.2.3.1 Summary of Technical Information in the Application

The applicant described the containment isolation components and primary containment piping

system in LRA Section 2.3.2.3 and provided a list of components subject to an AMR in LRA

Table 2.3.2-3.

The containment isolation components and primary containment piping system is a composite

support system for the primary containment structure. The containment isolation components

and primary containment piping system comprises primary containment isolation valves,

penetrations, and piping from non-safety-related systems that perform no intended function

except primary containment isolation. It also includes safety-related piping, components, and

instrumentation that directly support intended functions of the primary containment structure

and that are not assigned to other systems in the scope of license renewal. The containment

isolation components and primary containment piping system ensures that the primary

containment structure can perform its intended functions.

Using the methodology described in LRA Section 2.1.4.1 for identifying the mechanical

components within the scope of license renewal, the applicant identified the following intended

functions of the containment isolation components and primary containment piping system:

* primary containment isolation-provides functions that support isolation

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* pressure suppression-provides functions that support absorption of energy by containment

air and water volumes

* containment integrity-provides vacuum relief between drywell, suppression chamber, and

reactor building

* preclude adverse effects on safety-related SSCs

* credited in regulated events-components relied upon for compliance with 10 CFR 50.49

(EQ)

In the event of a nuclear steam supply system piping failure within the drywell (evaluated with

the primary containment structure), reactor water and/or steam would be released into the

drywell. The resulting increased drywell pressure would force a mixture of radioactive

materials, noncondensible gases, steam, and water through the connecting vent lines into the

chamber of water in the suppression chamber, which is also called the torus (evaluated with the

primary containment structure). The steam would condense rapidly and completely in the

suppression chamber resulting in suppression of the pressure increase in the drywell. During

this period, the primary containment and suppression chamber piping isolation valves are relied

upon to ensure the containment of these gases and liquids.

The containment isolation components and primary containment piping system consists of:

primary containment pressure instruments; suppression chamber to reactor building vacuum

breaker lines; purge supply and exhaust penetrations (HVAC-primary containment);

suppression chamber level instrumentation penetrations; local leak-rate test (LLRT)

penetrations; and containment isolation barriers from the traversing in-core probe, drywell

equipment and floor drain sumps, atmospheric containment air dilution (ACAD), service air, and

instrument air systems. All associated piping, components, and instrumentation contained

within the flow paths and systems described above are included in the primary containment and

suppression chamber piping system evaluation boundary.

In LRA Section 2.3.2.3, the applicant described the evaluation boundary of the containment

isolation components and primary containment piping system. In addition, the applicant

highlighted those portions of the system and its structures and components that are within the

scope of the Rule in the P&lDs listed as references in LRA Section 2.3.2.3. Also, based on the

methodology described in LRA Section 2.1.5 for identifying the mechanical components subject

to an AMR, the applicant identified the following component groups and their intended functions

within the containment isolation components and primary containment piping system in LRA

Table 2.3.2.3 as being within the scope of license renewal and subject to an AMR:

* closure bolting (pressure boundary)

* flexible hoses and flow elements (pressure boundary, Quad Cities only)

* isolation barriers including piping, tubing, valves, and vacuum breakers (pressure boundary)

* isolation barriers-attached support including piping and valves (structural integrity)

* NSR vents or drains, piping, and valves (structure integrity/attached support)

* piping and fittings (structure integrity/attached support)

* piping and fittings (pressure boundary)

* restricted orifices (pressure boundary, Dresden only)

* tanks including drain pot (pressure boundary)

* thermowells (pressure boundary, Dresden only)

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* tubing (pressure boundary)

2.3.2.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.3, Dresden UFSAR Section 6.2.1, and Quad Cities

UFSAR Section 6.2.1 to determine whether there is reasonable assurance that the components

of the containment isolation components and primary containment piping system within the

scope of license renewal and subject to an AMR have been identified in accordance with

10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff review was conducted in accordance with

Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the containment isolation components and primary containment

piping system in the LRA. The staff did not identify any omissions.

Also, the staff selected system functions described in the UFSARs that were set forth in

10 CFR 54.4 to verify that components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the containment isolation components

and primary containment piping system that are within the scope of license renewal and subject

to an AMR in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1), respectively, the staff

compared the referenced P&lDs to the system drawings and system descriptions in the

UFSARs to ensure that the referenced P&lDs were representative of the containment isolation

components and primary containment piping system. The staff then reviewed the referenced

P&lDs to verify that those portions of the containment isolation components and primary

containment piping system that meet the scoping requirements of 10 CFR 54.4 are included

within the scope of license renewal and are identified as such by the applicant in LRA Section

2.3.2.3, and that the applicant identified all system components within the scope of license

renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.2.3 identified areas in which additional information is

necessary to complete the staff's review of the applicant's scoping and screening results.

Therefore, by letter on August 4, 2003, the staff issued RAls to the applicant concerning

specific items to determine whether the applicant has properly applied the scoping and

screening criteria of 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's RAls and the applicant's

responses, dated October 3, 2003, are described below.

RAI 2.3.2.3-1. On instrument air piping diagram LR-QDC-M-24-12, line 1-47209-1' is shown

within the scope of the containment isolation components (primary containment (PC)) system

that requires an AMR because it provides a safety-related pressure-retaining function. Lines 1-

47692-1 and 1-4315A which are connected to line 1-470209-1 are not shown in the PC system

to require an AMR. Similarly for Unit 2, lines 2-47692, 2-4315A, and 2-47209A which are

connected to line 2-470209 on diagram LR-QDC-M-71-7 are not shown in the PC system to

require an AMR. The staff asked the applicant to provide an AMR for these components or

provide a justification for excluding these components from an AMR.

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Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.2.3-1 stated that those portions of instrument air lines 1-

47209-1 "-T and 2-47209-1 "-T shaded in red on boundary diagrams LR-QDC-M-24-12 and LRQDC-M-71-7 are non-safety-related. These lines are attached to safety-related portions of lines

147209-1 "-T and 2-47209-1"-T, as shown on boundary diagrams LR-QDC-M-24-13 and LRQDC-M-71-8. Those portions of the lines colored in red provide structural support to the safetyrelated portions of piping colored in green. The non-safety-related piping and components and

components on lines 1-47209-1"-T and 2-47209-1"-T extend up to the first support in each of

the three orthogonal directions. A failure in lines 1-47692-1 1/4", 1-4315A-1/4"-L, 2-47692-1

1/4", or 2-4315A-1/4"-L would not have any impact on the structural integrity of the safetyrelated piping and components. Additionally, failure of these lines would not impact the

intended function of any safety-related systems. Safety-related valves that rely upon instrument

air fail in the safe position. Therefore, these lines are not within the scope of license renewal

and do not require an AMR.

Based on its review, the staff concurs with the applicant's clarification that a failure in the

above-cited instrument air lines would not have any impact on the structural integrity of the

safety-related piping and components and the intended function of any safety-related systems.

In accordance with criteria set forth in 10 CFR 54.4, these lines are not within the scope of

license renewal and do not require an AMR. Therefore, the staff finds the applicant's

response to RAI 2.3.2.3-1 acceptable and considers its concern described in RAI 2.3.2.3-1

resolved.

RAI 2.3.2.3-2. Instrument air piping diagram LR-QDC-M-24-13 does not show boundary breaks

between PC system components that may require an AMR and instrument air (IA) components.

The staff asked the applicant to identify the PC system component boundary breaks and to

identify where the LRA addresses the AMR for these components or provide a justification for

excluding these components from an AMR.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.2.3-2 stated that all of the piping and piping components

colored in red and green on boundary diagram LR-QDC-M-24-13 have been included within the

scope of license renewal and require an AMR. These components were evaluated within the

PC system boundary. All components highlighted in green are safety-related. All components

highlighted in red are non-safety-related components attached to safety-related components

providing structural support. The non-safety-related components providing structural support

include all components up to the first support in each of the three orthogonal directions.

Therefore, portions of piping highlighted in red end abruptly at some locations. Piping and

piping components that are colored in black are IA system components that are not included

within the scope of license renewal and do not require an AMR. Instrument air boundary

diagram LR-QDC-M-24-13 should have been corrected to include the boundary flags

designating breaks between PC system components and IA system components. Those

components that are highlighted in green and red are included in LRA Table 2.3.2-3 as being

within the scope of license renewal and subject to an AMR.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.2.3-2 acceptable because the applicant clearly identified the PC

system component boundary breaks, and the piping and components that are within the scope

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of license renewal are included in LRA Table 2.3.2-3 as subject to an AMR. Therefore, the staff

considers its concern described in RAI 2.3.2.3-2 resolved.

RAI 2.3.2.3-3. On diagram LR-QDC-M-71 -8, line 2-47209-1" (E-7) and line 2-4700-2" (D-10)

are shown within the scope of PC system components that require an AMR because they

provide a safety-related pressure-retaining function. Lines 2-47775 and 2-47498 which are

connected to lines 2-47209 and 2-4700 are not in the PC system requiring an AMR. The staff

asked the applicant to identify where the LRA addresses the AMR for these components or to

provide a justification for excluding these components from an AMR.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.2.3-3 stated that those portions of lines 2-47209-1" and

2-4700-2" shown on boundary diagram LR-QDC-M-71-8 that are highlighted in green are

safety-related and provide a pressure-retaining function. The safety-related boundary

pressure-retaining boundary ends at valves 2-4721 and 2-4799-156. Those portions of lines 2-

47209-1" and 2-4700-2" highlighted in red are not safety-related and provide structural support

for the safety-related portions of pipe. All components highlighted in green and red are

included within the scope of license renewal and require aging management. The non-safetyrelated portions of piping falling within the scope of license renewal extended up to the first

support in each of the three orthogonal directions. Therefore, the red highlighted lines appear

to end abruptly. Field walkdowns performed by Exelon identified those structural interactions

with the safety-related components that can affect the ability of SSCs to perform their intended

functions. Failure of lines 2-47775-1/2" and 2-47498-3/4" would not have any impact on the

structural integrity (interaction or attached) of the safety-related piping and components.

Additionally, failure of these lines would not impact the intended function of any safety-related

systems. Safety-related valves reliant upon instrument air fail in the safe position. Thus, these

lines were not included within the scope of license renewal and do not require an AMR.

Based on its review, the staff concurs with the applicant's clarification that failure of lines

2-47775-1/2" and 2-47498-3/4" would not have any impact on the structural integrity of the

safety-related piping and components and the intended function of any safety-related systems.

In accordance with criteria set forth in 10 CFR 54.4, these lines are not within the scope of

license renewal and do not require an AMR. Therefore, the staff finds the applicant's response

to RAI 2.3.2.3-3 acceptable and considers its concern described in RAI 2.3.2.3-3 resolved.

RAI 2.3.2.3-4. On liquid sampling system diagrams LR-QDC-M-1056-1 and LR-QDC-M-1061-

1, boundary breaks between PC system components that require an AMR and other system

components are not shown. The staff asked the applicant to identify the PC system component

boundary breaks and identify where the LRA addresses the AMR for these components or

provide a justification for excluding these components from an AMR.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.2.3-4 stated that piping and piping components shown on

boundary diagram LR-QDC-M-1056-1 highlighted in red or green fall within the scope of license

renewal and require aging management. Those portions of pipe highlighted in red and green

have been evaluated under various systems. For example, those portions of piping shown at

locations B-7 and C-6 (includes valves 1-2099-417 and 1-2099-500) were evaluated with the

PC system. These two stretches of pipe are bounded by high-radiation sampling system piping

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that falls outside the scope of license renewal. Those portions of pipe highlighted in red at

location G-9 on boundary diagram LR-QDC-M-1056-1 (includes valve 1-8941-701) were

evaluated with the reactor recirculation system. Those components highlighted in red are not

safety-related but provide structural support to safety-related reactor recirculation system

piping. Finally, those portions of pipe highlighted in green and red at location D-9 on boundary

diagram LR-QDC-M-1 056-1 (includes valve 1-1402-69) fall within the scope of license renewal

and require aging management. Those components were evaluated with the core spray

system and are bounded by high-radiation sampling system piping that falls outside the scope

of license renewal. The piping highlighted in green is safety-related, and the piping highlighted

in red is not safety-related but provides structural support to the safety-related pipe that is

attached.

Piping and piping components shown on boundary diagram LR-QDC-M-1061-1 highlighted in

red or green fall within the scope of license renewal and require aging management. Those

portions of pipe highlighted in red and green have been evaluated under various systems. For

example, those portions of piping shown at locations B-7 and C-6 (includes valves 2-2099-649

and 2-2099-394) were evaluated with the PC system. These two stretches of pipe are bounded

by high-radiation sampling system piping that falls outside the scope of license renewal. Those

portions of pipe highlighted in red at location G-9 on boundary diagram LR-QDC-M-1061-1

(includes valve 2-8941-721) were evaluated with the reactor recirculation system. Those

components highlighted in red are not safety-related but provide structural support to safetyrelated reactor recirculation system piping. Finally, those portions of pipe highlighted in green

and red at location D-9 on boundary diagram LR-QDC-M-1061-1 (includes valve 2-1402-69) fall

within the scope of license renewal and require aging management. Those components were

evaluated with the core spray system. These components are bounded by high-radiation

sampling system piping that falls outside the scope of license renewal. The core spray system

piping highlighted in green is safety-related, and the piping highlighted in red is not safetyrelated but provides structural support to the safety-related pipe that is attached.

Table 2.3.2-3 includes those components evaluated within the PC system boundary. Table

2.3.1.3-5 includes those components evaluated within the reactor recirculation system

boundary. Table 2.3.2-2 includes those components evaluated within the core spray system

boundary. Boundary diagrams LR-QDC-M-1056-1 and LR-QDC-M-1061-1 should have

included the appropriate system boundary flags.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.2.34 acceptable because the applicant clearly identified the PC

system component boundary breaks; the piping and components that are within the scope of

license renewal and are evaluated within the PC system boundary are included in LRA Table

2.3.2-3 subject to an AMR; and the piping and components that are evaluated within the reactor

recirculation system boundary are included in LRA Table 2.3.1.3-5. Therefore, the staff

considers its concern described in RAI 2.3.2.3-4 resolved.

RAI 2.3.2.3-5. On radwaste ventilation diagram LR-DRE-M-272, boundary breaks between PC

and RW system components are shown at location A-10, but no component in the PC system is

shown to require an AMR. The staff asked the applicant to identify the PC system components

on the above drawing and to identify where the LRA addresses the AMR for these components

or provide a justification for excluding these components from an AMR.

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Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.2.3-5 stated that the components shown on boundary

diagram LR-DRE-M-272 at coordinate A-9 were evaluated with the PC system and are

connected to piping that is continued on the same diagram at coordinate F-3. This portion of

non-safety-related piping is a continuation of piping from drawings LR-DRE-M-356

(coordinate A-1) and LR-DRE-M-25 (coordinate B-1). As shown on boundary diagrams LRDRE-M-25 (B-1) and LR-DRE-M-356 (A-1), the PC system piping highlighted in green is safetyrelated and provides a pressure-retaining function. Those portions of lines 2-1656-10" and 3-

1656-10" highlighted in red on boundary diagrams LR-DRE-M-25 (B-1) and LR-DRE-M-356 (A1) are not safety-related and provide structural support for the safety-related portions of pipe

colored in green. The non-safety-related pipe colored in red falls within the scope of license

renewal and extends up to the first support in each of the three orthogonal directions. The

piping continues beyond the first seismic anchor on diagrams LR-DRE-M-25 and LR-DRE-M356 and continues on to boundary diagram LR-DRE-M-272. The purpose of the boundary flags

on boundary diagram LR-DRE-M-272 is to identify the extent of the PC system boundary.

Failure of piping and piping components shown on boundary diagram LR-DRE-M-272 would not

have any impact on the structural integrity or intended function of the safety-related piping and

components in the PC system. As such, the PC system components on boundary diagram

LR DRE-M-272 were not included within the scope of license renewal and do not require an

AMR.

Based on its review, the staff concurs with the applicant's clarification that failure of PC system

piping and piping components shown on boundary diagram LR-DRE-M-272 would not have any

impact on the structural integrity of the safety-related piping and components and the intended

function of any safety-related systems. In accordance with criteria set forth in 10 CFR 54.4,

PC system piping and piping components shown on boundary diagram LR-DRE-M-272 are not

within the scope of license renewal and do not require an AMR. Therefore, the staff finds the

applicant's response to RAI 2.3.2.3-5 acceptable and considers its concern described in RAI

2.3.2.3-5 resolved.

2.3.2.3.3 Conclusions

The staff reviewed LRA Section 2.3.2.3, the accompanying scoping boundary drawings and the

applicant's response to RAls dated October 3, 2003, to determine whether any SSCs within the

scope of license renewal had not been identified by the applicant. In addition, the staff

performed an independent assessment to determine whether any components that should be

subject to an AMR were not identified by the applicant. The staff did not identify any omissions.

On the basis of its review, the staff concludes that the applicant has adequately identified the

components of the containment isolation components and primary containment piping systems

that are within the scope of license renewal, as required by 10 CFR 54.4, and that the applicant

has adequately identified the components of the containment isolation components and primary

containment piping systems that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.2.4 Reactor Core Isolation Cooling System-Quad Cities Only

2.3.2.4.1 Summary of Technical Information in the Application

The applicant described the reactor core isolation cooling (RCIC) system components in LRA

Section 2.3.2.4 and provided a list of components subject to an AMR in LRA Table 2.3.2-4.

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The RCIC system at Quad Cities provides cooling water to the reactor core in the event of a

postulated isolation of the reactor from the main condenser with a loss of reactor feedwater.

The RCIC system consists of a steam turbine-pump unit, piping, associated valves, auxiliary

support systems, and instrumentation. The turbine is driven by nuclear steam supplied from the

A" main steam line on Unit 1 and from the "D" main steam line on Unit 2 (evaluated with main

steam) and exhausts to the suppression chamber (evaluated with the primary containment

structure), below the water line. All steam leakage from valve packing and the turbine shaft

seals is routed to and condensed in the barometric condenser. The preferred water source to

the RCIC pump suction is supplied from the condensate storage tank (evaluated under the

condensate and condensate storage system), with a backup source from the suppression

chamber (evaluated with the primary containment structure). The pump discharge is delivered

into the reactor vessel through a connection to the "A" feedwater line (evaluated with the

feedwater system) and is distributed within the vessel through the feedwater spargers

(evaluated with reactor internals). A minimum flow bypass line from the pump discharge line to

the suppression chamber is provided for pump protection. The RCIC system is equipped with a

test line used for functional testing that returns condensate to the condensate storage tank.

The RCIC test return line is tied to the HPCI system test return line (evaluated under the HPCI

system). The RCIC auxiliaries include the drain pot subsystem, the barometric condenser and

vacuum subsystem, and the turbine oil subsystem. The RCIC turbine and pump are located in

a room with a CS pump, and the area is cooled by the CS room cooler (evaluated with ECCS

corner room HVAC).

Intended functions within the scope of license renewal include the following:

* pressure boundary-maintains the integrity of the reactor coolant pressure boundary

* primary containment isolation-provides containment isolation for those portions of the

system that interface with the primary containment

* core cooling-provides cooling water to the core and provides capability for level and

pressure control during normal reactor isolation conditions

* credited in regulated event(s)-provides core cooling, including capability for level and

pressure control, credited in mitigation of the Appendix R fire, ATWS, and SBO events;

also contains components relied upon for compliance with 10 CFR 50.49 (EQ)

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected

Table 2.3.2-4 of the LRA identified the component groups requiring AMR. The component

groups identified for RCIC include the following:

* closure bolting (Quad Cities only)

* dampeners (Quad Cities only)

* filters/strainers (pressure boundary, Quad Cities only)

* filters/strainers (filter, Quad Cities only)

* flexible hoses (Quad Cities only)

* NSR vents or drains, piping, and valves (attached support, Quad Cities only)

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* piping and fittings (includes rupture discs, Quad Cities only)

* piping and fittings (small bore, Quad Cities only)

* pumps (Quad Cities only)

* restricting orifices (pressure boundary, Quad Cities only)

* restricting orifices (throttle, Quad Cities only)

* sight glasses (Quad Cities only)

* tanks (includes drain pots, actuators, and condensers, Quad Cities only)

* traps (Quad Cities only)

* tubing (Quad Cities only)

* turbine casings (Quad Cities only)

* valves (Quad Cities only)

* valves (small bore, Quad Cities only)

2.3.2.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.4 and Quad Cities UFSAR Section 5.4.6 to determine

whether there is reasonable assurance that the components of the RCIC system within the

scope of license renewal and subject to an AMR have been identified in accordance with

10 CFR 54.4 and 54.21 (a)(1). The staff's review was conducted in accordance with Section 2.3

of the SRP for License Renewal (NUREG-1 800) and is described below.

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As part of

the evaluation, the staff determined whether the applicant had properly identified the SSCs

within the scope of license renewal and subject to an AMR, pursuant to 10 CFR 54.4(a) and 10

CFR 54.21 (a)(1). The staff reviewed the relevant portions of the UFSAR for the reactor vessel

and associated components and compared the information in the UFSAR with the information

in the LRA to identify those portions that the LRA did not identify as being within the scope of

license renewal and subject to an AMR. The staff then reviewed the structures and

components that were identified as not being within the scope of license renewal to verify that

(1) these structures and components do not have any of the intended functions delineated

under 10 CFR 54.4(a), and (2) for those structures and components that have applicable

intended function(s), verify that they either perform this function(s) with moving parts or a

change in configuration or properties, or they are subject to replacement based on a qualified

life or specified time period, as described in 10 CFR 54.21 (a)(1).

The staff also reviewed the UFSAR for any functions delineated under 10 CFR 54.4(a) that

were not identified as intended functions in the LRA to verify that the SSCs with such functions

will be adequately managed so that the functions will be maintained consistent with the CLB for

the extended period of operation.

2.3.2.4.3 Conclusions

The staff reviewed LRA Section 2.3.2.4 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. The

staff did not identify any omissions. On the basis of its review, the staff concluded that there is

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reasonable assurance that the applicant has adequately identified the components of the RCIC

system that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that

the applicant has adequately identified the components of the RCIC system that are subject to

an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.2.5 Isolation Condenser-Dresden Only

2.3.2.5.1 Summary of Technical Information in the Application

The applicant described the isolation condenser system components in LRA Section 2.3.2.5

and provided a list of components subject to an AMR in LRA Table 2.3.2-5.

The isolation condenser system at Dresden provides reactor core cooling in the event that the

reactor becomes isolated from the turbine and main condenser by closure of the main steam

isolation valves.

Using the methodology described in LRA Section 2.1.4.1 for identifying the mechanical

components within the scope of license renewal, the applicant identified the following intended

isolation condenser system functions:

* pressure boundary-maintains the integrity of the reactor coolant pressure boundary

* primary containment isolation-provides containment isolation for those portions of the

system that interface with the primary containment

* credited in regulated event(s)-provides reactor pressure control and core cooling functions

(in vessel isolation conditions) credited in mitigation of the Appendix R fire, ATWS, and SBO

events; also contains components that are relied upon for compliance with 10 CFR 50.49

(EQ)

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected

The isolation condenser is a heat exchanger, which consists of two tube bundles immersed in a

large water storage tank. The isolation condenser system operates by natural circulation

without the need for power other than direct current (dc) power to open the condensate return

valve to initiate system operation. During isolation condenser system operation, steam flows

through the isolation condenser steam supply line directly from the reactor vessel (evaluated

with the reactor vessel), condenses in the tubes of the heat exchanger, and returns by gravity

through the isolation condenser return line to the reactor via the 'A" recirculation loop

(evaluated with the reactor recirculation, recirculation flow control, and v/G sets system).

Isolation valves are provided on the lines that penetrate the primary containment. The

differential water head, created when the steam is condensed, serves as the driving force. The

water on the shell side of the condenser boils and vents to the atmosphere. The tube side of

the isolation condenser system is equipped with a high point vent which is used during normal

operation to prevent the long-term buildup of noncondensible gases. These gases are vented

to the "A" main steam line, downstream of the main steam line flow restrictor (venturi).

(evaluated with the main steam system). The differential pressure across the venturi provides

the driving force for the flow of steam and noncondensible gases from the tube side of the

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isolation condenser system to the main steam line. The preferred makeup water source is the

clean demineralized water storage tank via two diesel-driven isolation condenser makeup water

pumps. Alternate makeup water sources are the fire protection system (evaluated separately)

and the condensate storage system (evaluated with the condensate and condensate storage

system). Two radiation monitors (evaluated with the process radiation monitoring system) are

provided on the shell vent. In the event of excessive radiation levels, the tube side of the heat

exchanger can be isolated from the reactor.

In LRA Section 2.3.2.5, the applicant described the evaluation boundary of the isolation

condenser system. In addition, the applicant highlighted those portions of the system and its

structures and components that are within the scope of the Rule in the P&lDs listed as

references in LRA Section 2.3.2.5. Also, based on the methodology described in LRA

Section 2.1.5 for identifying the mechanical components subject to an AMR, the applicant

identified the following component groups and their intended functions within the isolation

condenser system in LRA Table 2.3.2.5 as being within the scope of license renewal and

subject to an AMR:

* closure bolting (pressure boundary, Dresden only)

* isolation condensers (pressure boundary, Dresden only)

* isolation condensers (heat transfer)

* NSR vents or drains, piping, and valves (structure integrity/attached support, Dresden only)

* piping and fittings (structure integrity/attached support, Dresden only)

* piping and fittings (pressure boundary, Dresden only)

* piping and fittings small bore (pressure boundary, Dresden only)

* pumps (pressure boundary, Dresden only)

* flow elements (pressure boundary, Dresden only)

* sight glasses (pressure boundary, Dresden only)

* tanks (pressure boundary, Dresden only)

* thermowells (pressure boundary, Dresden only)

* tubing (pressure boundary, Dresden only)

* valves (pressure boundary, Dresden only)

* valves (structure integrity/attached support, Dresden only)

2.3.2.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.5 and Dresden USAR Section 5.4.6 to determine whether

there is reasonable assurance that the components of the isolation condenser system within the

scope of license renewal and subject to an AMR have been identified in accordance with

10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff review was conducted in accordance with

Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSAR to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the isolation condenser system in the LRA. The staff did not identify

any omissions.

Also, the staff selected system functions described in the UFSAR that were set forth in 10

CFR 54.4 to verify that components having intended functions were not omitted from the scope

of the Rule. The staff also focused on components that were not identified as being subject to

an AMR to determine if any components were omitted.

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To verify that the applicant identified the components of the isolation condenser system that are

within the scope of license renewal and subject to an AMR in ac6ordance with 10 CFR 54.4 and

10 CFR 54.21(a)(1), respectively, the staff compared the referenced P&lDs to the system

drawings and system descriptions in the UFSAR to ensure that the referenced P&lDs were

representative of the isolation condenser system. The staff then reviewed the referenced

P&lDs to verify that those portions of the isolation condenser system that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal and are identified

as such by the applicant in LRA Section 2.3.2.5, and that the-applicant identified all isolation

condenser system components within the scope of license renewal and subject to an AMR in

accordance with 10 CFR 54.4 and 10-CFR 54.21(a)(1).

The staff's review of LRA Section 2.3.2.5 identified areas in which additional information was

necessary to complete the staff's review of the applicant's scoping and screening results.

Therefore, by letter on August 4, 2003, the staff issued RAls to the applicant concerning the

specific items to determine whether the applicant has properly applied the scoping and

screening criteria of 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's RAIs and the applicant's

responses, dated October 3, 2003, are described below.

RAI 2.3.2.5-1 (Dresden Units OnIv). For Unit 3, the system boundary between the isolation

condenser and demineralized water makeup piping system for AMR is shown on flow diagram

LR-DRE-M-359 (B-1) for line 3-4399-72. For Unit 2, the similar isolation boundary between the

isolation condenser and demineralized water makeup piping system for AMR is not shown on

flow diagram LR-DRE-M-28 (B-1) or on flow diagram M-35-1 (A-8) for line 2-4399-72. The staff

asked the applicant to indicate the LR boundary for Unit 2 piping between the isolation

condenser and demineralized water makeup system and to indicate where the LRA addresses

the AMR of these components or provide a justification for excluding these components from an

AMR.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.2.5-1 stated that for Unit 3, the system boundary break

between the isolation condenser and demineralized water makeup for AMR shown- on boundary

diagram LR-DRE-M-359 (B-1) for line 3-4388-4m-L (valve 3-4399-72) is correct and represents

the boundary evaluated. For Unit 2, the same boundary break between the isolation condenser

and demineralized water makeup system should have been shown on boundary diagram LRDRE-M-28 (B-1) for line 2-4388-4"-L (Valve 2-4399-72). These components fall within the

scope of license renewal. The components within the isolation condenser system boundary are

included in LRA Table 2.3.2-5 under the component groups "piping and fittings (Dresden only)"

and "valves (Dresden only)." The piping upstream of valve (2)3-4399-72 is evaluated in the

demineralized water makeup system boundary and is included in LRA Table 2.3.3-19 under the

component group "piping and fittings."

Based on its review, the staff concurs with the applicant's clarification that the above-cited

segment of piping and its associated components in Unit 2 are within the scope of the Rule and

subject to an AMR; they were inadvertently not highlighted in the LR boundary diagram; and

their associated components are included in the appropriate LRA tables subject to an AMR.

Therefore, the staff finds the applicant's response to RAI 2.3.2.5-1 acceptable and considers its

concern described in RAI 2.3.2.5-1 resolved.

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RAI 2.3.2.5-2 (Dresden Units Only). The LR boundary for the clean demineralized water

storage tank (2/3-4300) shown on flow diagram LR-DRE-M-35-1 for AMR is not clearly

indicated, and, therefore, it is unclear whether the boundary is covered in the isolation

condenser system or demineralized water system. The LR boundaries for line 2/3-43220-4"-H

and for line to LI and LT indicate that it is covered in the isolation condenser system. The LR

boundaries for line 2/3-43206-6"-H and for line 2/3 4301-3X-L indicate that it is covered in the

demineralized water system. These safety-related components are relied upon to remain

functional during and following the design-basis events to provide makeup water to the isolation

condenser for cooling. The staff asked the applicant to indicate the LR boundary for the tank

and connecting piping and identify where the LRA addresses the AMR for these components or

provide a justification for excluding these components from an AMR.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.2.5-2 stated that the clean demineralized water storage

tank T-105B (2/3-4300) shown on boundary diagram LR-DRE-M-35-1 was evaluated with the

isolation condenser system as stated in LRA Sections 2.3.2.5 and 2.3.3.19.

Piping and components associated with the clean demineralized water storage tank (T-105B)

that provide flow path to the isolation condenser makeup pumps and receive recirculation flow

return from the isolation condenser makeup pumps are evaluated in the isolation condenser

system boundary. Piping and components from the tank connection for the level instruments

(LI and LT) and the suction piping for the clean demineralizer water pumps (2/3-4301B-3"-L)

from the tank were evaluated in the clean demineralizer system boundary. Line 2/3-4301 B-3"-L

has the same boundary breaks as those of the piping for the LI and LT, in that the boundary

break is at the piping connection to the tank.

The LR boundary break for line 2/3-43206-6"-H (LR-DRE-M-35-1, E-9) shows that the piping

connecting the tank to the isolation condenser makeup pumps (through lines 2/3-43216A-8"-H

and 2/3-43216A-8"-H) was evaluated within the isolation condenser evaluation boundary. The

portion of piping for line 2/3-43206-6"-H at coordinate E-9 that has been colored black should

have been highlighted green to be in scope. This piping connects to valves 2/3-4399-329A/B

on the suction side of dilution pumps. The piping up to and including the valves is evaluated

with the makeup demineralizer system boundary for AMR.

The AMRs for those components evaluated with the isolation condenser system are included in

LRA Table 2.3.2-5. They are included under the component groups of "tanks (Dresden only),"

"valves (Dresden only)," and 'piping and fittings (Dresden only)." The AMRs for those

components evaluated with the makeup demineralizer system are included in LRA Table 2.3.3-

19. They are included under the component groups of "valves," and "piping and fittings."

The components discussed above are not safety-related and are not credited in any designbasis event. The tank and the associated piping and components are within the scope of

license renewal for compliance with the fire protection, ATWS, and SBO 10 CFR 54.4(a)(3)

regulated events.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.2.5-2 acceptable because it conforms with the criteria set forth

in 10 CFR 54.4 and 10 CFR 54.21(a)(1). Therefore, the staff considers its concern described in

RAI 2.3.2.5-2 resolved.

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, , - -- " _- 'Z7' , , .

r ; , , . .

RAI 2.3.2.5-3 (Dresden Units Only). Table 2.3.2-5, "Component Groups Requiring Aging

Management Review-Isolation Condenser (Dresden only)," does not list the vacuum breaker

2/3-4399-803 shown on isolation condenser makeup system flow diagram LR-DRE-M-4203 as

the component requiring AMR. This safety-related component is relied upon to remain

functional during and following the design-basis events to maintain the pressure boundary for

the essential components. The staff asked the applicant to identify where the LRA addresses

the AMR of this component or provide a justification for excluding this component from an AMR.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.2.5-3 stated that vacuum breaker 2/3-4399-803, shown on

isolation condenser makeup system boundary diagram LR-DRE-M-4203, falls within the scope

of license renewal and is evaluated in LRA Table 2.3.2-5 under the component group "Valves

(Dresden only)."

The staff finds the applicant's clarification discussed above acceptable because it conforms with

the criteria set forth in 10 CFR 54.4 and 10 CFR 54.21(a)(1). Therefore, the staff considers its

concern described in RAI 2.3.2.5-3 resolved.

RAI 2.3.2.5-4 (Dresden Units Only). (a) Drawing LR-DRE-M-359, Isolation Condenser Piping,

identifies two diaphragm seal components within the boundaries of license renewal; however,

these components are not listed in the LRA tables described above. The staff asked the

applicant to identify where the LRA addresses the AMR for these diaphragm seal components

or provide a justification for excluding these components from an AMR.

(b) The Dresden isolation condenser system description mentions the presence of a loop seal

and manway hatch as components in the isolation condenser system. Neither of these

components is mentioned in Tables 2.3.2-5, 3.2-1, or 3.2-2 of the LRA. The staff asked the

applicant to identify where the LRA addresses the AMR for these components or provide a

justification for excluding these components from an AMR.

(c) Condensate piping diagram LR-QDC-M-1 6-5 does not include level switch isolation

valves 0-33107A and 0-331 08A and connecting piping to level switch 0-3341-71 A within the

scope of license renewal. The staff asked the applicant to identify where the LRA addresses

the AMR for these components or provide a justification for excluding these components from

an AMR.

Applicant's Response and Staff's Evaluation

(a) The applicant's response to RAI 2.3.2.5-4(a) stated that the diaphragm seals indicated on

LR-DRE-M-28 and LR-DRE-M-359 are part of level transmitters LT-2-1341 and LT-3-1341,

which are a filled-capillary type of differential pressure transmitter. This type of transmitter

is used in applications where a constant reference leg level cannot be assured by process

conditions (for example, condensation from a two-phase fluid). The transmitters are

shipped with the diaphragm seals attached to the transmitter by coils of flexible tubing, with

the fill fluid already installed: These transmitters are in the scope of license renewal but do

not require aging management because they are active components.

(b) The applicant's response to RAI 2.3.2.5-4(b) stated that the loop seals are shown on

LR-DRE-M-39 (A-9) and LR-DRE-M-369 (A-9). They are needed to provide a secondary

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containment boundary between the isolation condenser vent header, which discharges to

the reactor building exterior, and the loop seal discharge to the reactor building. The loop

seals are constructed of 1.5 in carbon steel piping and are included in LRA Table 2.3.2-5,

with the component group of "piping and fittings (Dresden only)" and with a component

intended function of "Pressure Boundary." The loop seals are not depicted correctly on the

boundary diagrams. The boundary drawings should have highlighted the loop seals in

green, with an "RBD/ISO" flag positioned after the highlighted portion.

The isolation condenser manways are part of the isolation condenser itself and are included

in LRA Table 2.3.2-5, with the component group of "isolation condensers (Dresden only)"

and with a component intended function of "pressure boundary." The manway bolting is

included in LRA Table 2.3.2-5 with the component group of "closure bolting (Dresden only)"

and with a component intended function of "pressure boundary."

(c) The applicant's response to RAI 2.3.2.5-4 (c) stated that the isolation valves for LS-0-3341 -

71A and the connecting piping are in scope, and should have been highlighted on LR-QDCM-1 6-5. The valve equipment piece numbers on LR-QDC-M-1 6-5 are 0-3399-227A and 0-

3399-228A. The connecting piping is identified on the drawing as 0-33107A-1" and 0-

33108A-1." The valves are included in LRA Table 2.3.4-3 with the component group of

"valves," and a component intended function of "pressure boundary." The connecting piping

is included in Table 2.3.4-3 with the component group of "piping and fittings," and a

component intended function of "pressure boundary."

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.2.5-4 acceptable because it conforms with the criteria set forth

in 10 CFR 54.4 and 10 CFR 54.21(a)(1). Therefore, the staff considers its concern described in

RAI 2.3.2.5-4 resolved.

2.3.2.5.3 Conclusions

The staff reviewed LRA Section 2.3.2.5, the accompanying scoping boundary drawings and the

applicant's response to RAls dated October 3, 2003, to determine whether any SSCs within the

scope of license renewal had not been identified by the applicant. In addition, the staff

performed an independent assessment to determine whether any components that should be

subject to an AMR were not identified by the applicant. The staff did not identify any omissions.

On the basis of its review, the staff concludes that the applicant has adequately identified the

components of the isolation condenser system that are within the scope of license renewal, as

required by 10 CFR 54.4, and that the applicant has adequately identified the components of

the isolation condenser system that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.2.6 Residual Heat Removal System-Quad Cities Only

2.3.2.6.1 Summary of Technical Information in the Application

The applicant described the residual heat removal (RHR) system components in LRA Section

2.3.2.6 and provided a list of components subject to an AMR in LRA Table 2.3.2-6.

The RHR system at Quad Cities has three modes of operation. The LPCI mode of RHR is the

only ESF function of the system and operates to restore water level in the reactor vessel. The

containment cooling mode furnishes spray to the drywell and suppression chamber to aid in

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reducing containment pressure following a LOCA. This mode also provides suppression

chamber cooling to reduce water temperatures during operations that add heat to the

suppression chamber and minimizes the amount of heat that the containment will need to

accommodate during a LOCA. The shutdown cooling mode removes reactor residual and

decay heat for shutdown, refueling, and servicing operations.

The RHR system consists of two loops, each loop containing two RHR pumps, one RHR heat

exchanger (evaluated with the RHR service water system), and the necessary valves and piping

to connect these components to the reactor vessel via the recirculation system piping, the

suppression chamber for spray/cooling and the drywell for spray. The RHR system piping is

maintained full by the ECCS keep fill system (evaluated with the CS system). Each loop of the

system is equipped with a minimum flow bypass line to the suppression chamber for RHR

pump protection. During normal plant operation, the RHR system is maintained in a lineup to

be ready to inject water into either recirculation loop with all RHR pumps. Process lines that

penetrate the primary containment structure contain isolation valves. The RHR room coolers

are evaluated with the ECCS corner room HVAC system.

For the LPCI mode of operation, the primary source of water to the RHR system is supplied

from the suppression chamber (evaluated with the primary containment structure). The backup

source of water is the condensate storage tank (evaluated with the condensate and condensate

storage system). For each loop, water is pumped from the suppression chamber, through the

pumps to the heat exchanger (HX) and the HX bypass valve. Upon automatic initiation of the

RHR system, the LPCI loop select logic will select the recirculation loop (evaluated with

recirculation, recirculation flow control, and M/G sets system) that appears most likely intact

and, provided reactor pressure is sufficiently low, will inject to the intact recirculation loop.

For the containment cooling mode of operation, there are three different uses.

(1) Drywell spray takes suction from the suppression chamber and pumps water to two spray

nozzle headers in the drywell. These spray headers may be used during a LOCA to

reduce drywell pressure.

(2) Suppression chamber spray takes suction from the suppression chamber and pumps

water to spray nozzles in the suppression chamber. This reduces suppression chamber

pressure following a LOCA.

(3) Suppression chamber cooling takes suction from the suppression chamber and pumps

through an RHR heat exchanger (which rejects heat to the RHR service water system)

and pumps the water back to the suppression chamber. This mode provides a heat sink,

external to the containment, which will limit suppression chamber water temperature

during conditions such as RCIC operation and minimize the amount of heat that the

suppression chamber will need to accommodate during a LOCA (for pressure suppression

and ECCS pump required suction head).

For the shutdown cooling mode of operation, the RHR pumps take suction from the "B" reactor

recirculation system suction piping, pump water through an RHR heat exchanger (for heat

removal via RHR service water system), and return the water to the reactor vessel via the

recirculation system pump discharge line.

Intended functions within the scope of license renewal include the following:

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* pressure boundary-maintains the integrity of the reactor coolant pressure boundary

* core cooling-provides emergency core cooling for various postulated LOCAs for a range

of failure sizes from those for which the core is adequately cooled by HPCI up to and

including the design-basis accident; in addition provides heat removal sufficient to achieve

and maintain cold shutdown conditions during normal operation

* containment cooling-provides emergency containment cooling by recirculating

suppression chamber water through the system heat exchangers and by spraying water

into the drywell and the suppression chamber

* primary containment isolation-provides containment isolation for those portions of the

system that interface with the primary containment

* credited in regulated event(s)-provides containment cooling and decay heat removal

credited in mitigation of the Appendix R fire and ATWS events; also contains components

that are relied upon for compliance with 10 CFR 50.49 (EQ)

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected

Table 2.3.2-6 of the LRA identified the component groups requiring AMR. The component

groups identified for RHR include the following:

* closure bolting (Quad Cities only)

* dampeners (Quad Cities only)

* dampeners (attached support, Quad Cities only)

* ECCS suction headers (Quad Cities only)

* filters/strainers (pressure boundary, Quad Cities only)

* filters/strainers (Filter, Quad Cities only)

* flow elements (Pressure Boundary, Quad Cities only)

* flow elements (Throttle, Quad Cities only)

* NSR vents or drains, piping, and valves (attached support, includes flow glasses, Quad

Cities only)

* piping and fittings (Quad Cities only)

* piping and fittings (attached support, Quad Cities only)

* pumps (Quad Cities only)

* restricting orifices (includes dampeners, Quad Cities only)

* restricting orifices (Quad Cities only)

* sight glasses (attached support, Quad Cities only)

* spray Nozzles (Pressure Boundary, Quad Cities only)

* spray Nozzles (Spray, Quad Cities only)

* thermowells (Quad Cities only)

* tubing (Quad Cities only)

* tubing (attached support, Quad Cities only)

* valves (Quad Cities only)

* valves (attached support, Quad Cities only)

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2.3.2.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.6 and Quad Cities UFSAR Sections 5.4.7, 6.3.1, and

6.3.2 to determine whether there is reasonable assurance that the components of the RHR

system within the scope of license renewal and subject to an AMR have been identified in

accordance with 10 CFR 54.4 and 54.21 (a)(1). The staff's review was conducted in accordance

with Section 2.3 of the SRP for License Renewal (NUREG-1 800) and is described below.

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As part of

the evaluation, the staff determined whether the applicant had properly identified the SSCs

within the scope of license renewal and subject to an AMR, pursuant to 10 CFR 54.4(a) and

10 CFR 54.21 (a)(1). The staff reviewed the relevant portions of the UFSAR for the reactor

vessel and associated components and compared the information in the UFSAR with the

information in the LRA to identify those portions that the LRA did not identify as being within the

scope of license renewal and subject to an AMR. The staff then reviewed the SCs that were

identified as not being within the scope of license renewal to verify that (1) these SCs do not

have any of the intended functions delineated under 10 CFR 54.4(a), and (2) for those SCs that

have an applicable intended function(s), verify that they either perform this function(s) with

moving parts or a change in configuration or properties, or that they are subject to replacement

based on a qualified life or specified time period, as described in 10 CFR 54.21 (a)(1).

The staff also reviewed the UFSAR for any functions delineated under 10 CFR 54.4 (a) that

were not identified as intended functions in the LRA, to verify that the SSCs with such functions

will be adequately managed so that the functions will be maintained consistent with the CLB for

the extended period of operation.

2.3.2.6.3 Conclusions*

The staff reviewed LRA Section 2.3.2.6 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to'determine whether

any components that should be subject to an AMR were not identified by the applicant. The

staff did not identify any omissions. On the basis of its review, the staff concludes that the

applicant has adequately identified the components of the RHR system that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the RHR system that are subject to an AMR, as required by 10

CFR 54.21 (a)(1).

2.3.2.7 Low-Pressure Coolant Injection System-Dresden Only

2.3.2.7.1 Summary of Technical Information in the Application

The applicant described the LPCI system components in LRA Section 2.3.2.7 and provided a

list of components subject to an AMR in LRA Table 2.3.2-7.

The LPCI system comprises two independent loops, each with two pumps and a heat

exchanger that supply water to the reactor core via the reactor recirculation system. The LPCI

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system provides core cooling during a LOCA for break sizes ranging from those for which the

core is adequately cooled by the HPCI system alone, up to and including a design-basis

accident (DBA). The LPCI is capable of injecting large quantities of water into the reactor

pressure vessel and provides core cooling by submerging the core in water. The LPCI system

is also designed to supply cooling/spray water to the primary containment (drywell and

suppression chamber) during accident conditions to maintain containment temperature and

pressure below design limits. The LPCI system is also the normal means of removing water

from the suppression chamber to maintain the water level in the normal band.

The LPCI system consists of two independent loops, each with two motor-driven pumps, an

LPCI heat exchanger (evaluated with the containment cooling service water system (CCSW),

associated piping, valves, and instrumentation. The normal water source is supplied from the

suppression chamber via an ECCS suction header (evaluated with the primary containment

structure). An alternate source of water to the LPCI pumps is supplied from the condensate

storage tank (evaluated with the condensate and condensate storage system). The LPCI

pumps can route water to several discharge paths. The LPCI system supplies water to the

reactor vessel through the LPCI heat exchanger and into the reactor recirculation system

(evaluated with the recirculation, recirculation flow control and MG set system) downstream of

the reactor recirculation pumps. A motor-operated valve allows LPCI flow to bypass the heat

exchanger. Each loop can deliver water to the reactor vessel through its own injection line or

through the other LPCI loop injection line via a cross-tie line. Each LPCI loop is equipped with a

test return line to the suppression chamber to permit functional testing and a minimum flow

bypass line to the suppression chamber for pump protection.

Each LPCI loop also has the capability to deliver cooling/spray water to the primary containment

during accident conditions. The containment cooling mode of operation consists of (1) drywell

spray where LPCI pumps are aligned to pump water from the suppression chamber to headers

equipped with spray nozzles in the drywell (evaluated with the primary containment structure) to

reduce containment pressure following a LOCA, (2) suppression chamber spray where LPCI

pumps are aligned to pump water from the suppression chamber to a header equipped with

spray nozzles (evaluated with the primary containment structure) in the suppression chamber to

reduce containment pressure following a LOCA, and (3) suppression chamber cooling where

LPCI pumps are aligned to recirculate water from the suppression chamber, through the LPCI

heat exchangers and back to the suppression chamber.

The LPCI system is also the normal means of removing water from the suppression chamber to

maintain normal operational level band. Taking suction from the suppression chamber, the

LPCI pumps can transfer water from the suppression chamber to the suppression chamber of

the other unit, to the main condenser (evaluated separately) of either unit, or to the floor drain

collector tank (evaluated with radwaste and equipment drains).

Intended functions within the scope of license renewal include the following:

* pressure boundary-maintains the integrity of the reactor coolant pressure boundary

* core cooling-provides emergency core cooling for various postulated LOCAs for a range of

failure sizes from those for which the core is adequately cooled by HPCI up to and including

the DBA

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* containment cooling-provides emergency containment cooling by recirculating suppression

chamber water through the system heat exchangers and by spraying water into the drywell

and the suppression chamber.5

* primary containment isolation-provides containment isolation for those portions of the

system that interface with the primary containment

* credited in regulated event(s)-provides containment cooling functions credited in mitigation

of the Appendix R fire protection and ATWS events; also contains components that are

relied upon for compliance with 10 CFR 50.49, (EQ)

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected

Table 2.3.2-7 of the LRA identified the component groups requiring AMR. The component

groups identified for LPCI include the following:

* closure bolting (Dresden only)

* ECCS suction headers (Dresden only)

* filters/drainers (Dresden only)

* flow elements (pressure boundary, Dresden only)

* flow elements (throttle, Dresden only)

* NSR vents or drains, piping, and valves (attached support, includes flow glasses, Dresden

only)

* piping and fittings (Dresden only)

* piping and fittings (attached support, Dresden only)

* pumps (Dresden only)

* restricting orifices (pressure boundary, Dresden only)

* restricting Orifices (throttle, Dresden only)

* sight glasses (attached support, Dresden only)

* spray nozzles (pressure boundary, Dresden only)

* spray nozzles (spray, Dresden only)

* thermowells (Dresden only)

* tubing (Dresden only)

* tubing (attached support, Dresden only)

* valves (Dresden only)valves (attached support, Dresden only)

2.3.2.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.7 and Dresden UFSAR Sections 6.2.2, 6.3.1.2, and

6.3.2.2 to determine whether there is reasonable assurance that the components of the LPCI

system within the scope of license renewal and subject to an AMR have been identified in

accordance with 10 CFR 54.4 and 54.21 (a)(1). The staff's review was conducted in accordance

with Section 2.3 of the SRP for License Renewal (NUREG-1 800) and is described below.

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As part of

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the evaluation, the staff determined whether the applicant had properly identified the SSCs

within the scope of license renewal and subject to an AMR, pursuant to 10 CFR 54.4(a) and

10 CFR 54.21 (a)(1). The staff reviewed the relevant portions of the UFSAR for the reactor

vessel and associated components and compared the information in the UFSAR with the

information in the LRA to identify those portions that the LRA did not identify as being within the

scope of license renewal and subject to an AMR. The staff then reviewed the SCs that were

identified as not being within the scope of license renewal to verify that (1) these SCs do not

have any of the intended functions delineated under 10 CFR 54.4(a), and (2) for those SCs that

have an applicable intended function(s), verify that they either perform this function(s) with

moving parts or a change in configuration or properties, or that they are subject to replacement

based on a qualified life or specified time period, as described in 10 CFR 54.21 (a)(1).

The staff also reviewed the UFSAR for any functions delineated under 10 CFR 54.4(a) that

were not identified as intended functions in the LRA, to verify that the SSCs with such functions

will be adequately managed so that the functions will be maintained consistent with the CLB for

the extended period of operation.

After completing the initial review, the staff requested the applicant to provide additional

information on the LPCI system. By letter dated October 3, 2003, the applicant responded to

the staff's RAI as discussed below.

The LPCI coupling was identified in the BWRVIP-06 report as a safety-related component. It

appears, however, that the component was not identified in the LRA as requiring an AMR. In

RAI 2.3.2.7-1, the staff asked the applicant if the component exists at Dresden and/or Quad

Cities. If so, the applicant was requested to justify its exclusion from aging management;

otherwise, the applicant must submit an AMR for the subject component. In response, the

applicant stated that the LPCI coupling identified in BWRVIP-06, BWR Vessel and Intemals

Project, applies to BWR/4, BWR/5, and BWR/6 reactors (Section 2.7, BWRVIP-06). The

Dresden and Quad Cities reactors are BWR/3. The LPCI coupling identified in Section 2.7 of

BWRVIP-06 does not exist at Dresden or at Quad Cities. Based on this discussion, the staff

finds the applicant's assessment acceptable.

2.3.2.7.3 Conclusions

The staff reviewed LRA Section 2.3.2.7 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. The

staff did not identify any omissions. On the basis of its review, the staff concludes that the

applicant has adequately identified the components of the LPCI system that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the LPCI system that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.2.8 Standby Liquid Control System

2.3.2.8.1 Summary of Technical Information in the Application

The applicant described the standby liquid control (SBLC) system components in LRA Section

2.3.2.8 and provided a list of components subject to an AMR in LRA Table 2.3.2-8.

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*-- red ~'' ; ... :W 7

The SBLC system is able to bring the reactor from full power to a cold, xenon-free subcritical

condition, assuming that none of the withdrawn control rods can be inserted, by injecting

sodium pentaborate solution into the reactor core.

The SBLC system consists of a tank for sodium pentaborate solution storage, two parallel

suction lines from the tank with normally opened suction valves feeding a common pump

suction header; two positive displacement pumps with normally opened suction valves that

discharge into a common header; two explosion-actuated shear plug valves arranged in parallel

discharge lines from the common discharge header; and other piping, valves, and

instrumentation. The explosive valves are actuated to provide a flow path, and the sodium

pentaborate solution is delivered to the reactor vessel (evaluated separately) by one or both of

the positive displacement pumps. The pumps and piping are protected from overpressure by

two relief valves which discharge back to the SBLC tank. Heaters are installed in the SBLC

storage tank to ensure that the solution is maintained at sufficient temperature to keep the

sodium pentaborate in solution. System piping normally filled with the sodium pentaborate

solution is heat traced to ensure that the sodium pentaborate does not precipitate in the piping.

The system also includes a test tank and associated piping used to measure pump

performance.

Intended functions within the scope of license renewal include the following:

* reactivity control-provides the capability for bringing the reactor from full power to a cold,

xenon-free shutdown assuming that none of the withdrawn control rods can be inserted

* pressure boundary-maintains the integrity of the reactor coolant pressure boundary.

* containment isolation-provides containment isolation for those portions of the system that

interface with the primary containment

* credited in regulated event(s)-provides reactivity control credited in mitigation of the ATWS

event

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected

Table 2.3.2-8 of the LRA identified the component groups requiring AMR. The component

groups identified for SBLC include the following:

* accumulators

* closure bolting

* dampeners (Quad Cities only)

* NSR vents or drains, piping, and valves (attached support)

* piping and fittings

* piping and fittings (attached support)

* pumps

* sight glasses

* tanks

* thermowells

* tubing

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* tubing (attached support)

* valves

* valves (attached support)

2.3.2.8.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.8, Dresden UFSAR Section 9.3.5, and Quad Cities

UFSAR Sections 9.3.5 to determine whether there is reasonable assurance that the

components of the SBLC system within the scope of license renewal and subject to an AMR

have been identified in accordance with 10 CFR 54.4 and 54.21 (a)(1). The staff's review was

conducted in accordance with Section 2.3 of the SRP for License Renewal (NUREG-1800) and

is described below.

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As part of

the evaluation, the staff determined whether the applicant had properly identified the SSCs

within the scope of license renewal and subject to an AMR, pursuant to 10 CFR 54.4(a) and

10 CFR 54.21(a)(1). The staff reviewed the relevant portions of the UFSAR for the reactor

vessel and associated components and compared the information in the UFSAR with the

information in the LRA to identify those portions that the LRA did not identify as being within the

scope of license renewal and subject to an AMR. The staff then reviewed the structures and

components that were identified as not being within the scope of license renewal to verify that

(1) these SCs do not have any of the intended functions delineated under 10 CFR 54.4(a), and

(2) for those SCs that have applicable intended function(s), they either perform this function(s)

with moving parts or a change in configuration or properties, or they are subject to replacement

based on a qualified life or specified time period, as described in 10 CFR 54.21(a)(1).

The staff also reviewed the UFSAR for any functions delineated under 10 CFR 54.4(a) that

were not identified as intended functions in the LRA, to verify that the SSCs with such functions

will be adequately managed so that the functions will be maintained consistent with the CLB for

the extended period of operation.

2.3.2.8.3 Conclusions

The staff reviewed LRA Section 2.3.2.8 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. The

staff did not identify any omissions. On the basis of its review, the staff concludes that the

applicant has adequately identified the components of the SBLC system that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the SBLC system that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

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2.3.2.9 Standby Gas Treatment System

2.3.2.9.1 Summary of Technical Information in the Application

The applicant described the standby gas treatment system (SBGTS) in LRA Section 2.3.2.9

and provided a list of components subject to an AMR in LRA Table 2.3.2-9.

The SBGTS, which is designed to maintain a small negative pressure in the reactor building

relative to the atmosphere outside of the building, has the functions of processing and

controlling the effluent releases from the primary containment (drywell and suppression

chambers) during vent and purge operation when necessary; processing radioactive effluent

from the HPCI gland seal exhaust subsystem (Dresden only) during HPCI operation; and

processing and controlling the intentional exhaust of radioactive material from the reactor

building spaces to the environment during a DBA. These ensure that the requirements of -10

CFR 100 are met.

Using the methodology described in LRA Section 2.1.4.1 for identifying the mechanicalcomponents within the scope of license renewal, the applicant identified the following SBGTS

intended functions:

* filtration-filters and removes radioactive gases and particulates that are present in the

secondary containment prior to discharging to the environment after a DBA

* containment-maintains a small negative pressure in the reactor building under isolation

conditions

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity for nonsafety-related components that could be a hazard to safety-related SSCs, so that the

intended function of safety-related SSCs is not adversely affected

* credited in regulated events-contains components that are relied upon for compliance with

10 CFR 50.49 (EQ)

The SBGTS consists of two 100 percent capacity treatment trains. During normal operation,

one train is selected as the primary and the other is placed in standby. The SBGTS receives

effluent from three sources-the reactor building, primary containment, and an HPCI gland

exhauster. Each train (which consists of piping that routes effluent flow to a demister, an

electrical heater, roughing pre-filter, high-efficiency filters, charcoal absorbers, high-efficiency

after filter, fan, associated valves, and instrumentation) filters and removes radioactive particles

and adsorbs radioactive halogens (noble gases not included). Each SBGTS train is capable of

maintaining a small negative pressure in the reactor building under isolation conditions to

prevent ground-level escape of airborne activity. Exhaust from each SBGTS train is routed

through piping to the reactor building ventilation chimney. Process moisture removed by the

demister is drained to the reactor building equipment drain tank. Both SBGTS trains are

connected by a cross-tie line containing a restricting orifice and isolation damper. During

operation, the primary train provides cooling flow to the standby train through the cross-tie line

with air from the reactor building atmosphere at Dresden and from the turbine building at Quad

Cities. The primary SBGTS train fan provides the motive force for both the treated flow through

the primary train and the cooling flow through the standby train.

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In LRA Section 2.3.2.9, the applicant described the evaluation boundary of the SBGTS. In

addition, the applicant highlighted those portions of the SBGTS and its structures and

components that are within the scope of the Rule in the P&lDs listed as references in LRA

Section 2.3.2.9. Also, based on the methodology described in LRA Section 2.1.5 for identifying

the mechanical components subject to an AMR, the applicant identified the following

component groups and their intended functions within the SBGTS system in LRA Table 2.3.2-9

as being within the scope of license renewal and subject to an AMR:

* closure bolting (pressure boundary)

* ducts-including piping and fittings (pressure boundary)

* doors, closure, closure bolts, equipment frames-including inlet bells, restricting orifices,

and tubing (pressure boundary)

* doors, closure, closure bolts, equipment frames-including restricting orifices and exhaust

header (throttle)

* fan housings (pressure boundary)

* filters/strainers-including demisters (Dresden only, pressure boundary)

* flex collars, doors, and damper seals (pressure boundary)

* housings and supports including filters (pressure boundary)

* manifolds (pressure boundary)

* NSR vents or drains, piping, and valves-including tubing (structural integrity/attached

support)

* seals (pressure boundary)

* tubing (structural integrity/attached)

* tubing (pressure boundary)

* valves (pressure boundary)

* valves (structural integrity/attached)

2.3.2.9.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.9, Dresden UFSAR Section 6.5.3, and Quad Cities

UFSAR Section 6.5.3 to determine whether there is reasonable assurance that the SBGTS

components within the scope of license renewal and subject to an AMR have been identified in

accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff's review was conducted in

accordance with Section 2.3 of NUREG-1800.

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In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the SBGTS in the LRA. The staff did not identify any omissions.

Also, the staff selected system functions described in the UFSARs that were required by

10 CFR 54.4 to verify that components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the SBGTS that are within the scope of

license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1), respectively, the staff compared the referenced P&lDs to the system

drawings and system descriptions in the UFSARs to ensure that the referenced P&lDs were

representative of the SBGTS. The staff then reviewed the referenced P&lDs to verify that those

portions of the SBGTS that meet the scoping requirements of 10 CFR 54.4 are included within

the scope of license renewal and are identified as such by the applicant in LRA Section 2.3.2.9

and that the applicant identified all SBGTS components within the scope of license renewal and

subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.2.9 identified areas in which additional information is

necessary to complete the staff's review of the applicant's scoping and screening results.

Therefore, by the letter of August 4, 2003, the staff issued RAls to the applicant concerning the

specific items needed to determine whether the applicant has properly applied the scoping and

screening criteria of 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's RAls and the applicant's

responses by letter dated October 3, 2003, are described below.

RAI 2.3.2.9-1. Ventilation damper housings are highlighted on the ventilation flow diagrams

identified in the LRA as within the scope of license renewal. While ventilation damper housings

are highlighted as within the scope of license renewal, ventilation damper housings are not

identified in the application tables that identify component groups requiring AMR. Examples of

ventilation damper housings not identified in the component groups requiring AMR application

tables include the following:

* standby gas treatment system, Table 2.3.2-9

* standby blackout building HVAC, Table 2.3.3-10

* reactor building HVAC, Table 2.3.3-8 (Quad Cities HVAC butterfly isolation valve housings)

The staff asked the applicant to state whether these components are within the scope of license

renewal and subject to an AMR. If they are, the staff asked the applicant to provide the

relevant information about the components so that the staff can complete the component

groups requiring AMR tables of the LRA. If the components are not in scope or subject to an

AMR, the applicant must provide justification for their exclusion.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.2.9-1 stated that the ventilation damper housings

highlighted on boundary diagrams LR-DRE-M-49 and LR-QDC-M-44 for the SBGTS are within

the scope of license renewal and subject to an AMR. These ventilation dampers are included

under the component group "valves" found in LRA Table 2.3.2-9.

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The ventilation damper housings highlighted on boundary diagrams LR-DRE-M-4356-1, 2, 3, 4,

and 5, and LR-QDC-M-3033-1, and 2 for the station blackout building HVAC system are within

the scope of license renewal and subject to an AMR. These ventilation dampers were

evaluated with the component group 'doors, closure bolts, equip frames" found in LRA Table

2.3.3-10.

The Quad Cities HVAC butterfly isolation valves highlighted on boundary diagrams

LR-QDC-371 and LR-QDC-M-371-1 for the reactor building HVAC system are within the scope

of license renewal and subject to an AMR. These ventilation dampers were evaluated with the

component group 'doors, closure bolts, equip frames" in LRA Table 2.3.3-8.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.2.9-1 acceptable because it conforms with the criteria set forth

in 10 CFR 54.4 and 10 CFR 54.21(a)(1). Therefore, the staff considers its concern described in

RAI 2.3.2.9-1 resolved.

RAI 2.3.2.9-2. The following passive components associated with ventilation system ductwork

are not identified as within the scope of license renewal or subject to an AMP:

* ductwork turning vanes

* ventilation system elastomer seals

* ventilation equipment vibration isolator flexible connections

* ductwork test connections

* ductwork access doors

The staff asked the applicant to state whether it agrees that these components are within the

scope of license renewal and subject to an AMR. If they are, the applicant must provide the

information necessary to complete the AMR result tables. If these components are not in scope

and subject to an AMR, the applicant must provide justification for their exclusion.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.2.9-2 stated that ductwork turning vanes and the ductwork

access doors were evaluated as part of the ductwork. The ductwork is included within the

scope of license renewal and is subject to an AMR. The ductwork is included on LRA Tables

2.3.3.7, 2.3.3.8, and 2.3.3.10 and is evaluated under the component group 'Doors, closure

bolts, equip frames."

Ventilation system elastomer seals and ventilation equipment vibration isolator flexible

connections are included within the scope of license renewal and are subject to an AMR. The

seals and flexible connections are included on LRA Tables 2.3.3.7, 2.3.3.8, and 2.3.3.10 and

are evaluated under the component group, "flex collars, doors, duct and damper Seals."

Ductwork test connections are within the scope of license renewal and are subject to an AMR.

The test connections are included on LRA Tables 2.3.3.7, 2.3.3.8, and 2.3.3.10 under the

component group, "duct fittings, hinges, latches."

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.2.9-2 acceptable because it conforms with the criteria set forth

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in 10 CFR 54.4 and 10 CFR 54.21 (a)(1). Therefore, the staff considers its concern described in

RAI 2.3.2.9-2 resolved.

RAI 2.3.2.9-3. The staff asked the applicant to clarify whether structural sealants used to

maintain the power block building pressure boundary envelope (i.e., main control room,

auxiliary building, fuel handling building, reactor building) at design pressure with respect to the

adjacent areas are included in the scope of license renewal and subject to an AMR. The staff

asked for information relating to structural sealant use as referenced in Table 2.1-3 on page

2.1-15 of NUREG-1800. According to NUREG-1800, an applicant's structural AMP is expected

to address structural sealants with respect to an AMR program. If structural sealants are not in

the scope of license renewal and subject to an AMR, the applicant must provide justification for

their exclusion.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.2.9-3, the applicant stated that structural sealants used to maintain

the power block building pressure boundary envelope are included in the scope of license

renewal and subject to an AMR.

The following structures have caulking and sealant within the scope of license renewal and are

subject to an AMR:

* Reactor buildings roof joints and blowout panel seals are included in LRA Table 2.4-2 under

the component group, ucaulking/sealants."

* Contaminated condensate storage tanks foundations tank seals are included in LRA Table

2.4-10 under the component group "caulking/sealants."

* Exhaust duct penetration sealant located in the station blackout battery room (Dresden only)

and the station blackout day tank rooms (Quad Cities only) is included in LRA Table 2.4-6

under the component group "caulking/sealants."

* Station chimney sealant at manhole elevation 561' at Dresden and sealant at manhole

elevation 638'-6' at Quad Cities are included in LRA Table 2.4-13 under the component

group "caulking/sealants."

* 2/3 isolation condenser pump house (Dresden only) roof flashing to reactor building

interface is included in LRA Table 2.4-7 under the component group "caulking/sealants."

* Turbine building caulking/sealant is included in LRA Table 2.4-4 under the component

group, "caulking/sealants."

* Control room (both stations) and auxiliary electrical equipment room (Dresden only)

penetration seal caulking/sealant is included in LRA Table 2.4-3 under the component group

"penetration seals."

A new component group 'caulking/sealants,' should have been included in LRA Table 2.4-3

with a component intended function of structural pressure barrier.

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Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.2.9-3 acceptable because the applicant identified structures'

caulking and sealant as within the scope of license renewal and subject to an AMR in

accordance with the criteria set forth in 10 CFR 54.4 and 10 CFR 54.21 (a)(1). Therefore, the

staff considers its concern described in RAI 2.3.2.9-3 resolved.

RAI 2.3.2.9-4. The applicant did not describe its process of evaluating consumables in the

LRA. The staff asked the applicant to state whether its evaluation process for consumables is

subject to screening guidance in accordance with Table 2.1-3 of NUREG-1800. If consumables

are not considered subject to NUREG-1800 scoping and screening guidance, the applicant

should provide a justification for their exclusion.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.2.9-4 states that Exelon concurs that the process of

evaluating consumables was not described in the LRA. However, the Exelon process for

evaluating consumables was consistent with the screening guidance provided in Table 2.1-3 of

NUREG-1 800 and the NRC memo to NEI, Mr. C.l. Grimes to Mr. D.J. Walters, License

Renewal Issue No. 98-12, "Consumables," dated March 10, 2000. The following describes

Exelon's process for evaluating consumables.

Group (a) subcomponents (packing, gaskets, component seals, and O-rings) of pressure

boundary components were not listed explicitly in scoping and screening. The pressure

boundary components that include packing, gaskets, seals, and O-rings as subcomponents

have been designed to industry codes and standards, such as ANSI 831.1 or ASME Code,

Section III, and do not rely on such subcomponents to maintain the structural integrity of the

pressure boundary. The Dresden and Quad Cities specifications that implement the codes and

standards applicable to piping and piping components do not list these as pressure boundary

components, and these components are not credited with maintaining the pressure boundary

function.

Group (b) subcomponents (structural sealants) were not called out explicitly in scoping and

screening. The AMRs for structures determined whether structural sealants were credited with

an intended function and, where applicable, included them in an appropriate AMP.

Group (c) consumables (oil, grease, and component filters) were not listed in scoping and

screening and are not subject to AMR because they are periodically replaced.

Group (d) consumables (system filters, fire extinguishers, fire hoses and air packs) were not

listed in scoping and screening because these items are replaced on condition. System filters

are replaced based on manufacturers' requirements. Fire extinguishers, fire hoses and air

packs are periodically inspected or tested consistent with instructions that implement applicable

National Fire Protection Association (NFPA) guidelines as documented in the fire hazards

analysis for each station.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.2.9-4 acceptable because it conforms with the criteria set forth

in 10 CFR 54.4 and 10 CFR 54.21(a)(1). Therefore, the staff considers its concern described in

RAI 2.3.2.9-4 resolved.

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2.3.2.9.3 Conclusions

The staff reviewed LRA Section 2.3.2.9, the accompanying scoping boundary drawings, and the

applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. In addition, the staff performed an

independent assessment to determine whether any components that should be subject to an

AMR were not identified by the applicant. The staff did not identify any omissions. On the

basis of this review, the staff concludes that the applicant has appropriately identified the

components of the SBGTS that are within the scope of license renewal, as required by 10 CFR

54.4(a), and that the applicant has appropriately identified the components of the SBGTS that

are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.2.10 Automatic Depressurization System

2.3.2.10.1 Summary of Technical Information in the Application

The applicant described the automatic depressurization system (ADS) in LRA Section 2.3.2.10.

The applicant did not provide a list of components subject to AMR. However, under the title,

"Table 2.3.2-10," in LRA Section 2.3.2.10, the applicant stated that Dresden and Quad Cities

design-basis documents treat the ADS relief valves and associated piping, solenoids, pressure

controllers, and position switches as components of the main steam system. These mechanical

components of the ADS subject to an AMR are included as components of the main steam

system in this LRA.

The ADS, which is a safety-related system, has the function of providing backup for the HPCI

system and performing vessel depressurization for all "small breaks" inside the primary

containment or "small unisolable breaks outside the containment. Using the methodology

described in LRA Section 2.1.4.1 for identifying the mechanical components within the scope of

license renewal, the applicant identified the following ADS intended functions:

* core cooling-provides core cooling by receiving process signal inputs and providing,

through appropriate relay logic, actuation signal outputs to relieve valves assigned to the

main steam system (opening of the relief valves actuated by the ADS depressurizes the

reactor vessel to support LPCI and low-pressure core spray operation)

* credited in regulated event(s)-provides emergency core cooling credited in mitigation of

the Appendix R fire protection and SBO events

The ADS is one of the ECCSs designed to operate with the LPCI and CS to protect reactor

vessel/fuel in situations where the vessel is losing coolant. At Quad Cities, LPCI is anoperational mode of the RHR system. For small breaks, the vessel is depressurized in

sufficient time to allow the CS or LPCI to provide adequate core cooling. For large breaks, the

vessel depressurizes through the break without assistance. The ADS evaluation boundary

comprises the logic relays, timers, and instrumentation that receives process signal input and

provides actuation signals to the relief valves actuated by the-ADS. The ADS uses five

safety/relief valves, which are part of the main steam system, to carry out its function. The

safety/relieve valves and their tail pipes, and vacuum breaker valves, related solenoids,

pressure controllers, position switches, and pneumatic air components associated with the

safety/relief valves are evaluated with the main steam system in LRA Section 2.3.4.1. The

suppression chamber and T-quenchers, through which steam is discharged into the

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suppression pool during ADS operation, are both evaluated with the primary containment

structure in LRA Section 2.4.1.

2.3.2.10.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.10, Dresden UFSAR Sections 6.3.1 and 6.3.2, and Quad

Cities UFSAR Sections 6.3.1 and 6.3.2 to determine whether there is reasonable assurance

that the components of the ADS within the scope of license renewal and subject to an AMR

have been identified in accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's

review was conducted in accordance with Section 2.3 of NUREG-1800.

In performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified as an ADS intended function in the LRA. The staff did

not identify any omissions

Also, the staff selected system functions described in the UFSARs that were set forth in

10 CFR 54.4 to verify that the components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

As discussed above under the title uTable 2.3.2-10" in LRA Section 2.3.2.10, the applicant

stated that the mechanical components of the ADS subject to an AMR are included as

components of the main steam system in the LRA. The staff reviewed LRA Section 2.3.4.1 to

verify that the scoping and screening section for the main steam system included all the

mechanical components that support the ADS operation. The staff found all the mechanical

components that support the ADS operation included with the main steam system with the

exception of the T-quenchers, which the licensee stated in LRA Section 2.3.2.10 were

evaluated with the primary containment. The staff's evaluation of the primary containment is

provided in Section 2.4.1 of this SER.

2.3.2.10.3 Conclusions

The staff reviewed LRA Section 2.3.2.10 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. No

omissions were found. On the basis of its review, the staff concludes that the applicant has

adequately identified the components of the ADS that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and that the applicant has adequately identified the components

of the ADS that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.2.11 Anticipated Transient Without Scram System

The applicant noted that the ATWS system is not classified in the Dresden or Quad Cities

UFSAR as an ESF. However, the ATWS system is evaluated in this section because of

similarities with other systems that are characterized as ESF systems.

2.3.2.11.1 Summary of Technical Information in the Application

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The applicant described the ATWS system components in LRA Section 2.3.2.11 and provided a

list of components subject to an AMR in LRA Table 2.3.2-11.

The ATWS system provides the instrumentation and logic necessary for control rod insertion

and recirculation pump trips to mitigate the effects of an ATWS situation.

ATWS events are beyond design-basis accidents. They are low-probability events in which an

anticipated transient occurs and is not followed by an automatic reactor

shutdown (scram) when required. The failure of the reactor to scram quickly during these

transients can lead to unacceptable reactor coolant system pressures and to fuel damage. The

ATWS system logic, when energized, will reposition alternate rod insertion (ARI) solenoid

valves to depressurize the scram air header for control rod insertion and, in the event of an

automatic initiation, trip the recirculation pump motor generator field breakers. The ATWS

system is divided into two separate systems. The trip logic circuitry of each ATWS system

division is capable of performing the required mitigating action (tripping both recirculation pump

motor generator field breakers and actuating three of the six ARI valves). The ATWS system

will automatically initiate upon signals of high reactor pressure or low-low reactor water level.

The ATWS system can also be initiated manually.

Intended functions within the scope of license renewal include the following:

* reactivity control-provides an alternate means of control rod insertion and trips reactor

recirculation pump M-G set field breakers

* credited in regulated event(s)-provides reactivity control credited in mitigation of ATWS

events

Table 2.3.2-11 of the LRA identified the component groups requiring AMR. The component

groups identified for ATWS include:

* closure bolting

* piping and fittings

* valves

2.3.2.11.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.11, Dresden UFSAR Section 7.8 and Quad Cities UFSAR

Section 7.8 to determine whether there is reasonable assurance that the components of the

ATWS system within the scope of license renewal and subject to an AMR have been identified

in accordance with 10 CFR 54.4 and 54.21 (a)(1). The staff's review was conducted in

accordance with Section 2.3 of the SRP for License Renewal (NUREG-1 800) and is described

below.

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As part of

the evaluation, the staff determined whether the applicant had properly identified the SSCs

within the scope of license renewal and subject to an AMR, pursuant to 10 CFR 54.4(a) and

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10 CFR 54.21 (a)(1). The staff reviewed the relevant portions of the UFSAR for the reactor

vessel and associated components and compared the information in the UFSAR with the

information in the LRA to identify those portions that the LRA did not identify as being within the

scope of license renewal and subject to an AMR. The staff then reviewed the SCs that were

identified as not being within the scope of license renewal to verify that (1) these SCs do not

have any of the intended functions delineated under 10 CFR 54.4(a), and (2) for those SCs that

have an applicable intended function(s), verify that they either perform this function(s) with

moving parts or a change in configuration or properties, or that they are subject to replacement

based on a qualified life or specified time period, as described in 10 CFR 54.21 (a)(1).

The staff also reviewed the UFSAR for any functions delineated under 10 CFR 54.4(a) that

were not identified as intended functions in the LRA, to verify that the SSCs with such functions

will be adequately managed so that the functions will be maintained consistent with the CLB for

the extended period of operation.

2.3.2.11.3 Conclusions

The staff reviewed LRA Section 2.3.2.11 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. The

staff did not identify any omissions. On the basis of its review, the staff concludes the applicant

has adequately identified the components of the ATWS system that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the ATWS system that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.2.12 Evaluation Findings

On the basis of its review, the staff concludes that there is reasonable assurance that the

applicant has adequately identified the engineered safety features systems and components

that are within the scope of license renewal, in accordance with the requirements of 10 CFR

54.4(a), and that the applicant has adequately identified the engineered safety features that are

subject to an AMR, in accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.2.13 References

1. Letter from Patrick R. Simpson (Exelon) to the NRC, Additional Information for the Review

of the License Renewal Applications for Quad Cities Nuclear Power Station, Units 1 and 2

and Dresden Nuclear Power Station, Units 2 and 3," October 3, 2003.

2.3.3 Auxiliary Systems

2.3.3.1 Refueling Equipment

2.3.3.1.1 Summary of Technical Information in the Application

The applicant described the refueling equipment system in LRA Section 2.3.3.1 and provided a

list of components subject to an AMR in LRA Table 2.3.3-1.

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The purpose of the fuel handling system is to receive and transfer nuclear fuel in a manner that

precludes the occurrence of inadvertent criticality and to provide equipment for handling both

new and irradiated fuel. To achieve this purpose the fuel handling equipment is designed to

handle fuel assemblies and other reactor components. Using the methodology described in

LRA Section 2.1.4.1 for identifying mechanical components within the scope of license renewal,

the applicant identified the following intended refueling equipment functions:

* Maintain structural integrity to prevent collapse of the platform onto the spent fuel storage

racks or the reactor core.

* Preclude occurring of inadvertent criticality by providing interlocks for the movement of

cranes.

In LRA Section 2.3.3.1, the applicant described the evaluation boundary of the refueling

equipment system. Also, based on the methodology described in LRA Section 2.1.5 for

identifying the mechanical components subject to an AMR, the applicant identified the following

component groups and their intended functions within the refueling equipment system in LRA

Table 2.3.3-1 as being within the scope of license renewal and subject to an AMR at Dresden:

* cranes (structural support)

* fuel grapples (structural support)

* fuel pool gates (pressure boundary)

* fuel preparation machines (structural support)

2.3.3.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.1, Dresden UFSAR Section 9.1.4, and Quad Cities

UFSAR Section 9.1.4 to determine whether there is reasonable assurance that the refueling

equipment system components within the scope of license renewal and subject to an AMR have

been identified in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff's review

was conducted in accordance with Section 2.3 of NUREG-1 800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the refueling equipment system in the LRA. The staff did not

identify any omissions.

Also, the staff selected system functions described in the UFSARs that were set forth in

10 CFR 54.4 to verify that components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

The staff's review of LRA Section 2.3.3.1 identified areas in which additional information was

necessary to complete the staff's review of the applicant's scoping and screening results.

Therefore, by the August 4, 2003 letter, the staff issued RAls to the applicant concerning the

specific items to determine whether the applicant has properly applied the scoping and

screening criteria of 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's scoping RAI and the

applicant's responses by letter, dated October 3, 2003, are described below.

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RAI 2.3.3.1-1. The applicant included the reactor building overhead crane in the component

group 'cranes' requiring an AMR as listed in LRA Table 2.3.3-1. LRA Table 3.3.1 lists the

component group cranes as cranes including bridge and trolleys and rail system in load

handling system that require an AMR for loss of material due to general corrosion and wear

(AMR Ref. No. 3.3.1.14). The staff was unable to identify the components consisting of the

group cranes in order to verify the acceptability of the applicant's system scoping and screening

results. Therefore, the staff requested the applicant to identify the specific components of

cranes, which are within the scope of license renewal and subject to an AMR.

Applicant's Response and Staff's Evaluation

In response to RAI 2.3.3.1-1, the applicant stated under its response to RAI 2.4-9 that while the

type of components comprising crane subsystems can vary, the following cranes component

types require aging management-load carrying flanges; support structures; bolts, nuts, or

rivets; load blocks; suspension housings; hand chain wheels; chain attachments; clevis; yokes;

suspension bolts; shafts; gears; bearings; pins; rollers; lock and clamping devices; hook

retaining nuts; hook retaining collars/pins; retaining member welds; load sprockets; drums;

sheaves; hydraulic subsystems; cable; cable clamps; brakes; and bridge/beam structures.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.1-1 acceptable because it provided a list of the components

subject to an AMR in accordance with the criteria set forth in 10 CFR 54.21(a)(1). Therefore,

the staff considers its concern described in RAI 2.3.3.1-1 resolved.

RAI 2.3.3.1-2. The LRA Section 2.3.3.1 states that the major component of the refueling

equipment system includes the refueling platform assembly which consists of refueling platform, fuel grapple, and associated equipment. The staff was unable to identify the

components the applicant referred to as "associated equipment in order to verify the

acceptability of the applicant's system scoping and screening results. Therefore, the staff

requested the applicant to list components referred to as the "associated equipment," and

specify which components (if any) are within the scope of license renewal and subject to an

AMR.

Applicant's Response and Staff's Evaluation

In response to RAI 2.3.3.1-2, the applicant identified the following components as "associated

equipment":

The refueling platform bridge includes a walkway, railings and a trolley mounted control cab, a main

grapple hoist, the adjacent frame mounted auxiliary hoist, a reverse mounted monorail auxiliary hoist,

a hinged jib arm powerwinch, and the reels, drives, pulleys, and sheaves required for the hoist cables

and the service air lines from the self contained, refueling platform mounted air compressor. The

bridge air system includes the compressor, air receiver, shutoff valves, solenoid valves, air hose

retrieval assist drives, and quick disconnect fittings.

The applicant also stated that all of the above-listed components are in the scope of license

renewal and subject to an AMR.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.1-2 acceptable because it provided a list of the components

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subject to an AMR in accordance with the criteria set forth in 10 CFR 54.21 (a)(1). Therefore,

the staff considers its concern described in RAI 2.3.3.1-2 resolved.

RAI 2.3.3.1-3. The LRA Section 2.3.3.1 states that the inboard main steamline plugs, vents,

and regulators associated with the reactor vessel system are evaluated with the refueling

equipment system. The applicant did not provide the results of this evaluation and the staff was

unable to verify the acceptability of the applicant's system scoping and screening results.

Therefore, the staff requested the applicant to clarify whether any of the above components are

within the scope of license renewal and subject to an AMR.

Applicant's Response and Staff's Evaluation

In response to RAI 2.3.3.1-3, the applicant stated that the inboard main steamline plugs, vents,

and regulators referenced in LRA Section 2.3.3.1 are temporary pieces of equipment (line

plugs) installed to facilitate refueling operations. This equipment is not within the scope of

license renewal and, therefore, not subject to an AMR.

Because the applicant stated that the subject components are temporary pieces of equipment

installed to facilitate refueling operations, the staff agrees that they are not subject to an AMR

since they are periodically replaced. Therefore, the staff finds the applicant's response to RAI

2.3.3.1-3 acceptable and considers its concern described in RAI 2.3.3.1-3 resolved.

2.3.3.1.3 Conclusions

The staff reviewed LRA Section 2.3.3.1, the accompanying scoping boundary drawings, and the

applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. In addition, the staff performed an

independent assessment to determine whether any components that should be subject to an

AMR were not identified by the applicant. The staff did not identify any omissions. On the'

basis of its review, the staff concludes that the applicant has adequately identified the

components of the refueling equipment system that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and that the applicant has adequately identified the components-of

the refueling equipment system that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.2 Shutdown Cooling System (Dresden only)

2.3.3.2.1 Summary of Technical Information in the Application

The applicant described the shutdown cooling system (SDCS) in LRA Section 2.3.3.2 and

provided a list of components subject to an AMR in LRA Table 2.3.3-2.

The function of SDCS at Dresden Station is to provide cooling of the reactor water when the

temperature and pressure in the reactor fall below the point at which the main condenser can

no longer be used as a heat sink following reactor shutdown. The system can also be used to

help cool the fuel pool during refueling outages and to heat reactor water with steam from the

plant heating system during startup from cold shutdown.

Using the methodology described in LRA Section 2.1.4.1 for identifying the mechanical

components within the scope of license renewal, the applicant identified the following SDCS

intended functions:

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* pressure boundary-maintains the integrity of the reactor coolant pressure boundary

* provides containment isolation-for those portions of the system that interface with the

primary containment

* core cooling-provides heat removal sufficient to achieve and maintain cold shutdown

conditions during normal operation

* credited in regulated events-provides heat removal sufficient to achieve and maintain cold

shutdown conditions during normal operation (This core cooling function is credited in

mitigation of the Appendix R fire event. The system contains components that are relied

upon for compliance with 10 CFR 50.49 (Equipment Qualification)).

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected

The SDCS consists of three partial capacity cooling loops, each containing a pump, a heat

exchanger, and associated piping, valves and instrumentation. The system takes suction from

either reactor recirculation loop, delivers the flow through each of the three separate cooling

loops, and then directs it to the LPCI injection lines. Capability also exists to permit flow from

both reactor recirculation loops to both LPCI injection lines simultaneously. When used to

augment fuel pool cooling, only one of the cooling loops is required. Each cooling loop is

provided with a minimum flow valve to return pump discharge flow to the pump suction. The

system heat exchangers are cooled by water from the reactor building closed cooling water

(RBCCW) system in the cooling mode and heated by steam from the plant heating system in

the heating mode. Provision is also made for chemical sampling, cleanup via the reactor water

cleanup system, and system drainage to the reactor building equipment drain system. The

SDCS is also used to help cool the fuel pool during refueling outages and to heat reactor water

with steam from the heating boiler during startup from cold shutdown.

In LRA Section 2.3.3.2, the applicant described the evaluation boundary of the SOCS. In

addition, the applicant highlighted those portions of the SDCS and its structures and

components that are within the scope of the Rule in the P&l drawings listed as references in

LRA Section 2.3.3.2. Also, based on the methodology described in LRA Section 2.1.5 for

identifying the mechanical components subject to an AMR, the applicant identified the following

component groups and their intended functions within the SDCS in LRA Table 2.3.3-2 as being

within the scope of license renewal and subject to an AMR at Dresden:

* closure bolting (pressure boundary)

* dampeners (pressure boundary)

* filters/strainers (pressure boundary)

* filters/strainers (filter)

* heat exchangers (pressure boundary)

* heat exchangers (heat transfer)

* NSR vents or drains, piping, and valves (structural integrity/attached support)

* piping and fittings (pressure boundary)

* pumps (pressure boundary)

* restricting orifices (pressure boundary)

* restricting orifices (throttle)

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* sight glasses (pressure boundary)

* sight glasses (structural integrity/attached support)

* thermowells (pressure boundary) l

* valves (pressure boundary)

2.3.3.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.2 and Dresden UFSAR Section 5.4.7, as well as other

UFSAR Sections that discussed the SDCS, which included Sections 1.2.2, 1.9.2, 3.1.2, 3.2.9,

3.3.2, 3.6.2, 3.8.5, 3.9.2, 5.1, 5.2.2, 5.4.1, 5.4.7, 6.2, 6.3.1, 7.1.3, 7.3.2, 7.4.2, 9.1.2, 9.1.3,

9.2.3, 9.3.2, 12.3.2, 12A.2, 12A.4, 14.2.4, and 15.6.4, to determine whether there is reasonable

assurance that the SDCS components within the scope of license renewal and subject to an

AMR have been identified in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff's

review was conducted in accordance with the Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the SDCS system in the LRA. The staff did not identify any

omissions.

Also, the staff selected system functions described in the UFSARs that were set forth in

10 CFR 54.4 to verify that components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the SDCS that are within the scope of

license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the

system drawings and system descriptions in the UFSARs to ensure that the referenced P&l

drawings were representative of the SDCS. The staff then reviewed the referenced P&l

drawings to verify that those portions of the SDCS that meet the scoping requirements of

10 CFR 54.4 are included within the scope of license renewal and are identified as such by the

applicant in LRA Section 2.3.3.2; and that the applicant identified all SDCS components within

the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21(a)(1).

The staff's review of LRA Section 2.3.3.2 identified areas in which additional information is

necessary to complete the staff's review of the applicant's scoping and screening results.

Therefore, by the August 4, 2003, letter, the staff issued RAls to the applicant concerning the

specific items to determine whether the applicant has properly applied the scoping and

screening criteria of 10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff's RAls and the applicant's

responses by letter, dated October 3, 2003, are described below.

RAI 2.3.3.2-1. License renewal boundary drawing LR-DRE-M-32, "Shutdown Reactor Cooling

Piping," (at A-7) shows a 0.5 in. pipe that is in scope (colored green) that goes from the SDCS

pump 2-1002A seal cooler, to drawing LR-DRE-M-39, "Reactor Building Equipment Drains" (at

A-8), where it ties into a pipe that goes from valve 2-1001-213A to the same SDCS pump

shown on drawing LR-DRE-M-39. However, on drawing LR-DRE-M-39 the pipe is not shown in

scope (not color coded). The staff believes that the run of pipe shown on drawing

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LR-DRE-M-39 that comes from drawing LR-DRE-M-32, and the pipe it tees into, up to and

including valve 2-1001-213A and the SDCS pump, should be in scope for the same reason the

portion of that pipe on drawing LR-DRE-M-32 is in scope. This also applies to pumps 2-1002B

and C on drawings LR-DRE-M-32 and -39, as well as to pumps 3-1002A, B and C on drawings

LR-DRE-M-363 and 369. Please provide a justification for the exclusion of the portion of the

piping shown on drawings LR-DRE-M-39 and LR-DRE-M-369.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.2-1 is that boundary diagrams LR-DRE-M-32,

LR-DRE-M-39, LR-DRE-M-363, and LR-DRE-M-369 should have highlighted the piping from

the seal coolers to the shutdown cooling pumps, up to and including pumps 2(3)-1 002A, B, and

C and valves 2(3)-1001-213A, B, and C. Valves 2(3)-1001-213A, B, and C are included in LRA

Table 2.3.3-2, under component group "valves (Dresden only.)." The Aging Management

Reference for the internal environment is 3.3.1.8. The Aging Management Reference for the

external environment is 3.3.2.27. Pumps 2(3)-1002A, B, and C are included in Table 2.3.3-2,

under component group "pumps (Dresden only.)." The Aging Management Reference for the

internal environment is 3.3.1.8. The Aging Management Reference for the external

environment is 3.3.1.5.

Based on its review of the applicant's clarification discussed above, the staff concurs with the

applicant's clarification that the above-cited segments of piping and their associated

components are within the scope of the Rule, and they were inadvertently not highlighted in the

LR boundary diagrams. Also, because the components associated with the cited segments of

piping are included in LRA Table 2.3.3-2 subject to an AMR, the staff finds the applicant's

response to RAI 2.3.3.2-1 acceptable. Therefore, the staff considers its concern described in

RAI 2.3.3.2-1 resolved.

RAI 2.3.3.2-2. License renewal boundary drawing LR-DRE-M-32, "Shutdown Reactor Cooling

Piping," (at C-9) shows relief valve RV 2-1099-29, and the associated piping to the header, in

scope (colored Green). However, the equivalent relief valve, RV 3-1099-29, on LR-DRE-M363, "Shutdown Reactor Cooling Piping," (at C-9) is shown not in scope (not color coded). The

staff believes that RV 3-1099-29 on LR-DRE-M-363 should be in scope for the same reason

that RV 2-1099-29 on LR-DRE-M-32 is in scope. The relief valve provides a passive intended

function. Please provide a justification for the exclusion of RV 3-1099-29 on LR-DRE-M-363

and the associated piping to the main header.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.2-2 is that boundary diagram LR-DRE-M-363 should

have highlighted valve 3-1099-29 and the associated piping to the main header. However,

Dresden Station has plans to remove these valves from the plant design. Since the LRA was

prepared, a modification was completed under engineering change (EC) 338910 that removed

relief valve 3-1099-29 and replaced it with a blind flange. EC 340263, to remove relief valve

2-1099-29 from Dresden Unit 2, has not yet been implemented.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.2-2 acceptable because the subject valve will be removed

and replaced with a blind flange. Therefore, the staff considers its concern described in RAI

2.3.3.2-2 resolved.

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<*; !'t ': f 1: ' '

2.3.3.2.3 Conclusions

The staff reviewed LRA Section 2.3.3.2, the accompanying scoping boundary drawings, and the

applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. In addition, the staff performed an

independent assessment to determine whether any components that should be subject to an

AMR were not identified by the applicant. The staff did not identify any omissions. On the basis

of its review, the staff concludes that the applicant has adequately identified the components of

the SDCS that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that

the applicant has adequately identified the components of the SDCS that are subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.3 Control Rod Drive Hydraulic System

2.3.3.3.1 Summary of Technical Information in the Application

The applicant described the control rod drive hydraulic (CRDH) system in LRA Section 2.3.3.3

and provided a list of components subject to an AMR in LRA Table 2.3.3-3.

The purpose of the CRDH system is to (1) control changes in reactivity by incrementally

positioning the control rods in response to signals from the reactor manual control system, and

(2) shut down the reactor quickly by rapidly inserting control rods into the core in response to'

manual or automatic signal. The CRDH system is made up of supply pumps, filters, strainers,

control valves, and associated instrumentation and controllers. The CRDH system provides

water at the required pressures to the hydraulic control units for cooling and all types of

required control rod motion. The CRDH system allows control rod withdrawal or insertion at a

limited rate, one rod at a time, for power level control and flux shaping during reactor operation.

Using the methodology described in LRA Section 2.1.4.1 for identifying mechanical components

within the scope of license renewal, the applicant identified the following intended CRDH

system functions:

* Provide reactivity control to rapidly shut down (scram) the reactor under appropriate

conditions.

* Provide pressure boundary to support integrity of the reactor coolant pressure boundary and

to support in-scope pressure boundaries at interfaces with other in-scope systems.

* Provide (1) scram discharge volume vent and drain isolation valves which are credited to

remain closed in the 10 CFR 50, Appendix R fire event, and (2) alternate rod insertion

capability which is credited in the ATWS event. At Dresden only, CRDH system water

supply to the vessel is credited in the 10 CFR 50, Appendix R fire event. Also at Dresden

only, CRDH system contains components that are relied upon for compliance with 10 CFR

50.49, environmental qualification of electric equipment important to safety for nuclear

power plants.

* Preclude occurring of adverse effects on safety-related SSCs by maintaining sufficient

integrity of non-safety-related components that could be a hazard to safety-related SSCs so

that the intended function of safety-related SSCs is not adversely affected.

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In LRA Section 2.3.3.3, the applicant described the evaluation boundary of the CRDH system.

In addition, the applicant highlighted those portions of the CRDH system and its structures and

components that are within the scope of the Rule in the P&l drawings listed as references in

LRA Section 2.3.3.3. Also, based on the methodology described in LRA Section 2.1.5 for

identifying the mechanical components subject to an AMR, the applicant identified component

groups and their intended functions within the CRDH system in LRA Table 2.3.3-3 as being

within the scope of license renewal and subject to an AMR.

Resulting from the revised methodology described in the May 18, 2004 response to the draft

SER Open Item 2.1-1 and clarified in a letter, dated June 22, 2004, the applicant expanded the

system boundaries for the CRDH system at both Dresden and Quad Cities due to the potential

for spatial interaction with safety-related components. The applicant added all of the CRDH

components shown on revised boundary diagrams LR-DRE-M-34-1, LR-DRE-M-365-1,

LR-DRE-M-419-4, LR-QDC-M-41-4, and LR-QDC-M-83-4 to the scope of license renewal. The

applicant excluded the isolated vent and drain piping the CRDH system from the scope of

license renewal because the piping does not contain any fluid that could spatially interact with

safety-related equipment in the general area. These changes resulted in adding four

component groups to LRA Table 2.3.3-3.

The following is the component groups and their intended functions within the CRDH system in

the revised LRA Table 2.3.3-3 as being within the scope of license renewal and subject to an

AMR:

* accumulators (pressure boundary)

* closure bolting (pressure boundary)

* dampeners (pressure boundary, Quad Cities only)

* dampeners (spatial interaction, Quad Cities only)

* filters/strainers (pressure boundary)

* filters/strainers (filter)

* filters/strainers (spatial interaction) (leakage boundary (spatial), Quad Cities only)

* flow elements (spatial interaction)

* flow elements (pressure boundary, Dresden only)

* NSR vents or drains, piping, and valves (attached support)

* piping and fittings, including dampeners and tubing (pressure boundary)

* piping and fittings (spatial interaction)

* piping and fittings (attached support)

* pumps (pressure boundary) (Dresden only)

* pumps (spatial interaction) (leakage boundary (spatial), Quad Cities only)

* restricting orifices (pressure boundary, Dresden only)

* restricting orifices (spatial interaction) (leakage boundary (spatial), Quad Cities only)

* rupture discs (pressure boundary)

* tanks, including accumulators (pressure boundary)

* tubing (pressure boundary)

* tubing (spatial interaction) (leakage boundary (spatial), Quad Cities only)

* valves (pressure boundary)

* valves (spatial interaction)

* valves (attached support)

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2.3.3.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.3, Dresden UFSAR Section 4.6.3, and Quad Cities

UFSAR Section 4.6.3 to determine whether there is reasonable assurance that the CRDH

system components within the scope of license renewal and subject to an AMR have been

identified in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff's review was

conducted in accordance with Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the CRDH system in the LRA.

Also, the staff selected system functions described in the UFSARs that were set forth in 10

CFR 54.4 to verify that components having intended functions were not omitted from the scope

of the Rule. The staff also focused on components that were not identified as being subject to

an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the CRDH that are within the scope of

license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21(a)(1), respectively, the staff compared the referenced P&l drawings to the system

drawings and system descriptions in the UFSARs to ensure that the referenced P&l drawings

were representative of the CRDH. The staff then reviewed the referenced P&l drawings to

verify that those portions of the CRDH that meet the scoping requirements of 10 CFR 54.4 are

included within the scope of license renewal and are identified as such by the applicant in LRA

Section 2.3.3.3; and that the applicant identified all CRDH components within the scope of

license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1).

The staff's review of LRA Section 2.3.3.3 identified areas in which additional information was

necessary to complete the staff's review of the applicant's scoping and screening results.

Therefore, by the letter dated August 4, 2003, the staff issued RAls to the applicant concerning

the specific items to determine whether the applicant has properly applied the scoping and

screening criteria of 10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff's RAls and the applicant's

responses by letter, dated October 3, 2003, and supplemented by letter, dated December 17,

2003, are described below.

RAI 2.3.3.3-1. License renewal boundary diagram LR-QDC-M-41-1 for Quad Cities Unit 1

excludes the following sections of piping from the scope of license renewal, while piping at both

ends of these sections is identified as in scope:

* 1-0314A-1/2*-A (section from locations A-7 to E-9)

* 1-0314B-1/2"-A (section from locations A-4 to E-2)

* 1-0314-2"-A (section from locations A-5 to A-6)

* 1-0313-1"-C (section from locations B-5 to B-6)

* 1-0315-1 -A (section from locations B-5 to B-6)

License renewal boundary diagram LR-QDC-M-83-1 excludes the corresponding sections of

Quad Cities Unit 2 from the scope of license renewal. As such, the staff was unable to verify

the acceptability of the applicant's system scoping and screening results. Therefore, the staff

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requested the applicant to justify the exclusion of the above sections from the scope of license

renewal and an AMR.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.3.3-1, the applicant stated that it performed a plant walkdown on

non-safety-related control rod drive (CRD) hydraulic piping at Quad Cities to identify those

portions that could interact with safety-related SSCs. Portions of the non-safety-related piping

were included in the scope of license renewal for either spatial considerations or because the

piping is attached to safety-related SSCs. Because of the proximity of the CRDH headers to

safety-related components, some situations exist where portions of piping in the center of a

pipe run cannot spatially interact with any safety-related SSCs. For this reason, they were

excluded from the scope of license renewal.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.3-1 acceptable because the excluded portions are non-safetyrelated and not in the proximity of any safety-related SSCs. Therefore, the staff considers its

concern described in RAI 2.3.3.3-1 resolved.

RAI 2.3.3.3-2. License renewal boundary diagram LR-QDC-M-41-2 for Quad Cities Unit 1

excludes the piping from the exhaust water header and fittings and the pressure indicator

1-0302-77 from the scope of license renewal. However, the corresponding components for

Quad Cities Unit 2 are identified as in the scope of license renewal per 10 CFR 54.4(a)(2)

(license renewal boundary diagram LR-QDC-M-83-2). As such, the staff was unable to verify

the acceptability of the applicant's system scoping and screening results. Therefore, the staff

requested the applicant to justify exclusion of the above components of Quad Cities Unit 1 from

the scope of license renewal and an AMR.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.3.3-2, the applicant stated that it performed a plant walkdown on

non-safety-related CRD hydraulic piping at Quad Cities to identify those portions that could

interact with safety-related SSCs. Those portions of the non-safety-related piping on

LR-QODC-M-41-2 and LR-QDC-M-83-2 were included in the scope of license renewal for spatial

interaction with safety-related SSCs. The piping from the exhaust water header and fittings and

the pressure indicator 1(2)-0302-77 cannot spatially interact with safety-related SSCs and were

not included in the scope of license renewal. The applicant noted that it color-coded these

components incorrectly as in the scope of license renewal on LR-QDC-M-83-2 for Quad Cities

Unit 2. The applicant also noted that boundary diagram LR-QDC-M-41-2 correctly identifies

those portions falling within the scope of license renewal.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.3-2 acceptable because the excluded portions are non-safetyrelated and not in the proximity of any safety-related SSCs. Therefore, the staff considers its

concern described in RAI 2.3.3.3-2 resolved.

RAI 2.3.3.3-3. Several solenoid valves shown in license renewal boundary diagram

LR-QDC-M-41-2 for Quad Cities Unit 1 (e.g., SO 1-0302-19A at location F-1) are identified as

within the scope of license renewal. However, the piping connections to these valves are

excluded from the scope of license renewal. As such, the staff was unable to verify the

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acceptability of the applicant's system scoping and screening results. Therefore, the staff

requested the applicant to justify exclusion of the above components from the scope of license

renewal and an AMR.

Applicant's Response and Staff's Evaluation

In response to RAI 2.3.3.3-3, the applicant stated that the piping in question is non-safetyrelated instrument air system. The failure of this non-safety-related instrument air support

system piping will not affect any of the CRDH system's intended functions. Loss of instrument

air will cause the CRD scram valves to fail open, inserting the control rods into the core and

causing other air-operated CRDH system valves to fail in their fail-safe positions. There are

small segments of safety-related instrument air piping (such as that connecting solenoid valves

SO 1-0305-117 and SO 1-0305-118) for each CRD hydraulic control unit that are included in

the scope of license renewal.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.3-3 acceptable because the applicant stated that the piping in

question is non-safety-related instrument air system; the failure of this non-safety-related

instrument air support system piping will not affect any of the CRDH system's intended

functions; and the small segments of safety-related instrument air piping for each CRD

hydraulic control unit are included in the scope of license renewal. Therefore, the staff

considers its concern described in RAI 2.3.3.3-3 resolved.

RAI 2.3.3.3-4. License renewal boundary diagram LR-QDC-M-41-2 for Quad Cities Unit 1

shows the pressure indicator, component PI 1-032-80, as within the scope of license renewal.

However, a similar component at the same location, pressure switch, component PS 1-032-81

is excluded from the scope of license renewal. As such, the staff was unable to verify the

acceptability of the applicant's system scoping and screening results. Therefore, the staff

requested the applicant to justify exclusion of component PI 1-032-80 from the scope of license

renewal and an AMR.--

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.3.3-4, the applicant stated that pressure indicator PI 1-0302-80,

manual instrument shutoff valve 1-0302-80, and the connecting tubing to the non-safety-related

instrument air system should not have been highlighted on boundary diagram LR-QDC-M-41-2.

As stated in the response to RAI 2.3.3.3-3, the failure of this non-safety-related instrument air

support system piping will not affect any of the CRDH system's intended functions. Therefore,

both PI-0302-80 and PS 1-0302-81 are outside the scope of license renewal.

Based on its review of the applicant's clarification discussed above, the staff finds that the

applicant's response to RAI 2.3.3.3-4 is in accordance with the criteria set forth in 10 CFR

54.4(a) and acceptable. Therefore, the staff considers its concern described in RAI 2.3.3.3-4

resolved.

RAI 2.3.3.3-5. License renewal boundary diagram LR-QDC-M-41-2 identified CRDs as within

the scope of license renewal. However, LRA Table 2.3.3-3 does not list CRDs as within the

scope of license renewal. As such, the staff was unable to verify the acceptability of the

applicant's system scoping and screening results. Therefore, the staff requested the applicant

to justify the exclusion of CRDs from LRA Table 2.3.3-3.

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Applicant's Response and Staff's Evaluation

In response to RAI 2.3.3.3-5, the applicant stated that component groups listed in LRA Table

2.3.3-3 only include those components requiring an AMR. Although CRIs are in the scope of

license renewal, they were screened as "active" components. As such, they do not require an

AMR and were not included in LRA Table 2.3.3-3.

Based on its review, the staff concurs with the applicant's clarification that CRDs are in the

scope of license renewal, however, they are active components and not subject to an AMR.

Therefore, the staff finds that the applicant's response to RAI 2.3.3.3-5 is in accordance with

the criteria set forth in 10 CFR 54.4(a) and acceptable. The staff considers its concern

described in RAI 2.3.3.3-5 resolved.

RAI 2.3.3.3-6. License renewal boundary diagram LR-QDC-M-41-2 for Quad Cities Unit 1

shows that the license renewal boundary for 2.5 in. piping section at location B-1 0 ends at an

undistinguishable location. As such, the staff was unable to verify the acceptability of the

applicant's system scoping and screening results. Therefore, the staff requested the applicant

to explain why (1) the piping section up to and including valve 1-0301-7, and (2) the

corresponding piping section of Quad Cities Unit 2 (license renewal boundary diagram

LR-QDC-M-83-2) up to and including valve 2-0301-7, were excluded from the scope of license

renewal.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.3.3-6, the applicant stated that it performed a plant walkdown on

non-safety-related CRDH. Portions of non-safety-related CRD hydraulic components depicted

on boundary diagrams LR-QDC-M-41-2 and LR-QDC-M-83-2 are included in the scope of

license renewal because the components could spatially interact with safety-related SSCs

located in the same area. The CRD pump discharge line, 1(2)-8302C-2-1/2*, is included in the

scope of license renewal from the point that the line enters the reactor building (A-10) to where

that line and others downstream of it no longer can spatially interact with safety-related SSCs.

Based on its review of the applicant's clarification discussed above, the staff finds that the

applicant's response to RAI 2.3.3.3-6 is in accordance with the criteria set forth in 10 CFR

54.4(a) and acceptable. Therefore, the staff considers its concern described in RAI 2.3.3.3-6

resolved.

RAI 2.3.3.3-7. License renewal boundary diagram LR-QDC-M-83-1 for Quad Cities Unit 2

excludes the following 0.75 in.-diameter sections of piping between the reducer and the quick

disconnect from the scope of license renewal:

* line containing valve 2-0301-139A at location A-7

* line containing valve 2-0301-138A at location A-7

* line containing valve 2-0301-137A at location B-7

* line containing valve 2-0301-136A at location C-7

* line containing valve 2-0301-136B at location C-4

However, license renewal boundary diagram LR-QDC-M-41-1 shows that the corresponding

sections of Quad Cities Unit 1 are included in the scope of license renewal. As such, the staff

was unable to verify the acceptability of the applicant's system scoping and screening results.

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Therefore, the staff requested (in RAI 2.3.3.3-7) the applicant to justify the exclusions of the

above sections of Quad Cities Unit 2 from the scope of license renewal and an AMR.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.3.3-7, the applicant stated that lines and valves 2-0301-136A,

2-0301-136B, 2-0301-137A, 2-0301-138A, and 2-0301-139A are included in the scope of

license renewal. Boundary diagram LR-QDC-M-83-1 should have highlighted the components.

They are included in LRA Table 2.3.3-3, under component group "NSR vents or drains, piping

and valves (attached support)."

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.3-7 acceptable because it is in accordance with the criteria

set forth in 10 CFR 54.4 and 10 CFR 54.21(a)(1). Therefore, the staff considers the concern

described in RAI 2.3.3.3-7 resolved.

RAI 2.3.3.3-8. License renewal boundary diagram LR-DRE-M-34-1 for Dresden Unit 2 shows

that the license renewal boundary for 1.5 in. piping section at location B-5 (cooling water

pressure control station) ends at normally open valve 2-0301-72. The staff was not certain

whether the license renewal boundary should continue beyond this valve. As such, the staff

was unable to verify the acceptability of the applicant's system scoping and screening results.

Therefore, the staff requested the applicant to explain why (1) the piping section beyond this

value, and (2) the corresponding piping section of Dresden Unit 3 (license renewal boundary

diagram LR-DRE-M-365-1) beyond valve 3-0301-72 were excluded from the scope of license

renewal.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.3.3-8, the applicant stated that it expanded the in-scope portion of

the Dresden CRDH system as shown on license renewal boundary diagrams LR-DRE-M-34-1

and LR-DRE-M-365-1 to include all downstream pipe lines that would be isolated by closing

valve 2(3)-0301-72. The applicant made this change in its responses to RAI 2.1-02 and to

Supplement RAI 2.1-02b. The expanded boundary includes all of the piping, fittings, valves,

and piping components downstream of valve 2(3)-0301-72, up to and including points of

termination at blank flanges, at normally closed vent or drain valves, at instrumentation, or at

points of interface with portions of the piping system already designated as in-scope for license

renewal. The additional piping, fittings, valves, and piping components the applicant included

in-scope are constructed of the same materials, are in the same environments, and perform the

same intended functions as components listed in LRA Table 2.3.3-3. Therefore, LRA Table

2.3.3-3, which lists components groups of CRDH system requiring aging management review,

needed no change to encompass the expanded in-scope boundary.

Based on its review of the applicant's expanded in-scope boundary discussed above, the staff

finds the applicant's response to RAI 2.3.3.3-8 acceptable because it is in accordance with the

criteria set forth in 10 CFR 54.4 and 10 CFR 54.21 (a)(1). Therefore, the staff considers the

concern described in RAI 2.3.3.3-8 resolved.

RAI 2.3.3.3-9. License renewal boundary diagram LR-DRE-M-365-1 for Dresden Unit 3

excludes the following sections of piping from the scope of license renewal:

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* from valve 3-0301-60 to and including valve 3-0301-61 at location B-4

* from valve 3-0301-53 to and including valve 3-0301-54 at location B-2

However, the corresponding sections of Dresden Unit 2 are included in the scope of license

renewal (license renewal boundary diagram LR-DRE-M-34-1). As such, the staff was unable to

verify the acceptability of the applicant's system scoping and screening results. Therefore, the

staff requested the applicant to justify the exclusions of the above sections of Dresden Unit 3

from the scope of license renewal and an AMR.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.3.3-9, the applicant stated that it expanded the in-scope portion of

the Dresden CRDH system to include sections of piping (1) from valve 3-0301-60 to and

including valve 3-0301-61 and (2) from valve 3-0301-53 to and including valve 3-0301-54 as

shown on License Renewal Boundary Diagram LR-DRE-M-365-1. This boundary expansion

added active instruments dPT3-302-61 and dPT3-302-88 and their associated vent and

equalizing valves. The additional piping/tubing and valves (passive components) the applicant

included in-scope are constructed of the same materials, are in the same environments, and

perform the same intended functions as components listed in LRA Table 2.3.3-3. Therefore,

LRA Table 2.3.3-3, which lists components groups of CRDH system requiring aging

management review, needed no change to encompass the expanded in-scope boundary.

Based on its review of the applicant's expanded in-scope boundary discussed above, the staff

finds the applicant's response to RAI 2.3.3.3-9 acceptable because it is in accordance with the

criteria set forth in 10 CFR 54.4 and 10 CFR 54.21(a)(1). Therefore, the staff considers the

concern described in RAI 2.3.3.3-9 resolved.

RAI 2.3.3.3-10. License renewal boundary diagram LR-DRE-M-34-1 for Dresden Unit 2 shows

that the license renewal boundary ends at valves 2-0301-67A and 2-0301-67B at locations C-5

and B-5 (stabilizing valves). The staff was not certain whether the license renewal boundary

should continue beyond these valves. As such, the staff was unable to verify the acceptability

of the applicant's system scoping and screening results. Therefore, the staff requested the

applicant to explain why (1) the piping section beyond these valves, and (2) the corresponding

piping sections of Dresden Unit 3 (license renewal boundary diagram LR-DRE-M-365-1)

beyond valves 3-0301-67A and 3-0301-67B, were excluded from the scope of license renewal.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.3.3-1 0, the applicant stated that it expanded the in-scope portion of

the Dresden CRDH system as shown on License Renewal Boundary Diagrams LR-DRE-M-34-1

and LR-DRE-M-365-1 to include all downstream pipe lines that would be isolated by closing

valves 2(3)-0301-67A and 2(3)-0301-67B. The applicant made this change in its responses to

RAI 2.1-02 and to Supplement RAI 2.1-02b. The expanded boundary includes all of the piping,

fittings, valves, and piping components downstream of valves 2(3)-0301-67A and

2(3)-0301-67B, up to and including points of termination at blank flanges, at normally closed

vent or drain valves, at instrumentation, or at points of interface with portions of the piping

system already designated as in-scope for license renewal. The additional piping, fittings,

valves, and piping components the applicant included in-scope are constructed of the same

materials, are in the same environments, and perform the same intended functions as

components listed in LRA Table 2.3.3-3. Therefore, LRA Table 2.3.3-3, which lists components

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groups of CRDH system requiring aging management review, needed no change to encompass

the expanded in-scope boundary.

Based on its review of the applicant's expanded in-scope boundary discussed above, the staff

finds the applicant's response to RAI 2.3.3.3-10 acceptable because it is in accordance with the

* criteria set forth in 10 CFR 54.4 and 10 CFR 54.21 (a)(1 ); Therefore, the staff considers the

concern described in RAI 2.3.3.3-10 resolved.

2.3.3.3.3- Conclusions

The staff reviewed LRA Section 2.3.3.3, the accompanying scoping boundary drawings, and the

applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. In addition, the staff performed an

independent assessment to determine whether any components that should be subject to an

AMR were not identified by the applicant. The staff did not identify any omissions. On the

basis of its review, the staff concludes that the applicant has adequately identified the

components of the CRDH system that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant has adequately identified the components of the CRDH

system that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.4 Reactor Water Cleanup System

2.3.3.4.1 Summary of Technical Information in the Application

The applicant described the reactor water cleanup (RWCU) system in LRA Section 2.3.3.4 and

provided a list of components subject to an AMR in LRA Table 2.3.3-4.

The RWCU system has the functions to remove insoluble, waterborne activation products from

reactor coolant; prevent soluble inorganic impurities (i.e., chlorides) from concentrating in the

reactor coolant and exceeding specified water quality limits; reduce beta and gamma radiation

sources in the reactor coolant resulting from the presence of corrosion and fission products;

and remove water from the reactor coolant system at reduced activity levels during startup and

shutdown.

Using the methodology described in LRA Section 2.1.4.1 for identifying the mechanical

components within the scope of license renewal, the applicant identified the following RWCU

system intended functions:

* pressure boundary-maintains the integrity of the reactor coolant pressure boundary

* primary containment isolation-provides containment isolation for those portions of the

system that interface with the primary containment

* supports ESF function(s)-supports the ESF function of the standby liquid control system

by shutdown of RWCU pumps and closure of RWCU valves to prevent dilution or removal

of the injected boron

* credited in regulated event(s)-credited in evaluation of the Appendix R fire and in the

ATWS events (The system also contains components relied upon for compliance with 10

CFR 50.49 (EQ))

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* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected

The RWCU system consists of pumps, regenerative and nonregenerative heat exchangers,

demineralizers, filters (Quad Cities only), containment isolation valves, and associated piping,

valves, and instrumentation and controls. The system provides continuous purification of a

portion of the reactor coolant recirculation flow with a minimum of heat loss and water loss from

the cycle. It can be operated during startup, shutdown, refueling operations, and during normal

operation. The system takes suction from the reactor recirculation system at the shutdown

cooling system connection at Dresden and the reactor recirculation pump suction connection at

Quad Cities, and the reactor vessel bottom drain connection. From these two suction sources,

reactor water impurities are removed by directing the flow through the system's major

components, piping, and supporting components, and then back to the reactor vessel via the

feedwater system at Dresden and via the RCIC system at Quad Cities. The regenerative heat

exchangers transfer heat from the water leaving the reactor to the water returning to the

reactor. The nonregenerative heat exchangers are cooled by water from the reactor building

close cooling water system.

Containment isolation capability is provided by four motor-operated containment isolation

valves. The RWCU system maintains the integrity of the reactor coolant pressure boundary

and the RWCU system can be isolated from the reactor coolant system by closure of the

containment isolation valves.

During refueling at Quad Cities, the RWCU system, in conjunction with the fuel pool filter

demineralizers, maintains fuel pool water clarity and reduced activity levels.

In LRA Section 2.3.3.4, the applicant described the evaluation boundary of the RWCU system.

In addition, the applicant highlighted those portions of the RWCU system and its structures and

components that are within the scope of the Rule in the P&l drawings listed as references in

LRA Section 2.3.3.4. Also, based on the methodology described in LRA Section 2.1.5 for

identifying the mechanical components subject to an AMR, the applicant identified the following

component groups and their intended functions within the RWCU system in LRA Table 2.3.3-4

as being within the scope of license renewal and subject to an AMR:

* closure bolting (pressure boundary)

* NSR vents or drains, piping, and valves (structural integrity/attached support)

* piping and fittings (pressure boundary)

* piping and fittings (structural integrity/attached support)

* piping and fittings (spatial interaction, Quad Cities only)

* small bore piping and fittings (pressure boundary)

* sight glasses (structural integrity/attached support, Dresden Only)

* valves (pressure boundary)

* valves (structural integrity/attached support)

* valves (spatial interaction, Quad Cities only)

Resulting from the revised methodology described in the May 18, 2004 response to the draft

SER Open Item 2.1-1 and clarified in a letter, dated June 22, 2004, the applicant expanded the

system boundaries for the RWCU system at Dresden Station due to the potential for spatial

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interaction with safety-related components. Specifically, the applicant added associated piping

components lines 2-3324-1"-H, 2/3-1223-8-LX, and 2-3318-1-L of the RWCU system shown on

revised boundary diagram LR-DRE-M-30 and lines 2/3-1223-8"-H, 3-5503-4"-H, and

2-5508-4"-H of the RWCU system shown on new boundary diagram LR-DRE-M-45-1 to the

scope of license renewal. This boundary expansion includes more of the same type of

components already represented on Table 2.3.3-4 of the LRA. As such, no changes to Table

2.3.3-4 were required.

2.3.3.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.4, Dresden UFSAR Section 5.4.8 and Quad Cities

UFSAR Section 5.4.8. Additionally, the staff reviewed other UFSAR sections that discussed the

RWCU system to determine whether there is reasonable assurance that the RWCU system

components within the scope of license renewal and subject to an AMR have been identified in

accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). At Dresden these sections included

3.2.9, 3.6.1, 3.6.2, 3.11.1,5.0, 5.1, 5.2.3,7.1.3, 7.3.2, 7.5.2, 9.1.4, 9.2.6, 9.3.2, 9.3.5, 11.5.2.6,

12.2,12.3.2,123A.3,14.2.4,15.6.4, and 15.8.6. At Quad Cities these sections included 3.6.1,

3.11.1, 5.1.3, 5.2.3, 5.4.3, 5.4.7, 5.4.8, 7.1.3, 7.3.1, 9.1.3, 9.2.3, 9.2.6, 9.3.1, 9.3.2, 9.3.5,

10.4.6,11.2.2,11.5.2,12.2, and 12.3.2. The staff's review was conducted in accordance with

Section 2.3 of the SRP-LR.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the RWCU system in the LRA. The staff did not identify any

omissions.

Also, the staff selected system functions described in the UFSARs that were set forth in

10 CFR 54.4 to verify that components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the RWCU system that are within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the system

drawings and system descriptions in the UFSARs to ensure that the referenced P&l drawings

were representative of the RWCU system. The staff then reviewed the referenced P&l

drawings to verify that those portions of the RWCU system that meet the scoping requirements

of 10 CFR 54.4 are included within the scope of license renewal and are identified as such by

the applicant in LRA Section 2.3.3.4 and that the applicant identified all RWCU system

components within the scope of license renewal and subject to an AMR in accordance with 10

CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff found that those portions of the RWCU system that meet the scoping requirements of

10 CFR 54.4 are included within the scope of license renewal and are identified as such by the

applicant in LRA Section 2.3.3.4 and that the RWCU system components that are subject to an

AMR in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1) are included in LRA Table 2.3.3-

4. The staff did not identify any omissions.

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2.3.3.4.3 Conclusions

The staff reviewed LRA Section 2.3.3.4 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. The

staff did not identify any omissions. On the basis of its review, the staff concludes that the

applicant has adequately identified the components of the RWCU system that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the RWCU system that are subject to an AMR, as required by 10

CFR 54.21(a)(1).

2.3.3.5 Fire Protection System

2.3.3.5.1 Summary of Technical Information in the Application

The applicant described the fire protection (FP) systems in LRA Section 2.3.3.5 and provided a

list of component groups subject to an AMR in LRA Table 2.3.3.5.

The FP systems provide the means for detecting, alarming, isolating, and suppressing fires at

Dresden Units 2 and 3 and Quad Cities Units 1 and 2. These systems include the following

subsystems and attributes:

* The fire detection and alarm system, referred to as the fire computer system, is an

instrumentation system that alerts control room operators of a fire and indicates its location.

* The fire suppression system includes fire-fighting equipment such as automatic sprinklers,

Halon 1301 systems, carbon dioxide (CO2) systems, standpipe hose stations, and outside

fire hydrants.

* Fire-rated assemblies are features of plant design and construction (e.g., fire barriers)

which contribute to the separation of fire hazards into zones and fire areas and are

addressed as part of the structure. Fire doors, fire dampers, and penetration seals provide

the necessary closures associated with openings in the fire rated barriers.

The FP systems are relied upon to meet the requirements of 10 CFR 50.48, "Fire Protection

Rule," and Appendix R to 10 CFR Part 50, "Fire Protection Program for Nuclear Power Facilities

Operating Prior to January 1, 1979." The plants are divided into unique fire areas as required

by Appendix A of Branch Technical Position (BTP) Auxiliary and Power Conversion System

Branch (APCSB) 9.5-1, "FP for Nuclear Power Plants." The SSCs satisfying the safe-shutdown

requirements of Appendix R are contained in the safe-shutdown equipment list (SSEL) and

captured by the review conducted for 10 CFR 54.4(a)(1) and 10 CFR 54.4(a)(2). The applicant

provided technical position papers which summarize the results of the review performed on the

fire protection program (FPP) documents and summarize the systems and structures necessary

to demonstrate compliance with 10 CFR 50.48.

2.3.3.5.2 Staff Evaluation

The staff reviewed LRA Sections 2.1.3.5 and 2.3.3.5, UFSAR Section 9.5.1, and FP technical

position papers to determine whether there is reasonable assurance that the FP system

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components within the scope of license renewal and subject to an AMR have been identified in

accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1), respectively.

In the performance of the review, the staff selected system functions described in the UFSAR

that were required by 10 CFR 54.4 to verify that components having intended functions were

not omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

The staff also reviewed SERs referenced for the FP program which summarize the FPP and

commitments made to meet 10 CFR 50.48 using the guidelines of Appendix A to BTP APCSB

9.5-1 and Appendix R. The staff sampled portions of these SERs to verify that the functions of

the FP components relied upon to satisfy the provisions of Appendix A to BTP APCSB 9.5-1

and Appendix R were included within the scope of license renewal as intended functions in the

LRA.

After the staff's initial review of the LRA, the staff identified several concerns regarding the

scoping and screening of FP SSCs required for compliance with 10 CFR 50.48. Section 2.1.3.5

of the LRA states that technical position papers were developed for FP which summarize the

results of a detailed review of the FPP documents demonstrating compliance with

10 CFR 50.48 and 10 CFR 50 Appendix R, Sections Ill.G, 111.J, Ill. L, and lIl.O. It is unclear that

these position papers also included the licensing commitments contained in the applicant's

response to Appendix A to the BTP APCSB 9.5-1 and the SERs resulting from the review of

those responses. In a letter dated August 4, 2003, the staff requested that the applicant clarify

that plant commitments contained in FP SERs, and other plant documentation which may also

reflect the plant FP CLB, were included in the development of the technical position papers to

ensure that all FP SSCs relied upon for compliance with 10 CFR 50.48 were included within the

scope of license renewal (RAI 2.3.3.5-1a). In a letter dated October 3, 2003, the applicant

responded that the Dresden and Quad Cities FP position papers identify those SSCs relied

upon to demonstrate compliance with 10 CFR 50.48. These include SSCs credited with

satisfying the commitments contained in the responses to Appendix A to BTP APCSB 9.5-1,

and the SERs resulting from the review of those responses, and SSCs credited with satisfying

any FP SERs issued before BTP APCSB 9.5-1 was published. The staff reviewed the

applicant's response and agreed that the applicant included these bases in the scoping

process.

LRA Section 2.3.3.5 lists "detects fires" as a system purpose and references the fire computer

system, which includes initiation devices. This fire detection/alarm computer system is not

referenced elsewhere in the LRA, for example, as part of the scoping and screening of the

electrical and instrumentation systems. By letter dated August 4, 2003, the staff requested that

the applicant clarify where the fire detection and alarm systems and components are addressed

in the LRA (RAI 2.3.3.5-1 b). In a letter dated October 3, 2003, the applicant responded that

although the fire computer system, including smoke detectors, heat sensors, pressure/flow

sensors, and actuation devises for preaction systems, is within the scope of license renewal, all

of the components in the system were categorized as "active" based on the determinations

documented in NEI 95-10, Appendix B, and are not subject to an AMR. Therefore, they are not

discussed in LRA Section 2.5, "Scoping and Screening Results: Electrical and Instrumentation

and Control Systems." The staff reviewed the applicant's response and agreed that the

components are categorized as active.

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The staff reviewed the LRA boundary drawings included with the LRA to assess what portions

of the FP system were in scope. In a letter dated August 4, 2003, the staff asked the applicant

to clarify information contained in the LRA boundary drawings for Dresden (RAI 2.3.3.5-1c

through f). In the response dated October 3, 2003, the applicant provided the following

clarifications.

LR-DRE-M-23-1: LRA boundary drawing LR-DRE-M-23-1 should have highlighted valves PIV 1-4199-

187, PIV 1-4199-188, PIV 1-4199-189, PIV 1-4199-190, PIV 1-4199-194, fire hydrants FH-30, FH-31

at drawing coordinates C-1 0 and the piping segments associated with these valves and hydrants. The

piping segment up to and including these valves and hydrants are included in the scope of license

renewal. The FP piping, and components down stream of these valves are not included as part of the

plant FP plan and do not perform functions that demonstrate compliance with 10 CFR 50.48. Fire

hydrants FH-8, FH-9 and FH-10 at drawing coordinate A-4 on LRA boundary drawing LR-DRE-M-23-1

and fire hydrant FH-33 at drawing coordinate E-7 on LRA boundary drawing LR-DRE-M-23-1 are within

the scope of license renewal. LRA boundary drawing LR-DRE-M-23-1 should have included those

components within the scope of license renewal.

LR-DRE-M-23-4: The portions of Unit 1 FP piping shown on LRA boundary drawing LR-DRE-M-23-4

that perform functions necessary to demonstrate compliance with 10 CFR 50.48 are the fire hose

stations F21 (drawing coordinate C-8), F22 (drawing coordinate C-5), F23 (drawing coordinate C-6),

F27 (drawing coordinate A-5), F29 (drawing coordinate C-8), and F47 (drawing coordinate C-2), the

West Aux Bay North and South sprinkler systems, and the piping connected to Unit 2 and 3 FP piping

up to and including the isolation values that connect to the Unit 1 piping. The Unit 1 fire hose stations

are in scope because they are included as part of the Dresden Unit 2 and 3 FP plan. The West Aux

Bay North system and South sprinkler system are in scope because of the cable concentrations in the

Unit 1 West Auxiliary Bay, located below the Unit 2 control room. All remaining piping, valves, fire hose

station, service water drops, and sprinkler systems pertaining to Unit 1 are not included as part of the

Dresden Unit 2 and 3 FP plan and do not perform functions that demonstrate compliance with 10 CFR

50.48.

LRA boundary drawing LR-DRE-M-23-4 contains some boundary interfaces that do not end at an

isolation valve. At location A-8, the piping down stream of valve 1-4199-134 up to and including valve

1-4199-264 should not have been highlighted and does not belong within the scope of license renewal.

A small portion of piping down stream of valves 1-4199-314 (drawing coordinate E-6), 1-4199-315

(drawing coordinate E-6) and 1-4199-131 (drawing coordinate D-8) should not have been highlighted. These portions of pipe do not belong within the scope of license renewal. LRA boundary drawing LRDRE-M23-4 should have excluded these components from the scope of license renewal.

LR-DRE-M-23-5: Those portions of Unit 1 FP piping shown on LRA boundary drawing LR-DRE-M-23-5

that perform functions necessary to demonstrate compliance with 10 CFR 50.48 are fire hose stations

F11 (drawing coordinate F-3) and F37 (drawing coordinate B-10), the Unit 1 emergency diesel driven

fire pump (drawing coordinate D-2) and sprinkler system (drawing coordinate F-5), and the piping

connected to the Unit 2 and 3 FP piping up to and including the isolation values that connect to the Unit

1 piping. Fire hose stations F11 and F37 are in scope because they are included as part of the

Dresden Unit 2 and 3 FP plan. The emergency diesel driven fire pump and sprinkler system are in

scope to facilitate protection of the Unit 1 emergency diesel driven fire pump.

All remaining piping, valves, fire hose stations, service water drops, and sprinkler systems pertaining

to Unit 1 are not included in the Dresden Unit 2 and 3 FP plan and do not perform functions necessary

to demonstrate compliance with 10 CFR 50.48. Those FP components falling within the scope of

license renewal can be isolated from those sections outside the scope of license renewal by manually

closing isolation valves that are within the scope of license renewal. Degradation of any pressure retaining components located in the out-of-scope portions of the FP system would be identified through

a drop in fire header pressure and isolated.

A review of LRA boundary drawing LR-DRE-M-23-5 identified a boundary interface at drawing

coordinate A-9 that does not at end at an isolation valve. A field walk down determined that this pipe has been cut and capped. Valve 1-4199-502-DV at drawing coordinate F-6 should have been

highlighted, is within the scope of license renewal and was evaluated for aging management.

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LR-DRE-M-4204: The fire sprinkler systems shown in the ISCO makeup pump building rooms A&B on

LRA boundary drawing LR-DRE-M-4204 are within the scope of license renewal and subject to an

AMR. LRA boundary drawing LR-DRE-M-4204 should have included these components within the

scope of license renewal. This sprinkler system was evaluated for aging along with the other sprinkler

systems shown on the boundary diagram.

The staff reviewed the response provided by the applicant and concurs with the changes to the

LRA boundary drawings proposed by the applicant on the basis that these portions of the FP

system are in the scope of license renewal.

In a letter dated August 4, 2003, the staff asked the applicant to clarify information contained in

LRA drawing LR-QDC-M-27-1 for Quad Cities (RAI 2.3.3.5-1 g). By letter dated October 3,

2003, the applicant supplied the following clarifications. The fire hydrants on LRA boundary

drawing LR-QDC-M-27-1 at drawing coordinates D-1, D-2, and E-4 are within the scope of

license renewal and are subject to an AMR. These fire hydrants should have been highlighted.

The fire hydrants at drawing coordinates F-7, G-6, and G-7 are located downstream of isolation

valve 1/2-4199-278 (drawing location F-6), are not included as part of the plant FP plan,-and do

not perform functions that demonstrate compliance with 10 CFR 50.48. For these reasons,

they were not included within the scope of license renewal. The fire hydrants at drawing

coordinates G-2 and G-3 are incorrectly shown as being located upstream of isolation valve

1/2-4199-288. A field walkdown verified that these hydrants are located downstream of

isolation valve 1/2-4199-288 (drawing coordinate G-4). These hydrants are not included as part

of the plant FP plan and do not perform functions that demonstrate compliance with 10 CFR

50.48.

The staff reviewed the response provided by the applicant and concurs with the clarifications on

the basis of those portions of the FP system that are included in the plant FP plan. The staff

also agrees that the portions of the FP water system located downstream of isolation valve

1/2-4-199-228 are not in the scope of license renewal, since they are not part of the licensing

basis.

Section 5.4.6.3 of the Dresden UFSAR states that the Unit 2 and 3 diesel-driven fire pump, or

the Unit 1 diesel-driven fire pump, automatically provide a backup supply of river water to the

FP system on low system pressure. LRA Sections 2.3.3.5 and 2.3.3.13 state that the fire pump

diesels for Dresden are evaluated with the FP system. While the fire pump diesels are

considered active components, and therefore may be excluded from the scope'of license

renewal, supporting components and subsystems of the fire pump diesels should appear in

Table 2.3.3.5 of the LRA. In a letter dated August 4, 2003, the staff requested that the

applicant identify the portions of the diesel fire pump that were intended to be included within

the scope of license renewal and clarify how they may be included in LRA Table 2.3.3.5 (RAI

2.3.3.5-1i). In a letter dated October 3, 2003, the applicant submitted the table below to identify

those portions of the diesel fire pump addressed by LRA Table 2.3.3-5.

Long-lived, passive components for the fire pump diesels and diesel fire pump subsystem are

included in LRA Table 2.3.3-5.

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Equipment Description LRA Table 2.3.3-5 Component Group

diesel fire pump suction screens filters/strainers

strainer diesel fire pump deluge system filters/strainers

fire pump diesel cooling water strainer filters/strainers

diesel fire pump room supply air damper fire dampers

fire pump diesel silencer mufflers

diesel fire pump headers piping and fittings

sprinkler system fire pump diesel day tank piping and fittings

fire diesel sprinkler piping and fittings

diesel fire pump pumps

sprinkler system fire pump diesel day tank sprinklers

fire pump diesel oil day tank tanks

diesel fire pump deluge system valves valves

diesel fire pump cross-tie valves valves

fire pump diesel cooling water valves valves

diesel fire pump discharge valves valves

fire pump diesel engine lubrication oil valves valves

diesel fire pump supply valves valves

fire pump diesel day tank valves valves

fire pump diesel instrumentation valves valves I

The staff finds the applicant's response acceptable on the basis that the components of the

diesel fire pump identified are within the scope of the license renewal and subject to an AMR.

Since no LRA boundary drawings were provided for the Halon 1301 fire suppression systems,

the staff requested in a letter dated August 4, 2003, that the applicant clarify which systems and

components are within scope and are covered in the AMR (RAI 2.3.3.5-1j). In a letter dated

October 3, 2003, the applicant stated that a P&ID for the Halon 1301 system at Dresden does

not exist. As such, an LRA boundary drawing was not created for that portion of the FP

system. There are three Halon subsystems at Dresden that are completely independent of one

another. These subsystems protect the record retention vault, the process computer room, and

the auxiliary electric equipment room/primary computer room. The Halon 1301 subsystems for

the record retention vault and the process computer room are not included within the scope of

license renewal because they are not included in the plant FP plan and do not perform

functions that demonstrate compliance with 10 CFR 50.48. However, the entire subsystem

supporting the auxiliary electric equipment room/primary computer room is within the scope of

license renewal. LRA Table 2.3.3-5 evaluates these components in component groups-piping

and fittings (including flex hoses, hose reels, hoses, nozzles, tubing, sprinklers, and gaskets of

buried components), aging management reference 3.3.1.5 and 3.3.2.138; and valves (including

nozzles), aging management reference 3.3.2.23 and 3.3.2.260.

The applicant further indicated that the Halon bottles/cylinders are considered consumable FP

equipment, are replaced based on condition, and, therefore, are not considered long-lived

components.

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At Quad Cities, Halon is only used in areas that do not house any safe shutdown equipment

(training building, records storage building, and new computer room). Therefore, the Halon

system at Quad Cities is not within the scope of license renewal because it is not included in the

plant FP plan and does not perform functions that demonstrate compliance with 10 CFR 50.48.

The staff finds the applicant's response acceptable on the basis that the applicant has included

the Halon system in the Dresden plant auxiliary electric equipment room/primary computer

room in the scope of license renewal as it is included in the Dresden FPP, and excluded the

Halon system at Quad Cities that does not perform an intended function.

The staff identified the use of water shields or baffles referenced in the Quad Cities response to

BTP APCSB 9.5-1 and requested that the applicant confirm that these components were

included within the scope of license renewal and subject to an AMR, or justify their exclusion

(RAI 2.3.3.5-1 k). The applicant responded in a letter dated October 3, 2003, that the water

shields referenced in Amendment 2 to the Quad Cities response to BTP APCSB 9.5-1 were

never installed. This configuration was clarified in the Quad Cities Fire Protection Report,

Volume 1, Section 4.3-3889, Revision 13, issued August 2001. Because these shields were

never installed, they are not included within the scope of license renewal.

The staff reviewed the applicant's response and concurs, on the basis that these shields were

never installed, that they are not included within the scope of license renewal and subject to an

AMR.

Portable equipment, such as fire extinguishers, self-contained breathing air packs, fire hoses,

and portable ductwork, are not included in the LRA. The staff believes that these components

should be within the scope of the license renewal, but exempt from an AMR, because portable

equipment is typically replaced on condition. These standards require the replacement of

portable equipment based on their condition or performance during testing and inspection.

These portable components are not long-lived and are maintained per the NFPA standards;

therefore an AMR is not required. In a letter dated August 4, 2003, the staff requested that the

applicant identify where in the LRA these components are identified as being within the scope

of license renewal, or provide a technical justification for their exclusion (RAI 2.3.3.5.1-I). In a

letter dated October 3, 2003, the applicant responded that portable FP equipment is included

within the scope of license renewal but is not discussed in the LRA. Section 2.1.5.4 of the LRA

should have been written as in the following section to be consistent with the NRC letter from

Mr. C. I. Grimes to Mr. D. J. Walters of NEI, dated March 10,2000, regarding License Renewal

Issue No. 98-12, "Consumables."

2.3.3.5.3 Consumable Fire Protection Equipment

Fire extinguishers, self-contained breathing air packs, fire hoses, and portable ductwork (smoke

ejectors) are within the scope of license renewal, but are not subject to aging management

because they are replaced on condition. These components are periodically inspected in

accordance with National Fire Protection Association (NFPA) standards. These standards

require replacement of equipment based on their condition or performance during testing and

inspection. These components are not long-lived and therefore, aging management is not

required.

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2.3.3.5.4 Conclusions

The staff reviewed LRA Section 2.3.3.5, the accompanying scoping boundary drawings, and the

applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. In addition, the staff performed an

independent assessment to determine whether any components that should be subject to an

AMR were not identified by the applicant. On the basis of its review, the staff concludes that

the applicant has adequately identified the components of the FP system that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the FP system that are subject to an AMR, as required by 10 CFR

54.21 (a)(1).

2.3.3.6 Emergency Diesel Generator and Auxiliaries

2.3.3.6.1 Summary of Technical Information in the Application

The applicant described the emergency diesel generator (EDG) and auxiliary systems in LRA

Section 2.3.3.6 and provided a list of components subject to an AMR in LRA Table 2.3.3-6.

The function of the EDG and auxiliary systems is to provide an emergency source of AC power

to the emergency core cooling system or safe shutdown equipment for each unit following a

design basis accident and/or in the event of loss of offsite power (LOOP). Using the

methodology described in LRA Section 2.1.4.1 for identifying the mechanical components within

the scope of license renewal, the applicant identified the following EDG and auxiliary systems

intended functions:

* provide emergency AC power-provides independent power source to assure safe reactor

shutdown under emergency conditions on a total loss of offsite power concurrent with a

design basis accident.

* credited in regulated event(s)-credited in support of fire protection (10 CFR 50.48) (The

system contains components that are relied upon for compliance with 10 CFR 50.49 (EQ)).

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected.

The EDG and auxiliary systems consist of three EDGs per site-one EDG per reactor and a

shared EDG. Each EDG, located in a separate diesel generator room, is an assembly

containing a diesel engine and a generator. Section 54.21 (a)(1) of Title 10 of the Code of

Federal Regulations recognizes that EDGs are active and excludes them from the group of

equipment subject to AMR. However, the auxiliary systems for each EDG are within the scope

of the Rule and subject to an AMR. These auxiliary systems include the following:

* EDG room ventilation system

* EDG jacket water system

* EDG air start system

* EDG lubrication system

* EDG combustion air intake and exhaust system

* EDG cooling water system

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* EDG fuel oil storage and transfer system

EDG Room Ventilation System

The staff's evaluation of the EDG room ventilation system is provided in Section 2.3.3.6A of this

SER.

EDG Jacket Water System

The EDG jacket water system provides cooling to the lube oil cooler and other diesel engine

subcomponents, and maintains the diesel engine at an acceptable starting temperature during

standby. The system is a closed loop system that starts with the EDG jacket water heat

exchangers, passes through the diesel engine and lube oil cooler, and returns to the heat

exchanger. It includes engine-driven pumps, an immersion heater, expansion tank, piping,

valves, and controls and instrumentation. Cooling water for the EDG jacket water heat

exchangers is provided by the EDG cooling water system.

EDG Air Start System

The EDG air start system stores and delivers sufficient air to start the diesel engine in the event

of a LOOP. Each EDG has an independent air starting system which primarily consists of a set

of two starting air compressors, four air receivers, two moisture separators, two air-driven

starting motors and piping, valves, and controls and instrumentation. The system starts with

the EDG starting air compressors, then passes through the air receivers, and moisture

separators, to the EDG start motors. Because the air receivers are designed to store and

provide sufficient air, as required to start the EDG, those portions of the system used for

charging the air receivers have no safety function and are noncritical quality elements.

Therefore, the air compressors and associated equipment are not included in the license

renewal scope.

EDG Lubrication System

The EDG lubrication system provides lubrication to the EDG and subcomponents, and

maintains the diesel engine at an acceptable starting temperature during standby. The system

includes five pumping circuits for each EDG. The lubrication system evaluation boundary for

each EDG starts from the engine sump, then passes through strainers, pumps, filters, and

coolers, to the supplied service for each of the five circuits. It includes piping, valves, and

controls and instrumentation. Also included is the oil pumping circuit for the governor drive

assembly.

EDG Combustion Air Intake and Exhaust System

The EDG combustion air intake and exhaust system provides filtered air for engine combustion

and removes exhaust gases to the outside. The system evaluation boundary starts from the air

intake hood, then passes through intake filters, the engine, the exhaust manifold, the exhaust

silencer, and the outlet screen.

EDG Cooling Water System

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The EDG cooling water system is described in LRA Section 2.3.3.12. The staff's evaluation of

the EDG cooling water system is provided in Section 2.3.3.12 of this SER.

EDG Fuel Oil Storage and Transfer System

The EDG fuel oil storage and transfer system is described in LRA Section 2.3.3.13. The staff's

evaluation of the fuel oil storage and transfer system is provided in Section 2.3.3.13 of this

SER.

In LRA Section 2.3.3.6, the applicant described the evaluation boundary of each EDG auxiliary

system. In addition, the applicant highlighted those portions of the EDG auxiliary systems and

its structures and components that are within the scope of the Rule in the P&l drawings listed

as references in LRA Section 2.3.3.6. Also, based on the methodology described in LRA

Section 2.1.5 for identifying the mechanical components subject to an AMR, the applicant

identified the following component groups and their intended functions within the EDG auxiliary

systems in LRA Table 2.3.3-6 as being within the scope of license renewal and subject to an

AMR:

* air accumulator vessels, including tanks (pressure boundary)

* closure bolting (pressure boundary)

* debris screens (filter, Quad Cities only)

* doors, closure bolts, and equip frames, including dampers, duct, and housings (pressure

boundary)

* duct fittings, hinges, and latches, including anchors, bolts, and fasteners (pressure

boundary)

* filters/strainers (pressure boundary)

* filters/strainers (filter)

* flex collars, doors, and damper seals (pressure boundary)

* flexible hoses (pressure boundary)

* heat exchangers, including coolers (pressure boundary)

* heat exchangers, including coolers (heat transfer)

* lubricators (pressure boundary)

* NSR vents or drains, piping, and valves (structural integrity/attached support, Quad Cities

only)

* piping and fittings, including dryers, heaters, and tubing (pressure boundary)

* piping and fittings (structural integrity/attached support)

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* pumps (includes governors)

* restricting orifices (pressure boundary)

* restricting orifices (throttle)

* sight glasses (pressure boundary)

* tanks (pressure boundary)

* thermowells (pressure boundary)

* tubes, including heat exchangers (heat transfer, Quad Cities only)

* tubing (pressure boundary)

* tubing (structural integrity/attached support, Quad Cities only)

* turbochargers (pressure boundary)

* valves (pressure boundary)

* valves (structural integrity/attached support, Quad Cities only)

2.3.3.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.6, Dresden UFSAR Sections 8.3.1, 9.4.7, 9.5.4, 9.5.5,

9.5.6, 9.5.7, and 9.5.8, and Quad Cities UFSAR Sections 8.3.1, 9.4.5, 9.5.4, 9.5.5, 9.5.6, 9.5.7,

and 9.5.8 to determine whether there is reasonable assurance that the EDG auxiliary system

components within the scope of license renewal and subject to an AMR have been identified in

accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's review was conducted in

accordance with the Section 2.3 of the SRP-LR.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the EDG auxiliary systems in the LRA. The staff did not identify any

omissions.

Also, the staff selected system functions described in the UFSARs that were set forth in

10 CFR 54.4 to verify that components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the EDG auxiliary systems that are

within the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1), the staff compared the referenced P&l drawings to the system drawings

and system descriptions in the UFSARs to ensure that the referenced P&l drawings were

representative of the EDG auxiliary systems. The staff then reviewed the referenced P&l

drawings to verify that those portions of the EDG auxiliary systems that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal and are identified

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as such by the applicant in LRA Section 2.3.3.6 and that the applicant identified all EDG

auxiliary systems components within the scope of license renewal and subject to an AMR in

accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff found that those portions of the EDG auxiliary systems that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal and are identified

as such by the applicant in LRA Section 2.3.3.6. The EDG auxiliary systems components that

are subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1) are included in

LRA Table 2.3.3-6. The staff did not identify any omissions.

2.3.3.6.3 Conclusions

The staff reviewed LRA Section 2.3.3.6 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. The

staff id not identify any omissions. On the basis of its review, the staff concludes that the

applicant has adequately identified the components of the EDG and auxiliary systems that are

within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has

adequately identified the components of the EDG and auxiliary systems that are subject to an

AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.6A Diesel Generator Room Ventilation

2.3.3.6A.1 Summary of Technical Information in the Application

The applicant described the EDG room ventilation system in LRA Section 2.3.3.6 and provided

a list of components subject to an AMR in LRA Table 2.3.3-6.

The design function of the EDG room ventilation system is to maintain a suitable environment

for equipment operation during normal and emergency operating modes when the EDG is

required. Based on 10 CFR 54.4, and using the methodology described in LRA Section 2.1.4.1

for identifying the mechanical components within the scope of license renewal, the applicant

identified the following EDG room ventilation system intended functions:

* credited in regulated event(s)-credited in support of fire protection (10 CFR 50.48) and

contains components that are relied upon for compliance with 10 CFR 50.49 (EQ).

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected.

Each EDG room has an independent ventilation system. Each ventilation system has a supply

fan which auto starts when the EDG starts. The fan draws in either outside air or turbine

building air through temperature-controlled modulation dampers, isolation dampers, and fire

dampers. The air exhausts the room through pneumatically operated dampers. Each

ventilation system is used only when its respective EDG is operating.

In LRA Section 2.3.3.6, the applicant described the evaluation boundary of the EDG room

ventilation system. In addition, the applicant highlighted those portions of the EDG room

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ventilation system and its structures and components that are within the scope of the Rule in

the P&l drawings listed as references in LRA Section 2.3.3.6. Also, based on the methodology

described in LRA Section 2.1.5 for identifying the mechanical components subject to an AMR,

the applicant identified and included the EDG room ventilation system component group subject

to an AMR in LRA Table 2.3.3.6, which lists all mechanical components of the EDG auxiliary

systems.

2.3.3.6A.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.6, Dresden UFSAR Section 9.4.7, and Quad Cities

UFSAR Section 9.4.5 to determine whether there is reasonable assurance that the system

components within the scope of license renewal and subject to an AMR have been identified in

accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff's review was conducted in

accordance with Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the EDG room ventilation system in the LRA. The staff did not

identify any omissions.

Also, the staff selected system functions described in the UFSARs that were required by

10 CFR 54.4 to verify that components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the EDG room ventilation system that

are within the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4

and 10 CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the

system drawings and system descriptions in the UFSARs to ensure that the referenced P&l

drawings were representative of the EDG room ventilation system. The staff then reviewed the

referenced P&l drawings to verify that those portions of the EDG room ventilation system that

meet the scoping requirements of 10 CFR 54.4 are included within the scope of license renewal

and are identified as such by the applicant in LRA Section 2.3.3.6 and that the applicant

identified all EDG room ventilation system components within the scope of license renewal and

subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff found that those portions of the EDG room ventilation system that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal and are identified

as such by the applicant in LRA Section 2.3.3.6 and that the EDG room ventilation system

components that are subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1) are included in LRA Table 2.3.3-6. The staff did not identify any omissions.

2.3.3.6A.3 Conclusions

The staff reviewed LRA Section 2.3.3.6 and the accompanying scoping boundary drawings to

determine whether any SSCs that should be within the scope of license renewal were not

identified by the applicant. In addition, the staff performed an independent assessment to

determine whether any components that should be subject to an AMR were not identified by the

applicant. The staff did not identify any omissions. On the basis of this review, the staff

concludes that the applicant has appropriately identified the components of the EDG room

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ventilation systems that are within the scope of license renewal, as required by 10 CFR 54.4(a),

and that the applicant has appropriately identified the components of the EDG room ventilation

systems that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.7 Main Control Room Heating, Ventilation, and Air Conditioning

2.3.3.7.1 Summary of Technical Information in the Application

The applicant described the main control room heating, ventilation, and air conditioning (CRVHVAC) system in LRA Section 2.3.3.7 and provided a list of components subject to an AMR in

LRA Table 2.3.3-7.

The CRV-HVAC system has the functions to-provide a suitable environment during normal

operation for the control room operators and equipment; provide a habitable environment after

a design basis accident in which the operators can safely shutdown and maintain the plant for

the duration of the accident; provide an environment from which the operators can safely

occupy and operate the plant during an onsite or offsite toxic chemical accident; provide

detection and protection for control room personnel from radioactive contamination or smoke

released to the atmosphere; provide detection and protection for control room personnel from

toxic gas (Quad Cities); provide fire protection to the operators with fire dampers for fires

outside the control room, and a smoke purge function mode for fires inside the control room;

and meet the seismic Category I requirements for all safety-related system components.

Using the methodology described in LRA Section 2.1.4.1 for identifying the mechanical

components within the scope of license renewal, the applicant identified the following CRVHVAC system intended functions:

* isolation and filtration-provides isolation and filtration for the control room during accident

conditions

* environmental control-provides habitable environment for the control room during normal,

abnormal, accident, and postaccident conditions

* credited in regulated event(s)-demonstrates compliance with NRC regulations regarding

station blackout (10 CFR 50.63) and fire protection (10 CFR 50.48)

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected

The CRV-HVAC system consists of the train-A HVAC system (a multizone unit), the train B

HVAC system (a single zone unit), the emergency air filtration unit (AFU), the toxic gas analyzer

system, and the smoke detection system. Each system train includes manual and air-operated

dampers, an air handling unit (AHU), and distribution air ducts to and from the control room

(including the cable spreading room and the auxiliary electric equipment room for Quad Cities)

and the train-B HVAC equipment room. The train-A HVAC system also included an exhaust fan

and the smoke detection system. The train-B HVAC system also included the AFU, associated

booster fans, a refrigeration condensing unit (RCU), the toxic gas analyzer system, and

associated valves, and instrumentation and controls. A sprinkler system is also provided to the

AFU from the fire protection system (evaluated with the fire protection system). The train-A

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AHU is the primary unit to provide the temperature control and air distribution for the control

room. The train-B AHU serves as a backup to the train-A AHU and provides the source of

cooling for the control room in the event the train-A AHU is lost. During normal operation,

outside air is mixed with return air to maintain the control room emergency zone at a positive

pressure. In the event of a design basis accident, the normal outside air intakes are isolated,

and the AFU provides filtered makeup air to maintain pressurization of the control room

emergency zone. In the event smoke is detected in the intake air ducts, the train-A HVAC

system outdoor air-intake is automatically isolated and the system air is recirculated. In the

event smoke is detected in the return air ducts, the train-A HVAC system is automatically

switched to the purge mode and the system is supplied with 100 percent outdoor air. The trainB RCU is normally cooled with SW (evaluated with the SW system). However, upon loss of

SW, the RCU may be cooled by containment cooling SW (evaluated with the containment

cooling SW system) at Dresden and by residual heat removal SW (evaluated with the residual

heat removal SW system) at Quad Cities. The toxic gas analyzer (at Quad Cities) continuously

monitors the outside air intake of the operating AHU, and automatically isolates outdoor air

intakes in the event specified toxic gas limits are approached. The toxic gas analyzer at

Dresden has been determined to not be needed, and has been abandoned in place. If

required, the outdoor air intakes can still be manually isolated.

In LRA Section 2.3.3.7, the applicant described the CRV-HVAC system evaluation boundary.

In addition, the applicant highlighted those portions of the CRV-HVAC system and its structures

and components that are within the scope of the Rule in the P&l drawings listed as references

in LRA Section 2.3.3.7. Also, based on the methodology described in LRA Section 2.1.5 for

identifying the mechanical components subject to an AMR, the applicant identified the following

component groups and their intended functions within the CRV-HVAC system in LRA Table

2.3.3-7 as being within the scope of license renewal and subject to an AMR:

* air handlers heating/cooling (CRV-HVAC) (pressure boundary)

* air handlers heating/cooling (CRV-HVAC) (heat transfer)

* dampeners (pressure boundary, Quad Cities only)

* debris screens (filter)

* diffusers (pressure boundary)

* doors, closure bolts, and equip frames, including dampers, duct, housings, and silencers

(pressure boundary)

* duct fittings, hinges, and latches (pressure boundary)

* filters/strainers (pressure boundary)

* filters/strainers (filter)

* flex collars, doors, and damper seals, including duct (pressure boundary)

* flow elements (throttle, Dresden only)

* heat exchangers (pressure boundary)

* heat exchangers (heat transfer)

* housings and supports (pressure boundary)

* NSR vents or drains, piping, and valves (structural integrity/attached support, Dresden only)

* piping and fittings (pressure boundary)

* piping and fittings (structural integrity/attached support, Quad Cities only)

* seals (pressure boundary)

* sight glasses (pressure boundary)

* tubing (pressure boundary, Dresden only)

* valves including dampers (pressure boundary)

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2.3.3.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.7, Dresden UFSAR Sections 6.4 and 9.4.1, and Quad

Cities UFSAR Sections 6.4 and 9.4.1 to determine whether there is reasonable assurance that

the CRV-HVAC system components within the scope of license renewal and subject to an AMR

have been identified in accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's

review was conducted in accordance with Section 2.3 of NUREG-1 800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the CRV-HVAC system in the LRA. The staff did not identify any

omissions.

Also, the staff selected system functions described in the UFSARs that were required by

10 CFR 54.4 to verify that components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the CRV-HVAC system that are within

the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21(a)(1), respectively, the staff compared the referenced P&l drawings to the

system drawings and system descriptions in the UFSARs to ensure that the referenced P&l

drawings were representative of the CRV-HVAC system. The staff then reviewed the

referenced P&l drawings to verify that those portions of the CRV-HVAC system that meet the

scoping requirements of 10 CFR 54.4 are included within the scope of license renewal and are

identified as such by the applicant in LRA Section 2.3.3.7 and that the applicant identified all

CRV-HVAC system components within the scope of license renewal and subject to an AMR in

accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.7 identified areas in which additional information is

necessary to complete the staff's review of the applicant's scoping and screening results.

Therefore, by the August 4, 2003, letter, the staff issued RAls to the applicant concerning the

specific items needed to determine whether the applicant has properly applied the scoping and

screening criteria of 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's RAls and the applicant's

responses by letter, dated October 3, 2003, are described below.

RAI 2.3.3.7-1. Ductwork in the main control room HVAC systems is identified on ventilation

system flow diagrams referenced in the LRA as within the scope of license renewal. Ductwork

performs the intended function of a pressure boundary. However, it is not included in the AMR

results in Table 2.3.3-7 of the LRA. Therefore, the staff requested the applicant to clarify

whether ductwork is subject to an AMR and provide the relevant information about this

component to enable the staff to complete its review of Table 2.3.3-7 in the LRA (Component

Groups Requiring AMR- HVAC). If ductwork is not subject to an AMR, provide justification for

its exclusion.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.7-1 states that the ductwork in the main control room

HVAC systems is included within the scope of license renewal and is subject to an AMR. The

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ductwork is included in LRA Table 2.3.3-7 and is evaluated under the component group "doors,

closure bolts, equip frames (including dampers, duct, housings and silencers)."

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.7-1 acceptable because it conforms with the criteria set forth

in 10 CFR 54.4 and 10 CFR 54.21(a)(1). Therefore, the staff considers its concern described in

RAI 2.3.3.7-1 resolved.

RAI 2.3.3.7-2. The Dresden and Quad Cities ventilation systems that support use of the safe

shutdown controls have not been included as part of the scoping and screening process. The

staff asked the applicant to state whether the ventilation systems used to support the safe

shutdown controls are within the scope of license renewal and subject to an AMR in accordance

with 10CFR54.4(a)(1) and (a)(2). If they are within scope, the applicant should provide the

relevant information about the components to enable the staff to complete its review of the

AMR result tables in the LRA. If the ventilation systems used to support the safe shutdown

controls are not in the scope of license renewal and subject to an AMR, provide justification for

their exclusion.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.7-2 states that safe shutdown of the Dresden and Quad

Cities plants from outside the control room is discussed in Dresden UFSAR Section 7.4.2 and

Quad Cities Section 7.4.2. Neither Dresden nor Quad Cities has a dedicated safe shutdown

control panel. Consequently, there is no ventilation system that specifically supports safe

shutdown controls. Each station has procedures for control room evacuation that provide

operator actions to be taken at various instrument and control panels located throughout the

plants. The ventilation systems that serve the areas where safe shutdown equipment is located

were included in the scoping and screening evaluation process. However, the Dresden and

Quad Cities current licensing bases do not require that a radiological accident be postulated

concurrent with a control room fire and they do not credit ventilation systems with maintaining

habitability for local operation of safe shutdown equipment during an event that requires the

control room to be evacuated.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.7-2 acceptable because it conforms with the criteria set forth

in 10 CFR 54.4 and 10 CFR 54.21 (a)(1). Therefore, the staff considers its concern described in

RAI 2.3.3.7-2 resolved.

2.3.3.7.3 Conclusions

The staff reviewed LRA Section 2.3.3.4, the accompanying scoping boundary drawings, and the

applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. In addition, the staff performed an

independent assessment to determine whether any components that should be subject to an

AMR were not identified by the applicant. The staff did not identify any omissions. On the

basis of this review, the staff concludes that the applicant has appropriately identified the

components of the CRV-HVAC system that are within the scope of license renewal, as required

by 10 CFR 54.4(a), and that the applicant has appropriately identified the components of the

CRV-HVAC system that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.3.8 HVAC-Reactor Building

2.3.3.8.1 Summary of Technical Information in the Application

The applicant described the reactor building HVAC (RBH-HVAC) system in LRA Section 2.3.3.8

and provided a list of components subject to an AMR in LRA Table 2.3.3-8.

The RBH-HVAC system has the functions to-provide conditioned air to the reactor building

and primary containment structures, and remove the heat remaining from the primary process

and operating equipment; minimize the level of airborne contaminants; make the plant

atmosphere adequate to support the presence of personnel; maintain the reactor building at a

negative pressure to minimize the release of radioactive contaminants to the environment;

maintain a differential pressure of at least 0.25 in. water between clean and potentially

contaminated areas; and remove exhaust air from the drywell and suppression chamber purge

system when the reactor is shutdown and/or whenever primary containment access is required.

Using the methodology described in LRA Section 2.1.4.1 for identifying the mechanical

components within the scope of license renewal, the applicant identified the following RBHHVAC system intended functions:

* support ESF function(s)-provides instrumentation to trip automatically on a secondary

containment isolation signal

* containment isolation-isolation dampers help ensure that adequate secondary containment

is maintained during and after an accident by minimizing potential paths to the environment

* credited in regulated event(s)-fire dampers provide isolation to prevent spread of a fire

credited in mitigation of the Appendix R fire

* flow path (Dresden only)-conducts effluent directly to the reactor building stack or the

standby gas treatment system

* pressure control (Dresden only)-maintains a negative pressure of at least 0.25 in. water

between the reactor building and the environment

* radioactivity control-(Dresden only) collects radioactivity released from a fuel handling

accident in the openings located on the periphery of the refueling pools, and provide timely

removal to the reactor building exhaust plenum providing sufficient level to isolate

secondary containment

The RBH-HVAC system operation provides general building ventilation. Using supply fans,

outside air is drawn into the RBH-HVAC system, and filtered, tempered, and discharged into the

supply system ducts. The supply air ducts distribute air throughout the building via air registers.

The system also uses two emergency isolation dampers in series in the main supply duct

upstream of all branch ducts. The exhaust fans draw building air into exhaust vents located

throughout the building and discharge it through the reactor building vent stack. The normal

ventilation exhaust duct for the spent fuel, reactor cavity, and dryer/separator pool area is

arranged to take suction through multiple inlets around the periphery of the pools above the

water line. Two emergency isolation dampers are installed in series in the main exhaust duct

upstream of the exhaust fan air intake and downstream of any branch connections to the

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exhaust duct. The reactor building ventilation system also removes exhaust air from the drywell

and suppression chamber purge system when the reactor is shut down for maintenance or

whenever primary containment access is required.

In LRA Section 2.3.3.8, the applicant described the RBH-HVAC system evaluation boundary. In

addition, the applicant highlighted those portions of the RBH-HVAC system and its structures

and components that are within the scope of the Rule in the P&I drawings listed as references

in LRA Section 2.3.3.8. Also, based on the methodology described in LRA Section 2.1.5 for

identifying the mechanical components subject to an AMR, the applicant identified the following

component groups and their intended functions within the RBH-HVAC system in LRA Table

2.3.3-8 as being within the scope of license renewal and subject to an AMR:

* debris screens (filter, Dresden only)

* doors, closure bolts, and equip frames including dampers, duct, housings, and silencers

(pressure boundary)

* duct fittings, hinges, and latches (pressure boundary)

* filters/strainers (pressure boundary, Dresden only)

* flex collars, doors and damper seals (pressure boundary, Dresden only)

* housing supports (pressure boundary, Dresden only)

* piping and fittings (pressure boundary, Dresden only)

* seals (pressure boundary, Dresden only)

* tubing (pressure boundary)

* valves, including dampers (pressure boundary, Dresden only)

2.3.3.8.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.8, Dresden UFSAR Sections 6.2.3, 9.4.2, 9.4.5, and

9.4.7, and Quad Cities UFSAR Sections 6.2.3, 9.4.2, 9.4.5, and 9.4.7 to determine whether

there is reasonable assurance that the RBH-HVAC system components within the scope of

license renewal and subject to an AMR have been identified in accordance with 10 CFR 54.4

and 10 CFR 54.21 (a)(1). The staff's review was conducted in accordance with Section 2.3 of

NUREG-1 800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the RBH-HVAC system in the LRA. The staff did not identify any

omissions.

Also, the staff selected system functions described in the UFSARs that were required by 10

CFR 54.4 to verify that components having intended functions were not omitted from the scope

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of the Rule. The staff also focused on components that were not identified as being subject to

an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the RBH-HVAC system that are within

the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21(a)(1), respectively, the staff compared the referenced P&l drawings to the

system drawings and system descriptions in the UFSARs to ensure that the referenced P&l

drawings were representative of the RBH-HVAC system. The staff then reviewed the

referenced P&l drawings to verify that: those portions of the RBH-HVAC system that meet the

scoping requirements of 10 CFR 54.4 are included within the scope of license renewal and are

identified as such by the applicant in LRA Section 2.3.3.8 and that the applicant identified all

RBH-HVAC system components within the scope of license renewal and subject to an AMR in

accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1).

The staff found that those portions of the RBH-HVAC system that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal and are identified

as such by the applicant in LRA Section 2.3.3.8 and that the RBH-HVAC system components

that are subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1) are

included in LRA Table 2.3.3-8. The staff did not identify any omissions.

2.3.3.8.3 Conclusions

The staff reviewed LRA Section 2.3.3.8 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. The

staff did not identify any omissions. On the basis of this review, the staff concludes that the

applicant has appropriately identified the components of the RBH-HVAC systems that are within

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has

appropriately identified the components of the RBH-HVAC systems that are subject to an AMR,

as required by 10 CFR 54.21 (a)(1).

2.3.3.9 Emergency Core Cooling System (ECCS) Comer Room HVAC

2.3.3.9.1 Summary of Technical Information in the Application

The applicant described the ECCS corner room (ECR-HVAC) system in LRA Section 2.3.3.9

and provided a list of components subject to an AMR in LRA Table 2.3.3-9.

The purpose of the ECR-HVAC system room coolers is to maintain the compartment

temperature below the qualification temperature of the components that are required for safe

shutdown of the plant. Using the methodology described in LRA Section 2.1.4.1 for identifying

the mechanical components within the scope of license renewal, the applicant identified the

following additional intended functions of the ECR-HVAC system:

* environmental control-provides ventilation to maintain an acceptable environment to

support proper ECCS pump operation during normal plant operating conditions and

following design basis events

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* credited in regulated event(s) (Dresden)-the system contains components that are relied

upon to demonstrate compliance with 10 CFR 50.49 (EQ)

* credited in regulated event(s) (Quad Cities)-provides ventilation and cooling credited in

mitigation of the Appendix R fire (The system also contains components that are relied upon

to demonstrate compliance with 10 CFR 50.49 (EQ))

Each of the ECCS corner rooms has an ECR-HVAC system which contains a water-cooled heat

exchanger and a fan unit. At Dresden, the ECR system includes the HPCI and LPCI room

coolers. The core spray pumps are located in the LPCI rooms. There are two LPCI room

coolers and one HPCI room cooler per unit. During normal plant operating conditions, the

cooling water for the room coolers is provided by the SW system. The CCSW system provides

backup cooling water to all three room coolers. At Quad Cities, the ECR-HVAC system

includes one HPCI, two core spray pumps, and two RHR room coolers per unit. The Quad

Cities Unit 1 and Unit 2 diesel generator cooling water pumps (evaluated with the diesel

generator service water system) provide cooling water to the room coolers in their respective

units. The SW system can also provide a non-safety-related alternate supply of cooling water

to the HPCI room emergency coolers.

In LRA Section 2.3.3.9, the applicant described the ECR-HVAC system evaluation boundary. In

addition, the applicant highlighted those portions of the ECR-HVAC system and its structures

and components that are within the scope of the Rule in the P&l drawings listed as references

in LRA Section 2.3.3.9. Also, based on the methodology described in LRA Section 2.1.5 for

identifying the mechanical components subject to an AMR, the applicant identified the following

component groups and their intended functions within the ECR-HVAC system in LRA

Table 2.3.3-9 as being within the scope of license renewal and subject to an AMR:

* air handlers heating/cooling (pressure boundary)

* air handlers heating/cooling (heat transfer)

* ducts, fittings, access doors, closure bolts, and equipment frames (pressure boundary)

2.3.3.9.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.9, Dresden UFSAR Sections 9.2.1, 9.2.2, and 9.4.6, and

Quad Cities UFSAR Sections 6.3.2, 9.2.2, and 9.5.5 to determine whether there is reasonable

assurance that the ECR system components within the scope of license renewal and subject to

an AMR have been identified in accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). The

staff's review was conducted in accordance with Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified as an intended function of the ECR-HVAC system in

the LRA. The staff did not identify any omissions.

Also, the staff selected system functions described in the UFSARs that were required by

10 CFR 54.4 to verify that components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the ECR-HVAC system that are within

the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

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10 CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the

system drawings and system descriptions in the UFSARs to ensure that the referenced P&I

drawings were representative of the ECR-HVAC system. The staff then reviewed the

referenced P&l drawings to verify that: those portions of the ECR-HVAC system that meet the

scoping requirements of 10 CFR 54.4 are included within the scope of license renewal and are

identified as such by the applicant in LRA Section 2.3.3.9 and that the applicant identified all

ECR-HVAC system components within the scope of license renewal and subject to an AMR in

accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.9 identified one area in which additional information is

necessary to complete the staff's review of the applicant's scoping and screening results.

Therefore, by the August 4, 2003, letter, the staff issued an RAI to the applicant concerning a

specific item needed to determine whether the applicant has properly applied the scoping and

screening criteria of 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's RAI and the applicant's

responses by letter, dated October 3, 2003, are described below.

RAI 2.3.3.9-1. The ECR-HVAC system Table 2.3.3-9 that identifies component groups

requiring AMR has not included the following in the scope of license renewal-flexible collars,

damper or door gaskets, seals, or other soft parts. These types of components were included

in the other HVAC systems. State whether these identified components are subject to an AMR

and provide the relevant information within Table 2.3.3-9 to enable the staff to complete the

license renewal review process. If these components are not subject to an AMR, provide

justification for their exclusion.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.9-1 states that the ECR-HVAC system consists of room

coolers that contain a cooling coil, a fan, and a housing. There is no ductwork attached to the

cooler. There are no flexible collars, damper or door gaskets, seals, or other soft parts

associated with the ECR-HVAC system.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.9-1 acceptable because it conforms with the criteria set forth

in 10 CFR 54.4 and 10 CFR 54.21(a)(1). Therefore, the staff considers its concern described in

RAI 2.3.3.9-1 resolved.

2.3.3.9.3 Conclusions

The staff reviewed LRA Section 2.3.3.9, the accompanying scoping boundary drawings, and the

applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. In addition, the staff performed an

independent assessment to determine whether any components that should be subject to an

AMR were not identified by the applicant. The staff did not identify any omissions. On the

basis of this review, the staff concludes that the applicant has appropriately identified the

components of the ECR-HVAC system that are within the scope of license renewal, as required

by 10 CFR 54.4(a), and that the applicant has appropriately identified the components of the

ECR-HVAC system that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.3.10 Station Blackout Building HVAC

2.3.3.10.1 Summary of Technical Information in the Application

The applicant described the station blackout building HVAC (SBO-HVAC) system in LRA

Section 2.3.3.10 and provided a list of components subject to an AMR in LRA Table 2.3.3-10.

The SBO-HVAC system has the functions to-maintain the SBO diesel generator and support

equipment ambient temperatures within an acceptable range for diesel readiness, provide

annunciation of temperature abnormalities, react to fire alarm actuation, and remove hydrogen

gas and diesel fumes from the building. Using the methodology described in LRA Section

2.1.4.1 for identifying the mechanical components within the scope of license renewal, the

applicant identified the following SBO-HVAC system intended functions:

* environmental control-supports the SBO diesel generators in providing AC power during a

loss of offsite power and station blackout by supplying the necessary HVAC to required

SBO diesel generators and auxiliaries

* credited in regulated event(s)-system functions to prevent the spread of a fire credited in

mitigation of the Appendix R fire (Quad Cities only)

Operation of the SBO-HVAC system provides heating and ventilation for the SBO diesel

generator rooms, the electrical equipment rooms, and the battery rooms. The ventilation

system for each diesel generator is capable of maintaining the design room conditions with the

diesel generators running at full load and maintaining design room conditions in winter with the

SBO diesel generators in the standby mode. The ventilation system for each electrical

equipment room is capable of maintaining the design room condition's with the diesel

generators running at full load. The heating systems for these rooms maintain room conditions

in winter. The ventilation systems for the battery rooms have an air-cooled condensing unit, an

air handling unit and an electric heater capable of maintaining the battery room at nominal

design conditions. The exhaust fans in the battery rooms and the day tank rooms are

* interlocked with the fire system to shut down on fire alarm actuation.

In LRA Section 2.3.3.10, the applicant described the SBO-HVAC system evaluation boundary.

In addition, the applicant highlighted those portions of the SBO-HVAC system and its structures

and components that are within the scope of the Rule in the P&l drawings listed as references

in LRA Section 2.3.3.10. Also, based on the methodology described in LRA Section 2.1.5 for

identifying the mechanical components subject to an AMR, the applicant identified the following

component groups and their intended functions within the SBO-HVAC system in LRA

Table 2.3.3-10 as being within the scope of license renewal and subject to an AMR:

* diesel generator building HVAC (DGB-HVAC) air handlers heating/cooling (pressure

boundary, Quad Cities)

* DGB HVAC air handlers heating/cooling (heat transfer, Quad Cities)

* debris screens (filter)

* doors, closure bolts, and equip frames (pressure boundary)

* duct fittings, hinges, and latches (pressure boundary)

* flex collars, doors and damper seals (pressure boundary)

* flow elements (pressure boundary, Dresden only)

* tubing (pressure boundary)

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2.3.3.10.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.10, Dresden UFSAR Section 9.5.9, and Quad Cities

UFSAR Section 8.3.1.9 to determine whether there is reasonable assurance that the SBOHVAC system components within the scope of license renewal and subject to an AMR have

been identified in accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's review

was conducted in accordance with Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the SBO-HVAC system in the LRA. The staff did not identify any

omissions.

Also, the staff selected system functions described in the UFSARs that were required by

10 CFR 54.4 to verify that components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the SBO-HVAC system that are within

the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the

system drawings and system descriptions in the UFSARs to ensure that the referenced P&l

drawings were representative of the SBO-HVAC system. The staff then reviewed the

referenced P&l drawings to verify that those portions of the SBO-HVAC system that meet the

scoping requirements of 10 CFR 54.4 are included within the scope of license renewal and are

identified as such by the applicant in LRA Section 2.3.3.10 and that the applicant identified all

SBO-HVAC system components within the scope of license renewal and subject to an AMR in

accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.10 identified areas in which additional information is

necessary to complete the staff's review of the applicant's scoping and screening results.

Therefore, by the August 4, 2003, letter, the staff issued RAls to the applicant concerning

specific items needed to determine whether the applicant has properly applied the scoping and

screening criteria of 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's RAls and the applicant's

responses by letter, dated October 3, 2003, are described below.

RAI 2.3.3.10-1. The standby blackout building ventilation fan housings are highlighted on the

ventilation flow diagrams identified in the LRA as within scope of license renewal. While

ventilation fan housings are highlighted as within the scope of license renewal, ventilation fan

housings are not identified in LRA Table 2.3.3-10 that identify component groups requiring

AMR. The applicant should state whether the standby blackout building ventilation fan

housings are within the scope of license renewal and subject to an AMR. If so, the applicant

should provide the relevant information about the components in order to provide the staff with

the ability to complete Table 2.3.3-10 of the LRA. If the standby blackout building ventilation

fan housings are not in scope or subject to an AMR, provide justification for their exclusion.

Applicant's Response and Staff's Evaluation

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The applicant's response to RAI 2.3.3.10-1 states that the SBO ventilation fan housings

highlighted on boundary diagrams LR-DRE-M-4356-1, -2, -3, -4, and -5, and LR-QDC-M-3033-1

and -2 for the SBO-HVAC system are within the scope of license renewal and subject to an

AMR. These ventilation fan housings were evaluated under the component group of "doors,

closure bolts, equip frames in LRA Table 2.3.3-1 0.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.10-1 acceptable because it conforms with the criteria set forth

in 10 CFR 54.4 and 10 CFR 54.21 (a)(1). Therefore, the staff considers its concern described in

RAI 2.3.3.10-1 resolved.

RAI 2.3.3.10-2. The Dresden and Quad Cities ventilation systems used to support fuel handling

have not been included as part of the scoping and screening process. The applicant should

state whether the ventilation systems used to support fuel handling are within the scope of

license renewal and subject to an AMR in accordance with 10 CFR 54.4(a)(1) and (a)(2). If so,

the applicant should provide the relevant information about the components to enable the staff

to complete its review of the application. If the ventilation systems used to support fuel handling

are not in the scope of license renewal and subject to an AMR, provide justification for their

exclusion.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.10-2 states that Dresden UFSAR Section 15.7.3.4.3.2,

Airborne Effects Over the Drywell Head Cavity, addresses airborne effects associated with

design basis fuel handling accidents and states the following:

If the noble gases are released within a couple of feet of the peripheral exhaust ducts, this activity

would be removed within a short period of time to the reactor building exhaust plenum header. The

radiation level in the exhaust duct would be sufficient to isolate secondary containment.

The Dresden UFSAR statement credits the radiation monitors in the reactor building ventilation

system for isolating the system and preventing further release of noble gas to the environment.

This requires the reactor building ventilation system to transport the noble gases released from

a fuel handling accident to the radiation monitors to isolate the system. The above statement

was the basis for inclusion of the entire reactor building ventilation system for Dresden in the

scope of license renewal. The Quad Cities UFSAR contains a similar fuel handling accident

scenario. However, the Quad Cities analysis does not credit the reactor building ventilation

radiation monitors for isolating the ventilation system. Rather, the analysis credits the radiation

monitors on the refueling floor for initiating the signal that isolates the reactor building

ventilation. UFSAR Section 15.7.2.5.3, Chimney Release Rate, addresses chimney release

rates associated with design basis fuel handling accidents and states the following:

The standby gas treatment system is actuated automatically on high area radiation in the reactor

building in order to control the release of fission products to the atmosphere. Monitors are located

near the fuel pool, and the SBGTS would be initiated prior to the escape of fission products through

the regular ventilation system.

The refueling floor radiation monitors are relied upon for actuation of the SBGTS (and

secondary containment isolation) for the Quad Cities fuel handling accident. Despite the fact

that radiation monitors are contained in the Quad Cities reactor building ventilation system

ductwork, no mention is made of these monitors in the UFSAR for this DBA. Consequently, a

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determination was made not to include system components other than the isolation dampers

(and selected fire dampers) in the scope of license renewal.

However, further consideration of the ventilation ducting leads to the conclusion that exhaust

dampers and fan configuration relative to the ventilation exhaust radiation monitors do provide a

basis for adding parts of the Quad Cities ventilation ducting within the scope of license renewal.

The function of the radiation monitors in the exhaust duct is to ensure that excessive radiation is

not released. This is done by isolating the secondary containment when the radiation level in

the building effluent is above the monitors' set point. Appropriate monitoring of all reactor

building effluent is ensured by (1) maintaining the building at a slightly negative pressure

relative to atmosphere, (2) monitoring the building ventilation effluent upstream of the exhaust

dampers, and (3) tripping the fans and closing the intake and exhaust dampers if the

permissible effluent radiation level is exceeded or if the negative pressure on the building is not

maintained. The ducting between the reactor building-to-turbine building interface and the

reactor building ventilation exhaust dampers must remain intact in order to ensure that all

reactor building effluent is properly monitored and that there is no potential exhaust path that

bypasses the radiation monitors. As such, this additional Quad Cities ventilation ductwork is

included within the scope of license renewal and will receive the same aging management as

the other ductwork included within the scope.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.10-2 acceptable because it conforms with the criteria set forth

in 10 CFR 54.4 and 10 CFR 54.21(a)(1). Therefore, the staff considers its concern described in

RAI 2.3.3.10-2 resolved.

2.3.3.10.3 Conclusions

The staff reviewed LRA Section 2.3.3.10, the accompanying scoping boundary drawings, and

the applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. In addition, the staff performed an

independent assessment to determine whether any components that should be subject to an

AMR were not identified by the applicant. The staff did not identify any omissions. On the

basis of this review, the staff concludes that the applicant has appropriately identified the

components of the SBO-HVAC systems that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and that the applicant has appropriately identified the components

of the SBO-HVAC system that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.11 Station Blackout System (Diesel and Auxiliaries)

2.3.3.11.1 Summary of Technical Information in the Application

The applicant described the station blackout (SBO) system in LRA Section 2.3.3.11 and

provided a list of components subject to an AMR in LRA Table 2.3.3-11.

The SBO system is a non-safety-related system which functions to provide an independent

source of additional on-site AC power as a backup to the EDGs. Using the methodology

described in LRA Section 2.1.4.1 for identifying the mechanical components within the scope of

license renewal, the applicant identified the following SBO system intended functions:

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* credited in regulated event(s)-4rovides an alternate source of AC electrical power to plant

equipment in the event of a station blackout (10 CFR 50.63)

* credited in regulated event(s)-provides an alternate power source credited in mitigation of

the Appendix R fire (Quad Cities only)

The system consists of two diesel generator (DG) sets. Each SB0 DG set is an assembly

consisting of two diesel engines and a generator arranged in tandem, and their associated

support systems. Each SBO DG set is located in a separate DG room. The support systems

included in the SBO system evaluation boundary are the SBO DG engine jacket water system,

SBO DG engine exhaust/combustion air system, S60 DG engine air start system, SBO DG

engine lube oil system, and SBO DG fuel oil system.

In LRA Section 2.3.3.11, the applicant described the evaluation boundary for the SB0 system.

In addition, the applicant highlighted those portions of the SBO system within the scope of the

Rule in the P&l drawings listed as references in LRA Section 2.3.3.11. Also, based on the

methodology described in LRA Section 2.1.5 for identifying the mechanical components subject

to an AMR, the applicant identified the following component groups and their intended functions

within the SBO system in LRA Table 2.3.3-11 as being within the scope of license renewal and

subject to an AMR:

* air accumulator vessels (pressure boundary)

* closure bolting (pressure boundary)

* filters/strainers (pressure boundary)

* filters/strainers, including separators (pressure boundary)

* flexible hoses (pressure boundary)

* flow elements (pressure boundary)

* heat exchangers, including coolers and heat exchangers (pressure boundary)

* heat exchangers, including coolers and heat exchangers (heat transfer)

* lubricators (pressure boundary)

* mufflers (pressure boundary)

* piping and fittings, including heaters, orifices, and thermowells (pressure boundary)

* piping and fittings, including restricting orifices (pressure boundary)

* pumps (pressure boundary)

* pumps (throttle, Dresden only)

* restricting orifices (pressure boundary)

* restricting orifices (throttle)

* sight glasses (pressure boundary)

* tanks (pressure boundary)

* thermowells (pressure boundary)

* tubing (pressure boundary)

* turbochargers (pressure boundary)

* valves (pressure boundary)

2.3.3.11.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.11, Dresden UFSAR Section 9.5.9, and Quad Cities

UFSAR Section 8.3.1.9 to determine whether there is reasonable assurance that the SBO

system components, within the scope of license renewal and subject to an AMR, have been

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identified in accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's review was

conducted in accordance with Section 2.3 of NUREG-1 800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the SBO system in the LRA. The staff did not identify any omissions.

Also, the staff selected system functions described in the UFSARs that were set forth in

10 CFR 54.4 to verify that components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the SBO system that are within the

scope of license renewal and subject to an AMR, in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the

system drawings and system descriptions in the UFSARs to ensure that the referenced P&l

drawings were representative of the SBO system. The staff then reviewed the referenced P&l

drawings to verify that those portions of the SBO system that meet the scoping requirements of

10 CFR 54.4 are included within the scope of license renewal and are identified as such by the

applicant in LRA Section 2.3.3.11 and that the applicant identified all SBO system components

within the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1).

The staff found that those portions of the SBO system that meet the scoping requirements of

10 CFR 54.4 are included within the scope of license renewal and are identified as such by the

applicant in LRA Section 2.3.3.11 and that the SBO system components that are subject to an

AMR in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1) are included in LRA Table 2.3.3-

11. The staff did not identify any omissions.

2.3.3.11.3 Conclusions

The staff reviewed LRA Section 2.3.3.11 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal were not identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. The

staff did not identify any omissions. On the basis of its review, the staff concludes that the

applicant has adequately identified the components of the SBO system that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the SBO system that are subject to an AMR, as required by 10

CFR 54.21 (a)(1).

2.3.3.12 Diesel Generator Cooling Water System

2.3.3.12.1 Summary of Technical Information in the Application

The applicant described the diesel generator cooling water (DGCW) system in LRA Section

2.3.3.12 and provided a list of components subject to an AMR in LRA Table 2.3.3-12.

The primary function of the DGCW system is to provide cooling water to the EDGs. In addition,

at Quad Cities, the DGCW system provides cooling water to the ECCS room coolers to ensure

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the proper environment for ECCS pump operation. Also, at Dresden, the DGCW system

provides an alternate water supply for the CCSW keep fill system.

Using the methodology described in LRA Section 2.1.4.1 for identifying the mechanical

components within the scope of license renewal, the applicant identified the following DGCW

system intended functions:

* supports emergency supply of AC power-provides cooling water to emergency diesel

generator heat exchangers and engine jacket cooling

* support ESF function(s) (Quad Cities only)-provides cooling water to ECCS room coolers

to ensure proper environment for ECCS pump operation

* provides structural support-non-safety-related portions of this system provide structural

support to attached safety-related piping

* credited in regulated event(s)-provides cooling water to safe shutdown equipment credited

in mitigation of the Appendix R fire

At Dresden, three motor driven submersible pumps take suction in the cribhouse and provide

cooling water to the DGCW heat exchangers. The DGCW return water is then routed back to

the SW discharge pipe. A cross-tie connection piping is provided between the DGCW systems

of Unit 2 and Unit 3. The DGCW pumps may also be used as the alternate safety-related water

supply to the CCSW keep fill system which is normally supplied by SW system.

At Quad Cities, the DGCW pumps take suction from the RHR SW inlet header. These pumps

provide cooling water to the EDG heat exchangers and to the room coolers of the HPCI room,

the RHR rooms, the CS rooms, and the diesel generator cooling water pump cubicle, and

ultimately discharge into the SW discharge pipe.

The applicant described the evaluation boundary for the DGCW system in LRA Section

2.3.3.12. In addition, the applicant highlighted those portions of the DGCW system within the

scope of the Rule in the P&l drawings listed as references in LRA Section 2.3.3.12. Also,

based on the methodology described in LRA Section 2.1.5 for identifying the mechanical

components subject to an AMR, the applicant initially identified the following component groups

and their intended functions within the DGCW system in LRA Table 2.3.3-12 as being within thescope of license renewal and subject to an AMR:

* DGB-HVAC air handlers heating/cooling, including DGCW pump cubicle coolers (pressure

boundary, Quad Cities only)

* DGB-HVAC air handlers heating/cooling, including DGCW pump cubicle coolers (heat

transfer, Quad Cities only)

* closure bolting (pressure boundary)

* doors, closure bolts, and equipment frames (pressure boundary, Quad Cities only)

* non-safety-related (NSR) vents or drains, piping, and valves (structural integrity/attached

support)

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* orifice bodies (pressure boundary)

* orifice bodies (throttle)

* orifice bodies (structural integrity/attached support, Quad Cities)

* piping and fittings, including flow elements (pressure boundary)

* piping and fittings (structural integrity/attached support)

* pulsation dampeners (structural integrity/attached support, Quad Cities)

* pumps (pressure boundary)

* strainer bodies (pressure boundary, Dresden only)

* strainer screens (filter, Dresden only)

* thermowells (pressure boundary)

* tubing (pressure boundary)

* valves (pressure boundary)

* valves (structural integrity/attached support)

Resulting from the revised methodology described in the May 18, 2004 response to the draft

SER Open Item 2.1-1, the boundaries of non-safety-related sections of the DGCW system at

Quad Cities were expanded and highlighted as shown on the revised boundary diagrams and

an additional new boundary diagram. Additional piping and components, including a gland seal

water tank, piping, valves, and associated instrumentation, from the DGCW system at Quad

Cities were added to the scope of license renewal. The applicant stated that the DGCW

system did not require a boundary expansion at Dresden because of a different diesel cooling

water pump design that does not require gland seal water.

The applicant identified the following additional component groups and their intended functions

within the DGCW system as being within the scope of license renewal, and added them to LRA

Table 2.3.3-12 being subject to an AMR:

* tanks (spatial interaction, Quad Cities only)

* valves (spatial interaction)

* piping and fittings (spatial interaction)

2.3.3.12.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.12, Dresden UFSAR Sections 7.4.2 and 9.5.5, and Quad

Cities UFSAR Sections 3.4.1.2, 6.3.2, and 9.5.5 to determine whether there is reasonable

assurance that the DGCW system components within the scope of license renewal and subject

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to an AMR have been identif ied in accordance'with 10 CFR 54.4 and 10 CFR 54.21(a)(1). The

staff's review was conducted in accordance with Section 2.3 of the NUREG-1 800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the DGCW system in the LRA. The staff did not identify any

omissions.

Also, the staff selected system functions described in the UFSARs that were set forth in 10

CFR 54.4 to verify that components having intended functions were not omitted from the scope

of the Rule. The staff also focused on components that were not identified as being subject to

an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the DGCW system that are within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the

system drawings and system descriptions in the UFSARs to ensure that the referenced P&l

drawings were representative of the DGCW system. The staff then reviewed the referenced

P&l drawings to verify that those portions of the DGCW system that meet the'scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal and are identified

as such by the applicant in LRA Section 2.3.3.12 and that the applicant identified all DGCW

system components within the scope of license renewal and subject to an AMR in accordance

with 10 CFR 54.4 and 10 CFR 54.21(a)(1).

The staff found that those portions of the DGCW system that meet the scoping requirements of

10 CFR 54.4 are included within the scope of license renewal and are identified as such by the

: applicant in LRA Section 2.3.3.12. The DGCW system components that are subject to an AMR

in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1) are included in LRA Table 2.3.3-12.

The staff did not identify any omissions.

2.3.3.12.3 Conclusions

The staff reviewed LRA Section 2.3.3.12 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. The

staff did not identify any omissions. On the basis of its review, the staff concludes that the

applicant has adequately identified the components of the DGCW system that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the DGCW system that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.3.13 Diesel Fuel Oil System

2.3.3.13.1 Summary of Technical Information in the Application

The applicant described the diesel fuel oil (DFO) system in LRA Section 2.3.3.13 and provided

a list of components subject to an AMR in LRA Table 2.3.3-13.

The function of the DFO system is to store and supply DFO for the EDGs, the SBO DGs, the

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diesel fire pumps, and (at Dresden only) the isolation condenser makeup pump diesels. Using

the methodology described in LRA Section 2.1.4.1 for identifying the mechanical components

within the scope of license renewal, the applicant identified the following DFO system intended

functions:

* support ESF function(s)-stores and provides a source of clean diesel fuel oil to the

emergency diesel generators which supply on-site AC power to ESF systems

* credited in regulated events-stores and provides oil to the diesel fire pump (10 CFR 50.48)

and the isolation condenser system (at Dresden only) diesel

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of non-safetyrelated components that could be a hazard to safety-related SSCs so that the intended

function of safety-related SSCs is not adversely affected

A separate fuel oil storage and transfer system, consisting of tanks, pumps, filters, strainers,

and associated piping, valves, and instrumentation and controls, is provided for each EDG.

Each storage and transfer system includes a fuel oil storage tank and a fuel oil day tank. Fuel

is transferred from the fuel oil storage tank to the fuel oil day tank by the diesel fuel oil transfer

pump. Transfer is accomplished automatically by level switches on the day tank. Fuel oil from

the fuel oil day tank is drawn through the engine-driven fuel oil pump and discharged through

the duplex fuel oil filter and on to the diesel engine injectors. Any excess fuel is returned to the

fuel oil day tank. At Dresden, the Unit 2 EDG fuel oil transfer system also supplies fuel oil to

the isolation condenser makeup pump fuel oil day tanks and the Unit 3 EDG fuel oil transfer

system also supplies fuel oil to the Unit 2/3 diesel fire pump day tank. At Quad Cities, the Unit

1 and Unit 2 EDG fuel oil transfer systems also supply fuel oil for the diesel fire pump day

tanks.

The applicant described the evaluation boundary for the DFO system in LRA Section 2.3.3.13.

In addition, the applicant highlighted those portions of the DFO system within the scope of the

Rule in the P&l drawings listed as references in LRA Section 2.3.3.13. Also, based on the

methodology described in LRA Section 2.1.5 for identifying the mechanical components subject

to an AMR, the applicant identified the following component groups and their intended functions

within the DFO system in LRA Table 2.3.3-13 as being within the scope of license renewal and

subject to an AMR:

* closure bolting (pressure boundary)

* filters/strainers (pressure boundary)

* filters/strainers (filter)

* flame arrestors (fire barrier)

* piping and fittings (pressure boundary)

* piping and fittings (structural integrity/attached support)

* pumps (pressure boundary)

* restricting orifices (pressure boundary, Quad Cities only)

* tubing (pressure boundary)

* sight glasses (pressure boundary)

* tanks (pressure boundary)

* valves (pressure boundary)

* valves (structural integrity/attached support)

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2.3.3.13.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.13, Dresden UFSAR Section 9.5.4, and Quad Cities

UFSAR Section 9.5.4 to determine whether there is reasonable assurance that the DFO system

components within the scope of license renewal and subject to an AMR have been identified in

accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff's review was conducted in

accordance with Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the DFO system in the LRA. The staff did not identify any omissions.

Also, the staff selected system functions described in the UFSARs that were set forth in

10 CFR 54.4 to verify that components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the DFO system that are within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the

system drawings and system descriptions in the UFSARs to ensure that the referenced P&l

drawings were representative of the DFO system. The staff then reviewed the referenced P&l

drawings to verify that those portions of the DFO system that meet the scoping requirements of

10 CFR 54.4 are included within the scope of license renewal and are identified as such by the

applicant in LRA Section 2.3.3.13 and that the applicant identified all DFO system components

within the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1).

The staff found that those portions of the DFO system that meet the scoping requirements of

10 CFR 54.4 are included within the scope of license renewal and are identified as such by the

applicant in LRA Section 2.3.3.13. The DFO system components that are subject to an AMR in

accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1) are included in LRA Table 2.3.3-13. The

staff did not identify any omissions.

2.3.3.13.3 Conclusions

The staff reviewed LRA Section 2.3.3.13 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. The

staff did not identify any omissions. On the basis of its review, the staff concludes that the

applicant has adequately identified the components of the DFO system that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the DFO system that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

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2.3.3.14 Process Sampling System

2.3.3.14.1 Summary of Technical Information in the Application

The applicant described the process sampling system in LRA Section 2.3.3.14 and provided a

list of components subject to an AMR in LRA Table 2.3.3-14.

The process sampling systems/subsystems are used to monitor process parameters from

various systems. Samples are taken and analyzed on a continuous and/or laboratory basis.

Selected parameters are recorded and/or alarmed. At Dresden, the process sampling systems

include nitrogen inerting and drywell oxygen sampling, turbine building and radwaste air

particulate sampling, drywell air particulate sampling, and off-gas building air particulate

sampling. At Quad Cities, the process sampling systems include drywell oxygen analysis,

drywell air particulate, and turbine building particulate sampling. Sample lines that penetrate

the primary containment are provided with isolation valves.

Using the methodology described in LRA Section 2.1.4.1 for identifying the mechanical

components within the scope of license renewal, the applicant identified the following intended

process sampling system function:

primary containment isolation-provides isolation of air sampling system piping penetrating

primary containment

At Dresden, the evaluation boundary includes the process sampling systems for nitrogen

inerting and drywell oxygen sampling, drywell air particulate sampling, turbine building and

radwaste air particulate sampling, and off-gas building air particulate sampling. At Quad Cities,

the evaluation boundary includes the process sampling systems for drywell oxygen analysis,

drywell air particulate, turbine building particulate sampling, and off-gas filter building

continuous air monitor.

In LRA Section 2.3.3.14, the applicant described the evaluation boundary of the process

sampling system. In addition, the applicant highlighted those portions of the system and its

structures and components that are within the scope of the Rule in the P&l drawings listed as

reference in LRA Section 2.3.3.14. Also, based on the methodology described in LRA Section

2.1.5 for identifying the mechanical components subject to an AMR, the applicant identified the

following component groups and their intended functions within the process sampling system in

LRA Table 2.3.3-14 as being within the scope of license renewal and subject to an AMR:

* closure bolting (pressure boundary)

* NSR vents or drains, piping and valves (structure integrity/attached support, Quad Cities

only)

* piping and fittings (structure integrity/attached support, Quad Cities only)

* piping and fittings (pressure boundary, Quad Cities only)

* tubing (pressure boundary)

* valves (pressure boundary)

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* valves (leakage boundary spatial interaction, Quad Cities only)

* valves (structure integrity/attached support,) (Quad Cities only)

2.3.3.14.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14, and Dresden UFSAR Sections 1.2.2.4, 5.2.5.6.1,

6.2.1, 7.3.2, and 9.3.2 and Quad Cities UFSAR Sections 1.2, 5.2, 6.2, 7.3, and 9.3.2 to

determine whether there is reasonable assurance that the process sampling system

components within the scope of license renewal and subject to an AMR have been identified in

accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff review was conducted in

accordance with Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the process sampling system in the LRA. The staff did not identify

any omissions.

Also, the staff selected system functions described in the UFSAR that were set forth in

10 CFR 54.4 to verify that components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the process sampling system that are

within the scope of license renewal and subject to an AMR, in accordance with 10 CFR 54.4

and 10 CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the

system drawings and system descriptions in the UFSARs to ensure that the referenced P&l

drawings were representative of the process sampling system. The staff then reviewed the

referenced P&l drawings to verify that those portions of the process sampling system that meet

the scoping requirements of 10 CFR 54.4 are included within the scope of license renewal and

are identified as such by the applicant in LRA Section 2.3.3.14 and that the applicant identified

all process sampling system components within the scope of license renewal and subject to an

AMR in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.14 identified areas in which additional information is

necessary to complete the staff's review of the applicant's scoping and screening results.

Therefore, by the August 4, 2003, letter, the staff issued RAls to the applicant concerning the

specific items to determine whether the applicant has properly applied the scoping and

screening criteria of 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's RAls and the applicant

responses, dated October 3, 2003, are described below.

RAI 2.3.3.14-1. Line 1-1655-2"-L is shown on process sampling (PS) diagram LR-QDC-461-1

(E-5) requiring AMR and extends to drawing M-34-1 (C-6). The LR interface for AMR between

PS and other systems for this line is not shown on drawing M-34-1. Similarly line 2-1655-2"-L is

shown on PS diagram LR-QDC-M-463-1 (C-3) and extends to drawing M-76-1 (C-5). The LR

interface for AMR between PS and other systems for this line is not shown on drawing M-76-1.

The staff asked the applicant to identify the boundary for these lines between PS and other

systems and where the LRA addresses the AMR of these components, or provide a justification

for excluding these components from an AMR.

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Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.14-1 stated that piping and piping components shown on

boundary diagram LR-QDC-M-461-1, highlighted in green, fall within the scope of license

renewal and require aging management. Piping shown on boundary diagram LR-QDC-M-461-1

at coordinate E-5 (includes valves 1-8803 and 1-8804) was evaluated with the PC system.

Boundary diagram LR-QDC-461-1 should have included the LR boundary flag for the PC

system at valve 1-8803. Remaining portions of pipe highlighted in green on boundary diagram

LR-QDC-M-461-1, were evaluated with either the process sampling or primary containment

systems as shown by the LR interface boundary flag on the boundary diagram.

Piping and piping components shown on boundary diagram LR-QDC-M-463-1, highlighted in

green, fall within the scope of license renewal and require aging management. Piping on

boundary diagram LR-QDC-M-463-1 at coordinate C-2 (includes valves 2-8803 and 2-8804)

was evaluated with the PC system. Boundary diagram LR-QDC-463-1 should have included

the LR boundary flag for the PC system at valve 2-8803. Remaining portions of pipe,

highlighted in green on boundary diagram LR-QDC-M-463-1, were evaluated with either the

process sampling or primary containment systems as shown by the LR interface boundary flag

on the drawing.

LRA Table 2.3.2-3 includes those components evaluated within the PC system boundary and

provides the appropriate aging management reference for each component group. LRA Table

2.3.3-14 includes those components evaluated within the process sampling system boundary

and provides the appropriate aging management reference for each component group.

Boundary diagrams LR-QDC-M-461-1 and LR-QDC-463-1 should have included the

appropriate system boundary flags.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.14-1 acceptable because it conforms with the criteria set forth

in 10 CFR 54.4 and 10 CFR 54.21(a)(1). Therefore, the staff considers its concern described in

RAI 2.3.3.14-1 resolved.

RAI 2.3.3.14-2. Line 2-9224 on drawing LR-DRE-M-178 (E-6) and line 3-9224 on drawing LRDRE-M-421 (C-6) requiring AMR shows coming from main steam tunnel but no drawing number

and coordinates of main steam tunnel are given for these lines. Similarly line 2-9203 on

drawing LRE-DRE-M-178 (F-6) and line 3-9203 on drawing LRE-DRE-M-421 (C-9) requiring

AMR shows coming from drawings M-25 and M-356 but no coordinates of M-25 and M-356 are

given for these lines. The staff asked the applicant to identify the above drawing numbers and

coordinates for lines 2-9224, 3-9224, 2-9203, and 3-9204. The staff also asked the applicant to

identify the boundary break between PS and other systems for these lines and associated

valves and where the LRA addresses the AMR of these components, or provide a justification

for excluding these component from an AMR.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.14-2 stated that as shown on boundary diagrams LRDRE-M-178 and LR-DRE-M-421, the PS system piping and tubing highlighted in green is

safety-related and provides a pressure retaining function. This piping and tubing is evaluated

with the PS system and is in the scope of license renewal requiring AMR. The piping is skid

mounted (rigid) and was provided by the vendor. Piping and piping components beyond the

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safety-related PS system boundary (colored in black) are evaluated with the PS system and are

outside the scope of license renewal.

On boundary diagram LR-DRE-M-178 (E-6 and F-6), line 2-9224-1/2'-T is air sample tubing

and line 2-9203-1/2'-AK is air sample piping that are not connected to the process piping and

do not continue from any other boundary diagram. The arrow shown on boundary diagram

LR-DRE-M-178 (that includes valves 2-8507-523, 2-8599-652, 2-8507-501, and 2-8599-630)

indicates that the piping comes from the main steam tunnel and drywell. The piping is open to

the atmosphere to draw air samples from the area.

LRA Section 2.3.3.14, Table 2.3.3-14, includes components evaluated within the PS system

boundary and provides the appropriate aging management reference for each component

group. The components within the scope of license renewal are evaluated for AMR as follows:

* AMR for the valves is addressed in aging management references 3.3.2.23, 3.3.2.40,

3.3.2.264, and 3.3.2.295.

* AMR for tubing is addressed in aging management references 3.3.2.42, 3.3.2.254, 3.3.2.34,

and 3.3.2.244.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.14-2 acceptable because it conforms with the criteria set forth

in 10 CFR 54.4 and 10 CFR 54.21(a)(1). Therefore, the staff considers its concern described in

RAI 2.3.3.14-2 resolved.

2.3.3.14.3 Conclusions

The staff reviewed LRA Section 2.3.3.14, accompanying scoping boundary drawings and the

applicant's response to RAls dated October 3, 2003, to determine whether any SSCs within the

scope of license renewal had not been identified by the applicant. In addition, the staff

performed an independent assessment to determine whether any components that should be

subject to an AMR were not identified by the applicant. The staff did not identify any omissions.

On the basis of its review, the staff concludes that the applicant has adequately identified the

components of the process sampling system that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and that the applicant has adequately identified the components of

the process sampling system that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.15 Carbon Dioxide System

2.3.3.15.1 Summary of Technical Information in the Application

The applicant described the carbon dioxide (C02 ) system in LRA Section 2.3.3.15 and provided

a list of component groups subject to anAMR in LRA Table 2.3.3.15. The CO2 system provides

fire suppression for three emergency diesel generator rooms, the two alternator exciters in the

main generator housings, and, at Dresden only, the auxiliary equipment room. The system also

provides for generator purging.

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2.3.3.15.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.15 and referenced LRA boundary drawings to determine

whether there is reasonable assurance that the C02 system components within the scope of

license renewal and subject to an AMR have been identified in accordance with 10 CFR 54.4

and 10 CFR 54.21(a)(1).

In the performance of the review, the staff selected system functions described in the UFSAR

that were required by 10 CFR 54.4 to verify that components having intended functions were

not omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

In a letter dated August 4, 2003, the staff requested that the applicant clarify the boundary of

the in-scope portions of the system to verify that the discharge nozzles are included or to justify

their exclusion (RAI 2.3.3.15-1a). In a letter dated October 3, 2003, the applicant responded

that the C02 discharge nozzles for Dresden are included within the scope of license renewal

and are subject to the same AMR as the Quad Cities C02 discharge nozzles. The C02

discharge nozzles are addressed in LRA Table 2.3.3-15 under the component group "piping

and fittings." Aging management reference 3.3.1.5 addresses the aging management of the

external surface of the carbon steel CO2 discharge nozzles. Aging management reference

3.3.2.138 addresses the aging management of the internal surface of the C02 discharge

nozzles. LRA boundary drawing, LR-DRE-M-42 should have highlighted the C02 fire

suppression system discharge nozzles indicating that they were within the scope of license

renewal. The staff finds the applicant's response acceptable as it clarifies the components

within the scope of license renewal.

In a letter dated August 4, 2003, the staff also requested that the applicant clarify which

components of these systems are addressed in the references in LRA Table 2.3.3.15 and Table

3.3.1 (RAI 2.3.3.15-1 b). In a letter dated October 3, 2003, the applicant responded that the

C02 storage tank, valves, and other components fall within the scope of license renewal and

are subject to an AMR. They are included under component groups "piping and fittings,"

"tanks," "tubing," and "valves" in LRA Table 2.3.3.15. The external surface of these

components is evaluated in aging management reference 3.3.1.5 and the internal surfaces are

evaluated in aging management references 3.3.2.138, 3.3.2.212, 3.3.2.234, 3.3.2.260, and

3.3.2.268. The staff finds the response provided by the applicant acceptable as it clarifies

which components are specifically referred to by reference 3.3.1.5.

LRA boundary drawing LR-QDC-M-30-3 does not show the 7.5 ton C02 tank as within the

scope of license renewal. This is inconsistent with LRA boundary drawing LR-DRE-M-42. The

staff believes that the C02 storage tank should be within the scope of license renewal and

subject to an AMR. In a letter dated August 4, 2003, the applicant was asked to clarify whether

the C02 storage tank at Quad Cities is in scope and subject to an AMR or provide justification

for its exclusion (RAI 2.3.3.15-1b). In a letter dated October 3, 2003, the applicant responded

that the 7.5 ton C02 tank falls within the scope of license renewal. LRA boundary drawing LRQDC-M-30-3 should have highlighted the 7.5 ton C02 tank as within the scope of license

renewal. These tanks are addressed in LRA Table 2.3.3-15 under the component group

"tanks." Aging management reference 3.3.1.5 addresses the aging management of the

external surface of the carbon steel C02 tanks and aging management reference 3.3.2.212

addresses the aging management of the internal surface. The staff finds the applicant's

response acceptable on the basis that it clarifies that the 7.5 ton C02 tank is within the scope of

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license renewal and subject to an AMR.

2.3.3.15.3 Conclusions

The staff reviewed LRA Section 2.3.3.15, the accompanying scoping boundary drawings, and

the applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. In addition', the staff performed an

independent assessment to determine whether any components that should be subject to an

AMR were not identified by the applicant. The staff did not identify any omissions. On the

basis of its review, the staff concludes that the applicant has adequately identified the

components of the C02 fire suppression system that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and that the applicant has adequately identified the components of

the C02 fire suppression system that are subject to an AMR, as required by 10 CFR

54.21 (a)(1).

2.3.3.16 Service Water System

2.3.3.16.1 Summary of Technical Information in the Application

The applicant describes the service water (SW) system in LRA Section 2.3.3.16 and provides a

list of components subject to an AMR in LRA Table 2.3.3-16.

The function of the SW system is to provide strained river water to cool various loads in the

reactor building, turbine building, and auxiliary building during plant normal operation. Using

the methodology described in LRA Section 2.1.4.1 for identifying the'mechanical components

within the scope of license renewal, the applicant identified the following SW system intended

functions:

* preclude adverse'eff ects on safety-related SSCS's-maintains sufficient integrity of nonsafety-related components that could spatially interact and be a hazard to safety-related

SSCs so that the intended function of safety-related SSCs is not adversely affected

* structural support-non-safety-related portions of this system provide structural support to

attached safety-related piping (Quad Cities only)

* pressure boundary-maintain pressure boundary of the CCSW keep fill line (Dresden only)

* support ESF function(s)-provides cooling water to ECCS room coolers to ensure proper

environment for ECCS pump operation (Dresden only)

* - credited in regulated event(s)-'provides cooling water to safe shutdown equipment credited

in mitigation of the Appendix R fire (Dresden only)

* emergency makeup-provides an alternate supply of water for makeup to the isolation

condenser (Dresden only)

* plant component cooling-provide strained cooling water to the RBCCW (Dresden only)

The SW system has five pumps, three strainers, and a common distribution header. Two SW

pumps are provided per unit, and the fifth shared pump is used as a backup. The system is

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cross connected between the units. The majority of the loads are heat exchangers, coolers,

and condensers.

The SW system provides cooling to the heat exchangers, turbine building closed cooling water

heat exchangers, traveling screen wash spray, fire protection system, turbine oil coolers,

reactor recirculation pump motor generator (M-G) set oil coolers, generator hydrogen coolers,

generator stator water coolers, standby coolant supply, control room air conditioning

condensers, auxiliary electric equipment room air conditioning condenser (Dresden only), offgas glycol chillers, X-area (Dresden)/MSIV room (Quad Cities) coolers (steam tunnel coolers),

off-gas filter building sample system heat exchanger, and control rod drive pump coolers

(Dresden only, and only as a backup to turbine building closed cooling water heat exchangers).

The applicant described the evaluation boundary of the SW system in LRA Section 2.3.3.16. In

addition, the applicant highlighted those portions of the SW system within the scope of the Rule

in the P&l drawings listed as references in LRA Section 2.3.3.16. Also, based on the

methodology described in LRA Section 2.1.5 for identifying the mechanical components subject

to an AMR, the applicant identified the component groups and their intended functions within

the SW system in LRA Table 2.3.3-16 as being within the scope of license renewal and subject

to an AMR.

Resulting from the revised methodology described in the May 18, 2004 response to the draft

SER Open Item 2.1-1 and clarified in a letter, dated June 22, 2004, the applicant expanded the

system boundaries for the SW system at both Dresden and Quad Cities due to the potential for

spatial interaction with safety-related components. The applicant included all of the SW

components shown on revised boundary diagrams LR-QDC-M-22-4, LR-QDC-M-22-5,

LR-QDC-M-69-4, LR-QDC-M-69-5, LR-DRE-M-22, LR-DRE-M-355 within the scope of license

renewal. The applicant included in the scope additional service water piping components

shown on revised boundary diagrams LR-QDC-M-69-1 and LR-QDC-M-22-1 and new boundary

diagrams LR-DRE-M-101 1-5 and LR-DRE-M-3496. These changes resulted in adding three

component groups to LRA Table 2.3.3-16.

The applicant included non-safety-related heat exchangers (e.g., 1 B-3802 at location E-5 on

revised boundary diagram LR-QDC-M-22-1), oil coolers (e.g., 2-202-51 C at location F-2 on

revised boundary diagram LR-DRE-M-22), and generator stator water coolers (e.g., 3-7002-A at

location E-1 0 on revised boundary diagram LR-DRE-M-355) in scope for the spatial interaction

intended function and evaluated them with the component group, piping and fittings (spatial

interaction), on Table 2.3.3-16 for AMR. The heat exchanger (cooler) leakage boundary is

comprised of the same materials and experiences the same environment as the components

evaluated under the component group, piping and fittings (spatial interaction).

The following is the component groups and their intended functions within the SW system in the

revised LRA Table 2.3.3-16 as being within the scope of license renewal and subject to an

AMR:

* closure bolting (pressure boundary)

* flow orifices (structural integrity/attached support, Quad Cities only)

* orifice bodies (pressure boundary, Dresden only)

* orifice bodies (throttle, Dresden only)

* piping and fittings (spatial interaction) (includes heat exchanger shells)

* piping and fittings (pressure boundary, Dresden only)

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* piping and fittings (structural integrity/attached support, Quad Cities only)

* pumps (pressure boundary, Dresden only)

* strainer bodies (pressure boundary, Dresden only)

* strainer bodies (filter)

* strainer bodies (spatial interaction) (leakage boundary, Quad Cities only)

* tanks (spatial interaction) (leakage boundary, Dresden only)

* thermowells (pressure boundary, Dresden only)

* tubing (pressure boundary, Dresden only)

* tubing (spatial interaction) (leakage boundary)

* valves (spatial interaction)

* valves (structural integrity/attached support)

* valves (pressure boundary, Dresden only)

2.3.3.16.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.16, Dresden UFSAR Section 9.2.2, and Quad Cities

UFSAR Section 9.2.2. Additionally, the staff reviewed other UFSAR sections that discussed the

SW system to determine whether there is reasonable assurance that the SW system

components within the scope of license renewal and subject to an AMR have been identified in

accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). At Dresden, these sections included

1.2, 2.4, 3.3.2, 3.4.1, 3.6.1, 5.4.6, 6.0.3, 6.2, 6.3.2, 6.4.2, 7.5.3, 9.1.3,9.2.1, 9.2.3, 9.2.5,9.2.7,

9.2.8, 9.4.6, 9.5.5, 11.0, 11.2, 11.5, 14.2.4, and 15.6.5. At Quad Cities, these sections included

1.2, 2.2.3,3.7.3, 6.0, 6.1.10, 6.3.2, 6.4.2, 8.3.1, 9.1.3, 9.2.3, 9.2.7, 9.2.8, 9.3.1, 9.3.5, 9.5.1,

9.5.5, 11.5.2, and 14.2.12. The staff's review was conducted in accordance with Section 2.3 of

NUREG-1800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the SW system in the LRA. The staff did not identify any omissions.

Also, the staff selected system functions described in the UFSARs that were set forth in1O CFR

54.4 to verify that components having intended functions were not omitted from the scope of

the Rule. The staff also focused on components that were not identified as being subject to an

AMR to determine if any components were omitted.

To verify that the applicant identified the components of the SW system that are within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the system

drawings and system descriptions in the UFSARs to ensure that the referenced P&l drawings

were representative of the SW system. The staff then reviewed the referenced P&l drawings to

verify that those portions of the SW system that meet the scoping requirements of 10 CFR 54.4

are included within the scope of license renewal and are identified as such by the applicant in

LRA Section 2.3.3.16, and that the applicant identified all SW system components within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 1OCFR

54.21 (a)(1).

The staff's review of LRA Section 2.3.3.16 identified one area in which additional information is

necessary to complete the staff's review of the applicant's scoping and screening results.

Therefore, by the August 4, 2003, letter, the staff issued an RAI to the applicant concerning the

specific item needed to determine whether the applicant has properly applied the scoping and

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screening criteria of 10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff's RAI and the applicant's

response by letter dated October 3, 2003, are described below.

RAI-2.3.3.16-1. The staff observed that there are no references to buried piping in Table 2.3.3-

16 of the LRA. RA and asked the applicant to provide the basis for not identifying any buried

SW piping in Table 2.3.3-16.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.16-1 is that it reviewed LRA Section 2.3.3.16, Table

2.3.3-16, and agree with NRC staff that there is no aging management reference in Table

2.3.3-16 for the external surface of buried piping. The buried SW piping is included within the

scope of license renewal. Section 2.3.3.16, Table 2.3.3-16, should have included the subject

buried piping under the component group 'piping and fittings (Dresden only)," with "pressure

boundary" as the component intended function. Aging management reference 3.3.1.16

discusses the aging management of the buried piping external surfaces as a carbon steel

component in open-cycle cooling water system (service water). Aging management reference

3.3.1.15 discusses the aging management of the piping internal surfaces as a carbon steel

component in open-cycle cooling water system (service water). Aging management reference

3.3.1.16 was inadvertently omitted from LRA Section 2.3.3.16, Table 2.3.3-16. Aging

management reference 3.3.1.16 should have been included in Table 2.3.3-16 as an aging

management reference for buried SW piping.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.16-1 acceptable

because the applicant (1) agrees with the staff that there is no aging management reference in

LRA Table 2.3.3-16 for the external surface of buried piping; (2) has clarified that the subject

buried SW piping is included within the scope of the Rule; and (3) acknowledges that aging

management reference 3.3.1.16 was inadvertently omitted from LRA Table 2.3.3-16 that should

have included the subject buried piping under the component group "piping and fittings

(Dresden only)," with "pressure boundary" as the component intended function. Therefore, the

staff considers its concern described in RAI 2.3.3.16-1 resolved.

2.3.3.16.3 Conclusions

The staff reviewed LRA Section 2.3.3.16, the accompanying scoping boundary drawings, and

the applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. In addition, the staff performed an

independent assessment to determine whether any components that should be subject to an

AMR were not identified by the applicant. The staff did not identify any omissions. On the

basis of its review, the staff concludes that the applicant has adequately identified the

components of the SW system that are within the scope of license renewal, as required by 10

CFR 54.4(a), and that the applicant has adequately identified the components of the SW

system that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.17 Reactor Building Closed Cooling Water System

2.3.3.17.1 Summary of Technical Information in the Application

The applicant described the reactor building closed cooling water system (RBCCW) in LRA

Section 2.3.3.17 and provided a list of components subject to an AMR in LRA Table 2.3.3-17.

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The function of .the RBCCW system is to provide cooling for equipment and systems in the

reactor. For Dresden only, the system also provides cooling water to the shutdown cooling heat

exchangers. Using the methodology described in LRA Section 2.1.4.1 for identifying the

mechanical components within the scope of license renewal, the applicant identified the

following RBCCW system intended functions:

* primary containment isolation-provide primary containment isolation for those portions of

the system that interface with the primary containment

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected

* credited in regulated event(s) (Dresden only)- provides cooling water to the shutdown

cooling heat exchangers to achieve and maintain cold shutdown during an Appendix R fire

(at Dresden and Quad Cities the system also contains components that are relied upon for

compliance with 10 CFR 50.49 (EQ))

The RBCCW system is a closed loop system. An expansion tank is connected to the common

RBCCW pump suction header to ensure adequate net positive suction head for the pumps (two

for each unit, with one additional shared spare). The pumps discharge into a common header

from which cooling water is provided to loads arranged in several loops. One loop provides

cooling to reactor building auxiliary loads such as the reactor water cleanup nonregenerative

heat exchangers, the fuel pool heat exchangers, and the reactor building equipment drain tank

heat exchanger. A loop inside the primary containment provides cooling to the primary

containment coolers, primary containment equipment drain sump heat exchanger, and the

reactor recirculation pump seals and motor oil coolers. For Dresden only, a loop also provides

cooling to the shutdown cooling heat exchangers to achieve and maintain cold shutdown during

an Appendix R fire. The loops all discharge into a common header at the inlet to the RBCCW

heat exchangers (also-two for each unit with one additional shared spare). The RBCCW

discharge from the heat exchangers flows back into the RBCCW pump suction header. The

SW system cools the RBCCW heat exchangers.

Primary containment isolation valves are provided for the RBCCW lines penetrating the primary

containment.

In LRA Section 2.3.3.17, the applicant described the evaluation boundary of the RBCCW

system. In addition, the applicant highlighted those portions of the RBCCW system within the

scope of the Rule in the P&l drawings listed as references in LRA Section 2.3.3.17. Also,

based on the methodology described in LRA Section 2.1.5 for identifying the mechanical

components subject to an AMR, the applicant identified the component groups and their

intended functions within the RBCCW system in LRA Table 2.3.3-17 as being within the scope

of license renewal and subject to an AMR.

Resulting from the revised methodology described in the response to the draft SER Open Item

2.1-1 and clarified in a letter, dated June 22, 2004, the applicant expanded the system

boundaries for the RBCCW system at both Dresden and Quad Cities due to the potential for

spatial interaction with safety-related components. The applicant added all of the RBCCW

components shown on revised boundary diagrams LR-DRE-M-20, LR-DRE-M-353,

LR-QDC-M-33-1, LR-QDC-M-33-2, LR-QDC-M-75-1, and LR-QDC-M-75-2 to the scope of

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license renewal. These changes resulted in adding two component groups to LRA

Table 2.3.3-17.

The following is component groups and their intended functions within the RBCCW system in

the revised LRA Table 2.3.3-17 as being within the scope of license renewal and subject to an

AMR:

* closure bolting (pressure boundary)

* flow elements (pressure boundary, Dresden only)

* heat exchangers (pressure boundary, Dresden only)

* heat exchangers (heat transfer, Dresden only)

* heat exchangers (spatial interaction) (leakage boundary (spatial))

* manifolds (pressure boundary, Dresden only)

* NSR vents or drains, piping and valves (attached support) (structural integrity (attached),

Quad Cities only)

* Orifice bodies (pressure boundary, Dresden only)

* piping and fittings (pressure boundary)

* piping and fittings, including flow elements (spatial interaction) (leakage boundary (spatial))

* piping and fittings (structural integrity/attached support, Quad Cities only)

* pumps (pressure boundary, Dresden only)

* pumps (spatial interaction) (leakage boundary (spatial))

* tanks (pressure boundary, Dresden only)

* tanks (spatial interaction) (leakage boundary (spatial))

* thermowells (pressure boundary, Dresden only)

* tubings (pressure boundary, Dresden only)

* tubings (spatial interaction) (leakage boundary (spatial))

* valves (pressure boundary)

* valves (spatial interaction)

* valves (structural integrity/attached support, Quad Cities only)

2.3.3.17.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.17, Dresden UFSAR Section 9.2.3, and Quad Cities

UFSAR Section 9.2.3. Additionally, the staff reviewed other UFSAR sections that discussed the

RBCCW system to determine whether there is reasonable assurance that the RBCCW system

components within the scope of license renewal and subject to an AMR have been identified in

accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). At Dresden, these sections included

1.2, 3.6.2, 3.8, 5.2.5, 5.4.7, 6.2.1, 7.4.2, 9.1.2, 9.1.3, 9.3.2, 9.4.8, 11.5, and 14.2.4. At Quad

Cities, these sections included 1.2, 5.2.5, 5.4.7, 5.4.8, 6.2.1, 9.1.3, 9.3.3, 9.4.7, and 11.5. The

staff's review was conducted in accordance with Section 2.3 of NUREG-1 800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the RBCCW system in the LRA. The staff did not identify any

omissions.

Also, the staff selected system functions described in the UFSARs that were set forth in

10 CFR 54.4 to verify that components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

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To verify that the applicant identified the components of the RBCCW system that are within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1), respectively, the staff reviewed and compared the referenced P&l drawings to the

system drawings and descriptions in the UFSARs to ensure that they were representative of the

RBCCW system. The staff then reviewed the referenced P&l drawings to verify that those

portions of the RBCCW system that meet the scoping requirements of 10 CFR 54.4 are

included within the scope of license renewal and are identified as such by the applicant in LRA

Section 2.3.3.17, and that the applicant identified all RBCCW system components within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1).

The staff found that those portions of the RBCCW system that meet the scoping requirements

of 10 CFR 54.4 are included within the scope of license renewal and are identified as such by

the applicant in LRA Section 2.3.3.17. The RBCCW system components that are subject to an

AMR in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1) are included in LRA Table

2.3.3-17. The staff did not identify any omissions.

2.3.3.17.3 Conclusions

The staff reviewed LRA Section 2.3.3.17 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. The

staff did not identify any omissions. On the basis of its review, the staff concludes that the

applicant has adequately identified the components of the RBCCW system that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the RBCCW system that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.3.18 Turbine Building Closed Cooling Water System

2.3.3.18.1 Summary of Technical Information in the Application

The applicant described the turbine building closed cooling water (TBCCW) system in LRA

Section 2.3.3.18 and provided a list of components subject to an AMR in LRA Table 2.3.3-18.

The function of the TBCCW system is to provide the means for heat rejection from systems

located in the turbine building and crib house. Using the methodology described in LRA

Section 2.1.4.1 for identifying the mechanical components within the scope of license renewal,

the applicant identified the following TBCCW system intended function:

credited in regulated event(s) (Dresden only)-provides flow path for control rod drive pump

cooling during an Appendix R fire

The TBCCW system is a closed loop system consisting of pumps, heat exchangers, an

expansion tank, and necessary control and support equipment. The system removes heat from

the following loads-circulating water pumps, feed pump lube oil and mechanical seal coolers,

condensate and condensate booster pump seal coolers, CRD pump seal coolers, instrument air

compressors, resin transfer air compressors, service air compressors, radwaste sparging air

compressors, electrohydraulic control (EHC) oil coolers, bus duct coolers, and main generator

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alternator exciter cooler. Station SW provides the cooling medium on the tube side of the

TBCCW heat exchangers.

In LRA Section 2.3.3.18, the applicant described the evaluation boundary of the TBCCW

system. In addition, the applicant highlighted those portions of the TBCCW system within the

scope of the Rule in the P&I drawings listed as references in LRA Section 2.3.3.18. Also,

based on the methodology described in LRA Section 2.1.5 for identifying the mechanical

components subject to an AMR, the applicant identified the component groups and their

intended functions within the TBCCW system in LRA Table 2.3.3-18 as being within the scope

of license renewal and subject to an AMR.

Resulting from the revised methodology described in the May 18, 2004 response to the draft

SER Open Item 2.1-1 and clarified in a letter, dated June 22, 2004, the applicant expanded the

system boundaries for the TBCCW system at Dresden Station due to the potential for spatial

interaction with safety-related components. Specifically, the applicant added all of the TBCCW

pumps, heat exchangers, piping, valves, surge tank, and other passive system components to

the scope of license renewal. The applicant added all of the components shown on revised

boundary diagrams LR-DRE-M-21, LR-DRE-M-354-1 and LR-DRE-M-354-2 to the scope of

license renewal. Additional components added to the scope along with system boundary flags

are shown on revised boundary diagrams LR-DRE-M-37-7, LR-DRE-M-37-10,

LR-DRE-M-177-1, LR-DRE-M-177-4, LR-DRE-M-178, LR-DRE-M-419-1, LR-DRE-M-419-4,

LR-DRE-M-420, LR-DRE-M-421 and new boundary diagrams LR-DRE-M-177-3,

LR-DRE-M-367-4, and LR-DRE-M-367-6.

The applicant previously excluded the TBCCW system at Quad Cities from the scope of license

renewal. However, the applicant added the TBCCW system at Quad Cities to the scope of

license renewal as a result of the scoping methodology change. Specifically, the applicant

added all of the TBCCW pumps, heat exchangers, piping, valves, surge tank, and other passive

system components to the scope due to the potential for spatial interaction with safety-related

components in the same general area. The applicant added equipment highlighted on revised

boundary diagram LR-QDC-M-462-3,and new boundary diagrams LR-QDC-M-21,

LR-QDC-M-68, LR-QDC-M-459-1, LR-QDC-M-459-3, and LR-QDC-M-462-1 to the scope of

license renewal. These changes resulted in adding three component groups to LRA

Table 2.3.3-18.

The applicant included non-safety-related heat exchangers (e.g., cooling water heat

exchangers, 1IA-3802 at location D-3 on revised boundary diagram LR-QDC-M-21) and coolers

(e.g., the alternator cooler at location E-9 on revised boundary diagram LR-QDC-M-21) in

scope for the spatial interaction intended function and evaluated them with the component

group, piping and fittings (spatial interaction), on Table 2.3.3-18 for AMR. The heat exchanger

(cooler) leakage boundary is comprised of the same materials and experiences the same

environment as the components evaluated under the component group, piping and fittings

(spatial interaction).

The following is component groups and their intended functions within the TBCCW system in

the revised LRA Table 2.3.3-18 as being within the scope of license renewal and subject to an

AMR:

* closure bolting (pressure boundary)

* heat exchangers (pressure boundary)

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* piping and fittings (pressure boundary)

* piping and fittings (spatial interaction) (includes heat exchanger shells) (leakage boundary

(spatial))

* pumps (spatial interaction) (leakage boundaryl(spatial))

* tanks (spatial interaction) (leakage boundary (spatial))

* valves (pressure boundary)

* valves (spatial interaction) (leakage boundary (spatial))

2.3.3.18.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.18 and Dresden UFSAR Sections 9.2.7, 9.3.1, and 14.2.4

to determine whether there is reasonable assurance that the TBCCW system components

within the scope of license renewal and subject to an AMR have been identified in accordance

with 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's reviewwas conducted in accordance

with Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSAR to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the TBCCW system in the LRA. The staff did not identify any

omissions.

Also, the staff selected system functions described in the UFSAR that were set forth in 10 CFR

54.4 to verify that components having intended functions were not omitted from the scope of

the Rule. The staff also focused on components that were not identified as being subject to an

AMR to determine if any components were omitted.

To verify that the applicant identified the components of the TBCCW system that are within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the system

drawings and system-descriptions in the UFSAR to ensure that the referenced P&l drawings

were representative of the TBCCW system. The staff then reviewed the referenced P&l

drawings to verify that those portions of the TBCCW system that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal and are identified

as such by the applicant in LRA Section 2.3.3.18, and that the applicant identified all TBCCW

system components within the scope of license renewal and subject to an AMR in accordance

with 10 CFR 54.4 and 10 CFR 54.21(a)(1).

The staff's review of LRA Section 2.3.3.18'identified one area in which additional information is

necessary to complete the staff's review of the applicant's scoping and screening results.

Therefore, by the August 4, 2003, letter, the staff issued an RAI to the applicant concerning the

specific item to determine whether the applicant has properly applied the scoping criteria of

10 CFR 54.4 and the screening criteria of 10 CFR 54.21. The staff's RAI and the applicant's

responses by letter, dated October 3, 2003, are described below.

RAI-2.3.3.18-1. The staff observed that on the TBCCW system piping flow diagram, LR-DREM-21, the control rod drive system drain valve 2-3868-B-500 (for pump 2-382-3B) and

associated piping from the header to the drain valve are not shown in scope. The

corresponding piping and drain valve (2-3868-A-500) for the pump 2-382-3A is shown in scope

on LR-DRE-M-21. Also, not shown in scope is a portion of the piping from valve 2-3837-A-500

to the drain valve 2-3867-A-500 (near pump 2-382-3A). Failure of these lines could prevent the

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system from performing its intended function, which is to provide a flow path for control rod

drive pump cooling during an Appendix R fire. The piping is passive, long lived, and not subject

to qualified life or specified time period, and it performs an intended safety function of

maintaining system integrity. The staff asked the applicant to provide the basis for exclusion of

the valve and piping identified above.

Applicant's Response and Staff's Evaluation

In its response to RAI 2.3.3.18-1, the applicant stated that it believes that the staff intended to

reference pumps 2-302-3A and 2-302-3B, rather than 2-382-3A and 2-382-36.

The control rod drive system drain valve 2-3868-B-500 (for pump 2-302-3B), and the associated

piping from the header to the drain valve 2-3868-B-500 (coordinate C-4) on the boundary

diagram, should have been highlighted in green. Also, the portion of the piping from valve

2-3837-A-500 to the drain valve 2-3867-A-500 (near pump 2-302-3A), including the drain valve

(coordinate D-4), should have been highlighted in green. The subject valves and piping are in

scope of license renewal. LRA Section 2.3.3.18, Table 2.3.3-18, includes the subject piping

and valve under the component groups 'piping and fitting" and "valves."

Based on its review of the applicant's clarification discussed above, the staff agrees with the

applicant that the staff intended to reference pumps 2-302-3A and 2-302-36, rather than

2-382-3A and 2-382-36. Also, the staff finds the applicant's response to RAI 2.3.3.18-1 has

clarified that the subject components and piping are within the scope of the Rule and subject to

an AMR, and they were inadvertently not highlighted in green (in scope components per 10

CFR 54.4(a)(1) and 10 CFR 54.4(a)(3)) in the LR boundary diagrams. In addition, the subject

piping and valve are included in LRA Table 2.3.3-18 under component groups "piping and

fitting" and "valves." Therefore, the staff finds the applicant's response to RAI 2.3.3.18-1

acceptable and considers its concern described in RAI 2.3.3.18-1 resolved.

2.3.3.18.3 Conclusions

The staff reviewed LRA Section 2.3.3.18, the accompanying scoping boundary drawings, and

the applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. The staff did not identify any omissions. In

addition, the staff performed an independent assessment to determine whether any

components that should be subject to an AMR were not identified by the applicant. The staff

did not identify any omissions. On the basis of its review, the staff concludes that the applicant

has adequately identified the components of the TBCCW system that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the TBCCW system that are subject to an AMR, as required by 10

CFR 54.21 (a)(1).

2.3.3.19 Demineralizer Water Makeup System

2.3.3.19.1 Summary of Technical Information in the Application

The applicant described the demineralizer water makeup (DWM) system in LRA Section

2.3.3.19 and provided a list of components subject to an AMR in LRA Table 2.3.3-19.

The function of the DWM system is to provide reactor quality water for use in power plant

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systems, equipment, and service drops. Using the methodology described in LRA Section

2.1.4.1 for identifying the mechanical components within the scope of license renewal, the

applicant identified the following DWM system intended functions:

* primary containment isolation-provides containment isolation for those portions of the

system that interface with the primary containment

* isolation condenser alternate makeup water (Dresden)-provides alternate makeup water to

the isolation condenser.

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected (Dresden only)

The DWM system consists of all equipment required to transfer water from the well water

storage tank, through the makeup demineralizers, and into the various water storage tanks on

site. Well water flows from the well water transfer pumps (which are classified within the out-ofscope well water system for Quad Cities) through the makeup demineralizers, to either the

clean or contaminated demineralized water storage tank. Dresden has permanently installed

demineralizers, and both stations have portable demineralizers. The clean demineralized water

transfer pumps take suction from the clean demineralized water storage tank and supply clean

demineralized water through a distribution header to plant systems and equipment, such as

makeup to the standby liquid control system, the plant heating system, and the reactor building

and turbine building closed cooling water systems. The DWM system also supplies various

system loop seals, the Unit 1 fuel building (Dresden only), sample panels, and clean -

demineralized water service drops inside the primary containment and throughout the plant.

Containment isolation valves are provided for the clean demineralized water lines that penetrate

the containment. Additionally, at Dresden, the distribution header provides makeup water to the

isolation condenser and emergency makeup water to the fuel pools. Also, at Dresden, the

isolation condenser makeup pumps take suction from the clean demineralized water storage

tank and discharge into a common header that supplies the isolation condensers for both Units

2 and 3.

In LRA Section 2.3.3.19, the applicant described the DWM system evaluation boundary. In

addition, the applicant highlighted those portions of the DWM system within the scope of the

Rule in the P&l drawings listed as references in LRA Section 2.3.3.19. Also, based on the

methodology described in LRA Section 2.1.5 for identifying the rmechanical components subject

to an AMR, the applicant identified the component groups and their intended functions within

the DWM system in LRA Table 2.3.3-19 as being within the scope of license renewal and

subject to an AMR.

Resulting from the revised methodology described in the response to the draft SER Open Item

2.1-1, the applicant expanded the system boundaries for the DWM system at both Dresden and

Quad Cities due to the potential for spatial interaction with safety-related components.

Specifically, the applicant added associated piping components located in the Turbine Building

that could spatially interact with safety-related components in the same general area to the

scope of license renewal. Added piping components are shown on revised boundary diagrams

LR-DRE-M-177-1, LR-QDC-M-462-3, LR-DRE-M-419-1, LR-DRE-M-35-1, LR-DRE-M-366, LRDRE-M-269-3, LR-DRE-M-269-3, LR-QDC-M-58-1 LR-QDC-58-3 and new boundary diagrams

LR-QDC-M-31, LR-QDC-M-459-1, LR-QDC-M-459-3, LR-QDC-M-462-1, LR-DRE-M-177-3, LR2-169
DRE-M-419-3, LR-DRE-M-35-2, and LR-DRE-M-530-1. As results of these changes one new

component group was added to LRA Table 2.3.3-19 and additional aging management

references were added to two component groups.

The applicant identified the following component groups and their intended functions within the

DWM system in the revised LRA Table 2.3.3-19 as being within the scope of license renewal

and subject to an AMR:

* closure bolting (pressure boundary)

* flow elements (spatial interaction, Quad Cities only)

* non-safety-related vents or drains, piping, and valves (support integrity/attached support,

Quad Cities only)

* piping and fittings (pressure boundary)

* piping and fittings (spatial interaction)

* piping and fittings (support integrity/attached support)

* pumps (pressure boundary, Dresden only)

* pumps (spatial interaction, Quad Cities only)

* restricting orifices (pressure boundary, Dresden only)

* restricting orifices (spatial interaction, Quad Cities only)

* strainers (spatial interaction, Quad Cities only)

* tubing (spatial interaction, leakage boundary (spatial))

* valves (pressure boundary)

* valves (spatial interaction)

* valves (support integrity/attached support, Quad Cities only)

2.3.3.19.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.19, Dresden UFSAR Section 9.2.4, and Quad Cities

UFSAR Section 9.2.4 to determine whether there is reasonable assurance that the DWM

system components within the scope of license renewal and subject to an AMR have been

identified in accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's review was

conducted in accordance with Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the DWM system in the LRA.

Also, the staff selected system functions described in the UFSARs that were set forth in 10

CFR 54.4 to verify that components having intended functions were not omitted from the scope

of the Rule. The staff also focused on components that were not identified as being subject to

an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the DWM system that are within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21(a)(1), respectively, the staff compared the referenced P&I drawings to the system

drawings and system descriptions in the UFSARs to ensure that the referenced P&l drawings

were representative of the DWM system. The staff then reviewed the referenced P&l drawings

to verify that those portions of the DWM system that meet the scoping requirements of 10 CFR

54.4 are included within the scope of license renewal and are identified as such by the applicant

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in LRA Section 2.3.3.19, and that the applicant identified all DWM system components within

the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10

CFR 54.21(a)(1).

The staff's review of LRA Section 2.3.3.19 identified areas in which additional information is

necessary to complete the staff's review of the applicant's scoping results. Therefore, by the

August 4,2003, letter, the staff issued RAls to the applicant concerning the specific items to

determine whether the applicant has properly applied the scoping criteria of 10 CFR 54.4 and

the screening criteria of 10 CFR 54.21 (a)(1). The staff's scoping RAls and the applicant's

responses by letters, dated October 3, 2003, and January 26, 2004, are described below.

RAI 2.3.3.19-1. In LRA Section 2.3.3.19, the applicant stated that the demineralized water

makeup system distribution header provides emergency makeup to the spent fuel pool.

However, this function is not identified as an intended function in LRA Section 2.3.3.19.

Without knowing the basis for the applicant's determination that emergency spent fuel pool

makeup is not an intended function, the staff is unable to verify the acceptability of the

applicant's system scoping and screening results. Therefore, in RAI 2.3.3.19-1, the staff

requested the applicant to provide the basis for concluding that emergency spent fuel pool

makeup is not an intended function of the demineralized water makeup system according to the

criteria described in 10 CFR 54.4(b).

Applicant's Response and Staff's Evaluation

In its response to RAI 2.3.3.19-1, the applicant stated that the DMW system provides

emergency makeup water to the spent fuel pools, but this function is not a credited function in

the current licensing basis and, therefore, is not a license renewal intended function. In the

event of a complete loss of fuel pool cooling,:the fuel pool water temperature will begin to rise

and eventually will reach the boiling temperature, and the fuel pool water will boil off. However,

there will be sufficient time to establish makeup water to the fuel pool from various available

systems which include the condensate transfer system, the DMW system, and the fire water

systems. For these reasons, emergency spent fuel pool makeup is not an intended function of

the DMW system.

Based on its review, the staff finds that the DMW system is included within the scope of license

renewal in accordance with 10 CFR 54.4(a)(2). However, the capability of the DMW system to

provide emergency makeup water to the spent fuel pools is not credited in the current licensing

basis. The failure of the DMW system would not prevent other systems from satisfactorily

providing emergency makeup water to the spent fuel pools. Therefore, the staff agrees with the

applicant that providing emergency makeup water to the spent fuel pools is not an intended

function of the DMW system in accordance with 10 CFR 54.4. The staff finds the applicant's

response to RAI 2.3.3.19-1 acceptable and considers its concern described in RAI 2.3.3.19-1

resolved.

RAI 2.3.3.19-2. In RAI 2.3.3.19-2, the staff requested the applicant to provide information

concerning three symbols used on LR boundary diagrams referenced in LRA Section 2.3.3.19,

so that the staff could verify that the scoping and screening results in the LRA are consistent

with 10 CFR 54.4 and 10 CFR 54.21. The staff could not locate the three symbols on the

symbol legend submitted with the LRA.

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Applicant's Response and Staff's Evaluation

In its response, the applicant provided interpretation of four symbols used in the P&l drawings

referenced in LRA Section 2.3.3.19-one in drawing LR-DRE-M-366 (E-3), one in drawing LRQDC-M-58-4 (C-8), one in drawing LR-DRE-M-1239-3 (F-6), and one in drawing LR-QDC-M41-2 (E-2).

The staff finds that the interpretation of the symbols provided by the applicant clarifies the

staff's concerns described in RAI 2.3.3.19-2. The staff determined that no additional

component needed to be within the scope of license renewal. Therefore, the staff finds the

applicant's response to RAI 2.3.3.19-2 acceptable and considers its concern described in RAI

2.3.3.19-2 resolved.

RAI 2.3.3.19-3. In RAI 2.3.3.19-3, the staff requested the applicant to provide the basis for

concluding that an oil drain line for clean demineralized water pump 1/2-4303B is not within the

scope of license renewal in accordance with 10 CFR 54.4(a), as similar oil drain lines for the "A"

and "C" clean demineralized water pumps are considered to be within the scope of license

renewal. It was not apparent to the staff whether the exclusion of the oil drain line for the "B"

pump was justified or an oversight.

Applicant's Response and Staff's Evaluation

In its response to RAI 2.3.3.19-3, the applicant stated that the oil drain line for clean

demineralized water pump 1/2-4303B is in the scope of license renewal similar to oil drain lines

for the "A" and "C" clean demineralized water pumps. Boundary diagram LR-QDC-M-58-1

should have highlighted these components within the scope of license renewal. The subject

piping and valve components are subject to an AMR and are included in LRA Table 2.3.3-19

under component group, "piping and fittings (spatial interaction)," with leakage boundary

(spatial) intended function.

Based on its review of the applicant's clarification discussed above, the staff concurs with the

applicant's clarification that the above-cited oil drain line and its associated components are

within the scope of the Rule, and they were inadvertently not highlighted in the LR boundary

diagrams. Also, because the components associated with the cited oil drain line are included in

LRA Table 2.3.3-19, subject to an AMR, the staff finds the applicant's response to RAI 2.3.3.19-

3 acceptable. Therefore, the staff considers its concern described in RAI 2.3.3.19-3 resolved.

RAI 2.3.3.19-4. In RAI 2.3.3.19-4, the staff requested the applicant to provide the basis for

concluding that the demineralized water makeup system is capable of performing its intended

functions without relying upon the integrity of numerous unisolable piping lines and connected

components (the piping lines and components are listed in RAI 2.3.3.19-4), and that the failure

of these unisolable lines and connected components would not prevent other systems from

satisfactorily accomplishing their intended functions for license renewal. From the information

available in the LRA, it is not apparent to the staff why the unisolable components listed in RAI

2.3.3.19-4 are not required to be within the scope of license renewal, in accordance with

10 CFR 54.4(a), as a result of the above criteria.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.19-4 states the preferred makeup source to the isolation

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condenser is the dedicated diesel driven makeup pumps that take suction from the clean

demineralized water tank. The clean demineralized water system is designed to supply water

to multiple sources in parallel with the isolation condenser diesel driven makeup pump.'For this

reason, leakage in any of the branch connections described in the RAI would not prevent this'

preferred path from fulfilling its function.

The demineralized water makeup system provides an alternate supply of makeup water to the

Isolation Condenser shell from the clean demineralized water storage tank; Therefore the

portion of the demineralized water makeup system in the flow path to the Isolation'Condenser

shell, including the clean demineralized water pumps, piping, associated valves, and

instrumentation are included within the scope of license renewal. When establishing the inscope boundary of the demineralized water makeup system for license renewal, credit was

allowed for operator action to close accessible, normally open, manual isolation valves.

The branch connections on the demineralized water piping system that are not included within

the scope of license renewal are located within the'power block (turbine building, reactor

building, radwaste) where detection in the event of failure would be detected. In the event of a

significant demineralized water line break, operators would receive a control room low pressure

alarm for the clean demineralized water header. Site operating procedure, DAN 923-1 C-6,

Clean Demon. Water Pp Trip/Press Lo, directs operators to check for excessive use of clean

demineralized water and to troubleshoot as needed. Operators would also detect any abnormal

increase of input to plant sumps that are monitored continuously by operators in the radwaste

control room. Individual sump inputs are monitored which would assist operations personnel in'

locating the area of any clean demineralized water line break. Operators would respond to

these indications of plant leakage and take appropriate actions to isolate the leakage.

Those portions of the clean demineralized water system that can spatially interact with safetyrelated equipment were included during previous system scoping efforts: A'pipe break and/or

leak from remaining portions of the clean demineralized piping that are not in scope can not

spatially affect safety--related components.

The valves listed below were added to the scope of license renewal and will be managed for

aging. Operator closure of these valves would isolate a failure in the out of scope portions of

the system located downstream and re-establish the demineralized water system pressure

boundary and makeup flow path to the isolation condenser. This action eliminates the need for

placing the downstream components within the scope of license renewal.

2-4303-500 2-4399-792 3-4399-711

2-4308-500 3-4399-706 3-4305-500

2-4308-501 3-4399-707 2/3-5799-1113

2-4309-500 3-4399-708 2/3-5799-1115

2-4399-730 3-4399-709 2/3-4311-500

2-4399-732 3-4399-710 2/3-4399-67

In addition, the following valves will be added to the scope of license renewal: check valve 2/3-

4300-852 (This valve isolates the branch connection on LR-DRE-M-35-1, grid location D-7,

from drawing M-101 1-2) and the unnumbered vent valve in line 2-4386-1"-L at grid location D-4

on LR-DRE-M-35-1.

Based on its review of the applicant's clarification discussed above, the staff concurs with the

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applicant's clarification that the operators will be able to identify system failure and close the

appropriate valve before the DMW system becomes unable to perform its intended function of

providing an alternate supply of makeup water to the Isolation Condenser shell. The applicant

also included the above-mentioned valve within scope of License Renewal and subject to AMR.

The Clean Demineralized Water Storage Tank (CDWST) has a capacity of 200,000 gallons and

the DMW system was designed to supply water to multiple systems. A failure of the system

sections downstream of these manual valves would be identified by several means before the

CDWST inventory drops to levels that would prevent the DMW system from performing its

intended function of providing an alternate supply of makeup water to the Isolation Condenser

shell. The applicant also has in place procedures the will direct the operator to check the

above-mentioned system sections for possible leakage. Therefore, the staff considers its

concern described in RAI 2.3.3.19-4 resolved.

2.3.3.19.3 Conclusions

The staff reviewed LRA Section 2.3.3.19, the accompanying scoping boundary drawings, and

the applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal were not identified by the applicant. In addition, the staff performed an independent

assessment to determine whether any components that should be subject to an AMR were not

identified by the applicant. The staff did not identify any omissions. On the basis of its review,

the staff concludes that the applicant has adequately identified the components of the DMW

makeup system that are within the scope of license renewal, as required by 10 CFR 54.4(a),

and that the applicant has adequately identified the components of the DMW makeup system

that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.20 Residual Heat Removal Service Water System (Quad Cities Only)

2.3.3.20.1 Summary of Technical Information in the Application

The applicant described the residual heat removal service water (RHRSW) system in LRA

Section 2.3.3.20 and provided a list of components subject to an AMR in LRA Table 2.3.3-20.

The function of the RHRSW system is to-remove heat from the suppression chamber, in

conjunction with the containment cooling mode of the residual heat removal system; remove

heat from the reactor coolant, in conjunction with the shutdown cooling mode of the residual

heat removal system; provide a safety-related source of cooling water to the train "B" control

room HVAC refrigerant condensing unit as a backup during a loss of offsite power; provide a

cross-tie to the opposite unit to achieve safe shutdown for fire events in accordance with

Appendix R to 10 CFR Part 50; and provide an auxiliary function during refueling by assisting in

the removal of heat from the spent fuel pool.

Using the methodology described in LRA Section 2.1.4.1 for identifying the mechanical

components within the scope of license renewal, the applicant identified the following RHRSW

system intended functions:

* containment and component cooling-provides a heat sink for the RHR system via the RHR

heat exchangers to support containment cooling after a LOCA

* back-up cooling-provides safety-related back-up cooling to the "B" train of the control room

HVAC refrigeration units as a backup during a loss of offsite power and LOCA

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* credited in regulated event(s)-provides a heat sink for the RHR system via the RHR heat

exchangers to support ATWS actions and in the Appendix R fire safe shutdown analysis

(The subsystems between the units can be connected by a normally isolated crosstie line

that is credited in the plant's fire protection safe shutdown analysis. The system also

contains components that are relied upon for compliance with 10 CFR Part 50.49 (EQ).)

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected

The RHRSW system is an open-loop cooling water system consisting of four two-stage pump

sets (i.e., two pumps driven by a single motor), associated valves, piping, and instrumentation

and controls, divided into two independent loops. The RHRSW system removes heat from the

RHR heat exchangers, which are evaluated as part of the RHRSW system. During RHRSW

system operation, the pressure on the tube side of the RHR heat exchanger is maintained

above the shell side to prevent reactor water leakage into the SW and thereby into the

discharge bay.

In LRA Section 2.3.3.20, the applicant described the RHRSW system evaluation boundary. In

addition, the applicant highlighted those portions of the RHRSW system within the scope of the

Rule in the P&l drawings listed as references in LRA Section 2.3.3.20. Also, based on the

methodology described in LRA Section 2.1.5 for identifying the mechanical components subject

to an AMR, the applicant identified the component groups and their intended functions within

the RHRSW system in LRA Table 2.3.3-20 as being within the scope of license renewal and

subject to an AMR.

Resulting from the revised methodology described in the May 18, 2004 response to the draft

SER Open Item 2.1-1, the applicant expanded the system boundaries for the RHRSW system

at Quad Cities due to the potential for spatial interaction with safety-related components. The

applicant included all of the components shown on new boundary diagrams LR-QDC-M-22-2

and LR-QDC-M-69-2 to the scope of license renewal. As results of these changes two new

component groups were added to LRA Table 2.3.3-20.

The applicant identified the following component groups and their intended functions within the

RHRSW system in the revised LRA Table 2.3.3-20 as being within the scope of license renewal

and subject to an AMR:

* auxiliary and RW HVAC air handlers heating/cooling (pressure boundary)

* auxiliary and RW HVAC air handlers heating/cooling (heat transfer)

* closure bolting (pressure boundary)

* dampeners (pressure boundary)

* ducts and fittings, access doors, closure bolts, and equipment frames (pressure boundary)

* heat exchangers (pressure boundary)

* heat exchangers (heat transfer)

* non-safety-related vents or drains, piping, and valves (structural integrity/attached support)

* NSR Vents or Drains, Piping and Valves (spatial interaction) (Quad Cities only)

* orifice bodies (pressure boundary)

* orifice bodies (throttle)

* piping and fittings (structural integrity/attached support)

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* pulsation dampeners (pressure boundary)

* pumps (pressure boundary)

* pumps (spatial interaction) (Quad Cities only)

* sight glasses

* strainer bodies (pressure boundary)

* strainer screens

* thermnowells (pressure boundary)

* tubing (pressure boundary)

* tubing (structural integrity/attached support)

* valves (pressure boundary)

* valves (structural integrity/attached support))

2.3.3.20.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.20 and Quad Cities USAR Sections 3.4.1.2, 5.4.7, 6.2.2,

6.3, 9.1.3.2, 9.2.1, and 9.2.5 to determine whether there is reasonable assurance that the

RHRSW system components within the scope of license renewal and subject to an AMR have

been identified in accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's review

was conducted in accordance with Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSAR to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the RHRSW system in the LRA. The staff did not identify any

omissions.

Also, the staff selected system functions described in the UFSAR that were set forth in 10 CFR

54.4 to verify that components having intended functions were not omitted from the scope of

the Rule. The staff also focused on components that were not identified as being subject to an

AMR to determine if any components were omitted.

To verify that the applicant identified the components of the RHRSW system that are within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21(a)(1), respectively, the staff compared the referenced P&l drawings to the system

drawings and system descriptions in the UFSAR to ensure that the referenced P&l drawings

were representative of the RHRSW system. The staff then reviewed the referenced P&l

drawings to verify that those portions of the RHRSW system that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal and are identified

as such by the applicant in LRA Section 2.3.3.20, and that the applicant identified all RHRSW

system components within the scope of license renewal and subject to an AMR in accordance

with 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.20 identified areas in which additional information is

necessary to complete the staff's review of the applicant's scoping and screening results.

Therefore, by the August 4, 2003, letter, the staff issued RAls to the applicant concerning the

specific items needed to determine whether the applicant has properly applied the scoping and

screening criteria of 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's RAIs and the applicant's

responses by letter, dated October 3, 2003, are described below.

RAI 2.3.3.20-1. In RAI 2.3.3.20-1, the NRC staff requested the applicant to provide the basis

for concluding that the LR scoping criteria of 10 CFR 54.4(a) do not require all piping and

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associated components necessary to discharge the flow of RHRSW returning from the control

room HVAC refrigerant condensing unit to be within the scope of license renewal. From the

associated LR boundary diagrams, it appears to the staff that the applicant only considered the

portion of the discharge flowpath upstream of locked-open valve 0-5799-388 to be within scope.

Applicant's Response and Staff's Evaluation

In its response to RAI 2.3.3.20-1, the applicant stated that the associated flow path cited above

is required for the performance of the control room HVAC refrigeration condensing unit, and the

components and piping sections are in the scope of license renewal. The subject line wasinadvertently left out of scope on the boundary diagram. The boundary diagram should have

included the path (up to and including valves required to maintain the path) in the scope of

license renewal. The following existing boundary diagrams should have also reflected the

components in the flow path in the scope of license renewal-LR-QDC-M-22-1, Service Water

Piping; LR-QDC-M-22-3, Service Water Piping-Diesel Generator Cooling Water; LR-QDC-M22-5, Service Water Piping; and LR-QDC-M-725-3, Control Room HVAC.

The components and piping sections discussed above and their intended functions are included

in LRA Table 2.3.3-20 under component groups "piping and fittings," "valves," and "orifice

bodies," as being within the scope of license renewal and subject to an AMR.

Based on its review, the staff finds that the applicant has clarified that the subject components

and piping are within the scope of the Rule and subject to an AMR. These components and

piping were inadvertently not highlighted in the LR boundary diagrams, however, they are

included in LRA Table 2.3.3-20, subject to an AMR. Therefore, the staff finds the applicant's

response to RAI 2.3.3.20-1 acceptable and considers its concern described in RAI 2.3.3.20-1

resolved.

RAI 2.3.3.20-2. In RAI 2.3.3.20-2, the NRC staff requested that the applicant provide the basis

for concluding that a temperature element connected to the outlet line 2-1043A-14"-L from the

residual heat removal heat exchanger 2-1003A is not within the scope of license renewal

according to 10 CFR 54.4(a). The applicant's treatment of this temperature element contrasts

with the treatment of similar temperature elements connected to in-scope piping on the

associated LR boundary diagram (LR-QDC-M-79). Therefore, the staff requested that the

applicant provide additional information to verify that the scoping criteria of 10 CFR 54.4(a) are

satisfied.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.3.20-2, the applicant stated that the subject instrument was

inadvertently not highlighted on the boundary diagram. Boundary diagram LR-QDC-M-79

should have highlighted the temperature element and associated tap (thermowell) in the scope

of the Rule. However,. the temperature element, which is not part of the pressure boundary, is

an active component and does not require an aging management. The tap is subject to an

AMR and is included in LRA Table 2.3.3-20 under component group "piping and fittings."

Based on its review, the staff finds the applicant's response to RAI 2.3.3.20-2 acceptable. The

staff concurs with the applicant's clarification that the temperature element and associated tap

are in scope of the scope of the Rule, the temperature element is not subject to an AMR

because it is an active component, the associated tap is included in LRA Table 2.3.3-20 subject

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to an AMR, and the temperature element and associated tap were inadvertently not highlighted

in the LR boundary diagram. Therefore, the staff considers its concern described in RAI

2.3.3.20-2 resolved.

RAI 2.3.3.20-3. In RAI 2.3.3.20-3, the NRC staff requested that the applicant explain apparent

scoping inconsistencies regarding four corrosion coupon holders on two LR boundary diagrams

(LR-QDC-M-37 and LR-QDC-M-79). All coupon holders except one show the connecting piping

and valves to be within the scope of license renewal. Also, for only one of the coupon holders

is the holder itself shown as being within the scope of license renewal. The staff requested that

the applicant explain these two apparent inconsistencies so that the staff could verify whether

or not the applicant's scoping results are consistent with 10 CFR 54.4(a). The staff could also

not determine whether the applicant had included the coupon holders in the AMR results listed

in LRA Table 2.3.3-20.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.3.20-3, the applicant stated that the coupon holder (1-1005B) and

associated isolation valve (1-1099-36B) located at C-8 on boundary diagram LR-QDC-M-37,

and coupon holders (2-1005A and 2-1005B) located at C-3 and C-8 on boundary diagram LRQDC-M-79 are in scope of license renewal but were inadvertently not highlighted in the

boundary diagrams. The coupon holder (1-1005A) located at B-3 on LR-QDC-37 is

appropriately identified on the boundary diagram as in scope of license renewal. The applicant

further stated that LRA Table 2.3.3-20 includes the above-listed components under component

groups 'piping and fittings," and "valves."

Based on its review, the staff finds that the applicant has clarified that the four corrosion coupon

holders and associated isolation valves are within the scope of license renewal and are included

in LRA Table 2.3.3-20, subject to an AMR. These components were inadvertently not

highlighted in the flow diagram, however, they are included in LRA Table 2.3.3-20 subject to an

AMR. Therefore, the staff finds the applicant's response to RAI 2.3.3.20-3 acceptable and

considers its concerns described in RAI 2.3.3.20-3 resolved.

RAI 2.3.3.20-4. In RAI 2.3.3.20-4, the NRC staff requested that the applicant provide the basis

for concluding that a segment of piping (1-1011 1C-1"-D) that is connected to in-scope piping

line 1-1003C-1 2"-D is not within the scope of license renewal in accordance with

10 CFR 54.4(a). The applicant's scoping classification for this segment of piping contrasts with

the treatment of similar segments of piping on the associated LR boundary diagram

(LR-QDC-M-37). As a result of the apparent inconsistency, it is not clear to the staff that the

criteria of 10 CFR 54.4(a) are satisfied.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.3.20-4, the applicant stated that boundary diagram LR-QDC-M-37

should have been highlighted to include the line (and pipe cap) in the scope of license renewal.

This line is in scope for license renewal but was inadvertently not highlighted in the LR

boundary diagram. The applicant further stated that LRA Table 2.3.3-20 includes the abovecited line under component group "piping and fittings."

Based on its review, the staff finds that the applicant has clarified that the subject segment of

piping was within the scope of license renewal and subject to an AMR. The subject segment of

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piping was inadvertently not highlighted in the flow diagram, however, it isiincluded in LRA

Table 2.3.3-20, subject to an AMR. Therefore, the staff finds the applicant's response to RAI

2.3.3.204 acceptable and considers its concerns described in RAI 2.3.3.20-4 resolved.

RAI 2.3.3.20-5. In RAI 2.3.3.20-5, the NRC staff requested that the applicant provide the basis

for not including flow elements as an eritry in LRA Table 2.3.3-20 (which contains the AMR'

results for the RHRSW system) to verify that the criteria set forth in 10 CFR 54.21 (a)(1) have

been satisfied. License renewal boundary diagrams associated with the RHRSW system depict'

flow elements within this system as being within the scope of license renewal; however, they'

are not included in the RHRSW AMR results table,'as is done in the AMR results tables for

various other systems in the LRA (e.g., DWM system and CCSW system).

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.3.20-5, the applicant stated that LRA Tables 2.3.3-20, 2.3.3-19, and

2.3.3-21 identify the component groups requiring AMR for the RHRSW, DWM,' and CCSW

systems, respectively. The component groups'identified in these tables were derived from

component types identified in each site's component maintenance database (Passport). The

designation of these database component types was not uniformly provided at the two sites.

Consequently, the database included component type designations corresponding to "flow

elements," "restricting orifices," and "orifice bodies," interchangeably to represent orifice bodies.

Similarly, the component groups "flow elements," "restricting orifices," and "orifice bodies," as

identified in the cited Chapter 2 tables, describe orifice bodies serving pressure/leakage

boundary or throttle functions.

The subject flow elements 2-1041-A, 2-1041-B, 1-1041-A, and 1-1041-B are depicted at the

cited locations on boundary diagrams LR-QDC-M-79 and LR-QDC-M-37. LRA Table 2.3.3-20

includes entries for orifice bodies with component intended functions of uPressure Boundary"

and "Throttle" to address these flow elements."

Based on its review, the staff finds the applicant's response to RAI 2.3.3.20-5 acceptable '

because the applicant has explained that the components identified in RAI 2.3.3.20-5 were

given different type of identification at the two sites, but are already within the scope of license

renewal and are included in LRA Table 2.3.3-20, subject to an AMR. Therefore, the staff

considers its concern described in RAI 2.3.3.20-5 resolved.

2.3.3.20.3 Conclusions

The staff reviewed LRA Section 2.3.3.20, the accompanying scoping boundary drawings, and

the applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal were not identified by the applicant. In addition, the staff performed an independent

assessment to determine whether any components that should be subject to an AMR were not

identified by the applicant. The staff did not identify any omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the components of the'RHRSW system that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and that the applicant has adequately identified the components

of the RHRSW system that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.3.21 Containment Cooling Service Water System (Dresden Only)

2.3.3.21.1 Summary of Technical Information in the Application

The applicant described the containment cooling service water (CCSW) system in LRA Section

2.3.3.21 and provided a list of components subject to an AMR in LRA Table 2.3.3-21.

The function of the CCSW system is to remove heat from the primary containment by providing

cooling water to the LPCI heat exchangers. Also, the CCSW system, in conjunction with LPCI,

limits the suppression chamber bulk water temperature to provide assurance that-suppression

chamber hydrodynamic loads during blowdown would not adversely impact the integrity of

structures and equipment; complete steam condensation occurs during a LOCA to limit longterm primary containment pressure; and adequate NPSH exists for ECCS pumps to maintain

long-term primary containment pressure control. The Unit 2 CCSW loops provide a safetyrelated source of SW to the control room air conditioning condensers. The CCSW system also

supplies a safety-related source of river water to the LPCI and HPCI room coolers (evaluated

with the ECR-HVAC) as a backup to the SW system. The CCSW is credited for certain

regulated events, as per the definition in 10 CFR 54.4(a)(3), which include-providing

redundancy in suppression chamber cooling during an ATWS event; operating with reliance

upon external source of power for an SBO event; mitigating fire events, in accordance with

Appendix R to 10 CFR Part 50; and containing system components that are relied upon for

compliance with environmental qualification requirements in 10 CFR 50.49.

Using the methodology described in LRA Section 2.1.4.1 for identifying the mechanical

components within the scope of license renewal, the applicant identified the following CCSW

system intended functions:

* containment and component cooling-provides containment cooling function, cooling to the

ECCS room coolers, and the CCSW water vault coolers to maintain room temperatures

* back-up cooling (Dresden Unit 2 only)-CCSW provides safety-related back-up cooling to

the 'B1 train of the control room HVAC refrigeration units

* credited in regulated event(s-provides redundancy in suppression chamber cooling during

an ATWS event, operates without reliance upon external sources of power (SBO), is

credited in the Appendix R fire safe shutdown analysis, and the system contains

components that are relied upon for compliance with 10 CFR Part 50.49 (EQ)

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected.

The CCSW system is an open-loop cooling water system consisting of four pumps, associated

valves, piping, and instrumentation and controls. The CCSW system removes heat from the

LPCI heat exchangers, which are evaluated as part of the CCSW system. The CCSW pumps

develop sufficient head to maintain the cooling water heat exchanger tube side outlet pressure

greater than the LPCI subsystem pressure on the shell side. Maintaining this pressure

differential prevents reactor water leakage into the SW and thereby into the river.

In LRA Section 2.3.3.21, the applicant described the CCSW system evaluation boundary. In

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addition, the applicant highlighted those portions of the CCSW systemn within the scope of the

Rule in the P&l drawings listed as references in LRA Section 2.3.3.21. Also, based on the

methodology described in LRA Section 2.1.5 for identifying the mechanical components subject

to an AMR, the applicant identified the following component groups and their intended functions"

within the RHRSW system in LRA Table 2.3.3-21 as being within the scope of license renewal'

and subject to an AMR:

* auxiliary and RW HVAC air handlers heating/cooling (pressure boundary)

* auxiliary and RW HVAC air handlers heating/cooling (heat transfer)

* closure bolting (pressure boundary)

* ducts and fittings, access doors,' closure bolts, and equipment frames (pressure boundary)

* flow elements (pressure boundary)

* heat exchangers (pressure boundary)

* heat exchangers (heat transfer)

* orifice bodies, including manifolds, tubes, and thermowells (pressure boundary)

* piping and fittings (structural integrity/attached support)

* pumps (pressure boundary)

* strainer bodies (pressure boundary)

* strainer screens (filter)

* thermowells (pressure boundary)

* tubing (pressure boundary)

* valves (pressure boundary)

* valves (structural integrity/attached support)

2.3.3.21.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.21 and Dresden UFSAR Sections 3.4.1.2, 6.2.2, 6.3.1.2,

6.4, and 9.2.1 to determine whether there is reasonable assurance that the CCSW system

components within the scope of license renewal and subject to an AMR have been identified in

accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's review was conducted in

accordance with Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSAR to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the CCSW system in the LRA.

Also, the staff selected system functions described in the UFSAR that were set forth in .10 CFR

54.4 to verify that components having intended functions were not omitted from the scope of

the Rule. The staff also focused on components that were not identified as being subject to an

AMR to determine if any components were omitted. -

To verify that the applicant identified the components of the CCSW system that are within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the system

drawings and system descriptions in the UFSARs to ensure that the referenced P&l drawings

were representative of the CCSW system.' The staff then reviewed the referenced P&l

drawings to verify that those portions of the CCSW system that meet the scoping requirements

of 10 CFR 54.4 are included within the scope of license renewal and are identified as such by

the applicant in LRA Section 2.3.3.21, and that the applicant identified all CCSW system

components within the scope of license renewal and subject to an AMR in accordance with 10

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CFR 54.4 and 10 CFR 54.21(a)(1).

The staff's review of the LRA identified areas in which additional information is necessary to

complete the staff's review of the applicant's scoping and screening results. Therefore, by the

August 4, 2003, letter, the staff issued RAIs to the applicant concerning the specific items

needed to determine whether the applicant has properly applied the scoping and screening

criteria of 10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff's RAIs and the applicant's

responses by letter, dated October 3, 2003, are described below.

RAI 2.3.3.21-1. In RAI 2.3.3.21 -1, the staff requested the applicant to provide the basis for

apparent scoping discrepancies on the referenced P&l drawings, LR-DRE-M-29-2 (Unit 2) and

LR-DRE-M-360-2 (Unit 3). Specifically, differences in the marking of pressure indicators and

flow transmitters on these boundary diagrams indicate that corresponding components at Units

2 and 3 have been brought within the scope of license renewal for different reasons. The staff

requested this information to ensure that the applicant has correctly identified the system

intended functions for license renewal, as defined by 10 CFR 54.4(b), and the in-scope

components, in accordance with 10 CFR 54.4(a).

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.21-1 states that the subject instruments and associated

upstream non-safety-related piping are in scope of license renewal because they meet the

requirements of 10 CFR 54.4(a)(2) regarding non-safety-related components attached to

safety-related components. Boundary diagrams LR-DRE-M-29-2 and LR-DRE-360-2 should

have highlighted these components in red, which indicates in scope components in accordance

with 10 CFR 54.4(a)(2) for non-safety-related components and systems.

Based on its review of the applicant's clarification discussed above, the staff finds that the

subject instruments and associated upstream non-safety-related piping were in scope for

license renewal. They were inadvertently not highlighted in the LR boundary diagram.

However, the subject components are included in LRA Table 2.3.3-21, subject to an AMR.

Therefore, the staff considers its concern described in RAI 2.3.3.21-1 resolved.

RAI 2.3.3.21-2. In RAI 2.3.3.21-2, the staff requested the applicant to provide the basis for

concluding that an unisolable segment of piping (and associated components) connected to inscope piping line 3-15112-3"-H (see boundary diagram LR-DRE-M-360-2, location A-5) is not

within the scope of license renewal according to 10 CFR 54.4(a). The staff could not determine

why the unisolable piping segment and associated components (up to the first isolation valve)

are not necessary for the CCSW system to perform its intended functions. Therefore, the staff

requested that the applicant provide additional information to verify that the scoping criteria of

10 CFR 54.4(a) are satisfied.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.21-2 states that boundary diagram LR-DRE-360-2 should

have highlighted the pipe segment cited above in green to designate that the components are

in the scope of license renewal. This segment and associated components are included in LRA

Table 2.3.3-21 under component group "piping and fittings, including manifolds, tubes, and

thermowells" subject to an AMR.

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Based on its review of the applicant's clarification discussed above, the staff concurs with the

applicant's clarification that the above-cited segments of piping and their associated

components are within the scope of the Rule. They were inadvertently not highlighted in the LR

boundary diagram. However, the components associated with the cited segments of piping are

included in LRA Table 2.3.3-21, subject to an AMR. Therefore, the staff finds the applicant's

response to RAI 2.3.3.21-2 acceptable and considers its concern described in RAI 2.3.3.21-2

resolved.

RAI 2.3.3.21-3. In RAI 2.3.3.21-3, the staff -requested the applicant to provide the basis for

concluding that the CCSW system is capable of performing its intended functions without

relying upon the integrity of three unisolable piping lines and associated components (the piping

lines 2/3-3936-3"-0, 2/3-3921-6"-0, and 2/3-3915-16'-O shown in boundary diagram LR-DRE-M22), and that the failure of these unisolable lines and associated components would not prevent

other systems from satisfactorily accomplishing their intended functions for license renewal.

The unisolable piping lines are connected to the CCSW return line from the control room air

conditioning condensers, upstream of its termination at a standpipe, which eventually - -

discharges to the circulating water discharge header. From the information available in the

LRA, it is not apparent to the staff why the unisolable piping and associated components

referenced in RAI 2.3.3.21-3 are not required to be within the scope of license renewal, in

accordance with 10 CFR 54.4(a), as a result of the above criteria.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.21-3 states that boundary diagram LR-DRE-M-22 should

have highlighted the pipe segment cited above in green to designate that the components are

in the scope of license renewal. This segment and associated components are included in LRA

Table 2.3.3-21 under component groups "piping and fittings," "valves," and uorif ice bodies,"

subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.21-3 acceptable. The

applicant clarified that the subject components are within the scope of the Rule and subject to

an AMR, and they were inadvertently not highlighted in the LR boundary diagram. However,

the subject components are included in LRA Table 2.3.3-21, subject to an AMR. Therefore, the

staff considers its concern described in RAI 2.3.3.21-3 resolved.

2.3.3.21.3 Conclusions

The staff reviewed LRA Section, the accompanying scoping boundary drawings, and the

applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. In addition, the staff performed an

independent assessment to determine whether any components that should be subject to an

AMR were not identified by the applicant. The staff did not identify any omissions. On the

basis of its review, the staff concludes that the applicant has adequately identified the

components of the CCSW system that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant has adequately identified the components of the CCSW

system that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

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2.3.3.22 Ultimate Heat Sink System

2.3.3.22.1 Summary of Technical Information in the Application

The applicant described the ultimate heat sink (UHS) system in LRA Section 2.3.3.22 and

provided a list of components subject to an AMR in LRA Table 2.3.3-22.

The function of the UHS system is to provide sufficient cooling water to the station, when the

normal heat sink is unavailable, to permit operation of the CCSW system at Dresden, the

RHRSW at Quad Cities, and the DGCW pumps at both stations. Using the methodology

described in LRA Section 2.1.4.1 for identifying the mechanical components within the scope of

license renewal, the applicant identified the following CCSW system intended functions:

* ultimate cooling water supply-provides sufficient cooling water to the station to permit

operation of the CCSW system and the DGCW pumps when the normal heat sink (the river)

is unavailable (Dresden)

* ultimate cooling water supply-provides sufficient cooling water to the station to permit

operation of the residual heat removal SW pumps and the diesel generator cooling water

pumps when the normal heat sink (the river) is unavailable (Quad Cities)

At Dresden, the Kankakee River is the normal source of emergency cooling water. If the

Dresden Island Lock and Dam on the Illinois River were to fail, the Kankakee River level would

fall below the high point of the Dresden intake flume. At Quad Cities, the Mississippi River is

the normal source of emergency cooling water. If Lock and Dam No. 14 on the Mississippi

River were to fail, the Mississippi River level would fall below the high point of the Quad Cities

intake flume. For both stations, the design of the UHS would trap a limited supply of water in

the intake and discharge canals in the event of the loss of the dammed water.

The applicant states that, at Dresden, the natural topography forms the UHS basin with the

level stabilizing at elevation 495'-O", the high point of the intake flume. The CCSW pumps take

suction from the center compartment of the crib house at elevation 498'-0", above the UHS

basin level. To provide adequate suction for the CCSW pumps necessitates isolating the

center compartment and raising its water level. Isolation is accomplished by replacing the

normal wire mesh screens in the center compartment openings with stop logs. The dewatering

valves are opened to allow water from the crib house forebay to flood the trash rake refuge pit,

the refuge pumps are lined up to discharge to the center compartment, and the pumps are

operated to flood the compartment above the CCSW pump suction. A CCSW pump (evaluated

with the CCSW system) is placed in service, discharging to the containment cooling heat

exchanger, and then to the discharge canal. The deicing valve is opened, allowing flow from

the discharge canal back to the forebay. A portable, low-head, high-volume, engine-driven

pump could make up the loss of the impounded river water due to evaporation.

The applicant states that, at Quad Cities, the natural topography of the intake flume, along with

the weir gate located in the discharge canal, forms the UHS basin. The level in the basin

stabilizes at elevation 565'-0m, the high point of the intake flume. The RHRSW (evaluated with

the RHRSW system and DGCW (evaluated with the DGSW system) take suction from the

center compartment of the crib house at elevation 556'-64, below the UHS basin level. The

pumps discharge to their assigned loads, and then to the discharge flume upstream of the weir.

The gate on the ice-melt line is opened, allowing flow from the discharge flume back to the

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intake flume. The water impounded in the intake and discharge flumes is then used as an

evaporative heat sink. With the loss of Dam No. 14 on the Mississippi River, river water would

backflow through the 16-foot diameter discharge piping connecting the river to the discharge

flume, to the downstream base of the weir gate. Portable diesel-driven pumps take suction

from downstream of the weir and discharge into the center compartment of the crib house to

make up the loss of the impounded river water due to evaporation.

In LRA Section 2.3.3.22, the applicant described the UHS system evaluation boundary. In

addition, the applicant highlighted those portions of the UHS system within the scope of the

Rule in the P&l drawings listed as references in LRA Section 2.3.3.22. Also, based on the

methodology described in LRA Section 2.1.5 for identifying the mechanical components subject

to an AMR, the applicant identified the following component groups and their intended functions

within the UHS system in LRA Table 2.3.3-22 as being within the scope of license renewal and

subject to an AMR:

* closure bolting (pressure boundary, Dresden only)

* piping and fittings (pressure boundary)

* pump casings (pressure boundary, Dresden only)

* valves (pressure boundary)

* stop logs (pressure boundary)-stop logs were initially inadvertently left out of the table.

2.3.3.22.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.22, Dresden UFSAR Sections 9.2.5 and 2.4, and Quad

Cities UFSAR Sections 9.2.5 and 2.4 to determine whether there is reasonable assurance that

the UHS system components within the scope of license renewal and subject to an AMR have

been identified in accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's review

was conducted in accordance with Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the UHS system in the LRA. The staff did not identify any omissions.

Also, the staff selected system functions described in the UFSARs that were set forth in 10

CFR 54.4 to verify that components having intended functions were not omitted from the scope

of the Rule. The staff also focused on components that were not identified as being subject to

an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the UHS system that are within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the system

drawings and system descriptions in the UFSARs to ensure that the referenced P&l drawings

were representative of the UHS system. The staff then reviewed the referenced P&l drawings

to verify that those portions of the UHS system that meet the scoping requirements of 10 CFR

54.4 are included within the scope of license renewal and are identified as such by the applicant'

in LRA Section 2.3.3.22, and that the applicant identified all UHS system components within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1).

The staff's review of the LRA identified areas in which additional information is necessary to

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complete the staff's review of the applicant's scoping and screening results. Therefore, by the

August 4, 2003, letter, the staff issued RAls to the applicant concerning the specific items to

determine whether the applicant has properly applied the scoping and screening criteria of

10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff's RAls and the applicant's responses by letter,

dated October 3, 2003, are described below.

RAI 2.3.3.22-1. In RAI 2.3.3.22-1, the staff requested the applicant to state whether the icemelt gates, described in LRA Section 2.3.3.22 as necessary components to support UHS

system intended function for Dresden and Quad Cities, are within the scope of license renewal

in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with

10 CFR 54.21(a)(1). The staff further requested the applicant to provide justification if the icemelt gates are not considered within the scope of license renewal and subject to an AMR. The

basis for the staff's RAI is that the ice-melt gates are not clearly identifiable to the staff in LRA

Table 2.3.3-22, which provides the AMR results for the UHS system.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.22-1 states that the ice-melt gates are included in LRA

Table 2.3.3-22, under the component group "valves." Additionally, the "Dresden only"

description should have been deleted from LRA Table 2.3.3-22 as shown below.

Table 2.3.3-22: Component Groups Requiring Aging Management Review-Ultimate Heat

Sink

I Component Group lComponent Intended Function Aging Management Ref

Valves Pressure Boundary 3.3.2.278. 3.3.2.300

Based on its review, the staff finds the applicant's response to RAI 2.3.3.22-1 acceptable. The

applicant acknowledges that the ice-melt gates are within the scope of the Rule and subject to

an AMR, and that the ice-melt gates are included in LRA Table 2.3.3-22, subject to an AMR.

Therefore, the staff considers its concern described in RAI 2.3.3.22-1 resolved.

RAI 2.3.3.22-2. In RAI 2.3.3.22-2, the staff requested the applicant to state whether stop logs

are within the scope of license renewal in accordance with 10 CFR 54.4(a) and subject to an

AMR in accordance with 10 CFR 54.21(a)(1), for Dresden. In LRA Section 2.3.3.22, the

applicant indicates that, for Dresden, stop logs are necessary to isolate the center compartment

of the crib house to allow the suction of the CCSW pumps to be flooded. Thus, stop logs

appear to perform a pressure-boundary intended function for license renewal. However, in LRA

Table 2.3.3-22, which contains the AMR results for the UHS system, the staff could not

definitively locate an entry for stop logs. Therefore, the staff requested the applicant to provide

additional information to verify that 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1) are satisfied.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.22-2 states that the stop logs are needed to support the

Ultimate Heat Sink and should have been added to Table 2.3.3-22 and Table 3.3-2 as shown

below.

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Table 2.3.3-22 Component Groups Requiring Aging Management Review-Ultimate Heat

Sink

Icomponent Group I Component Intended Function I Aging Management Ref

top Logs (Dresden only IStructural Pressure Barrier 1.3.2.304

Based on its review, the staff finds the applicant's'response to RAI 2.3.3.22-2 acceptable

because the applicant stated that the stop logs should have been added to Table 2.3.3-22 and

Table 3.3-2 subject to an AMR and AMP. Therefore, the staff considers its concern described

in RAI 2.3.3.22-2 resolved.

2.3.3.22.3 Conclusions

The staff reviewed LRA Section 2.3.3.22, the accompanying scoping boundary drawings, and

the applicant's response to RAls, to determine whether any structures, systems, or components

that should be within the scope of license renewal had not been identified by the applicant. In

addition, the staff performed an independent assessment to determine whether any

components that should be subject to an AMR were not identified by the applicant. The staff

did not identify any omissions. On the basis of its review, the staff concludes that the applicant

has adequately identified the components of the UHS system that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the UHS system that are subject to an AMR, as required by 10

CFR 54.21 (a)(1).

2.3.3.23 Fuel Pool Cooling and Filter Demineralizer System

2.3.3.23.1 Summary of Technical Information in the Application

The applicant described the fuel pool cooling and filter demineralizer system in LRA Section

2.3.3.23 and provided a list of components subject to an AMR in LRA Table 2.3.3-23.

The purpose of the fuel pool cooling and filter demineralizer system is to remove heat from the

spent fuel and to maintain fuel storage pool water clarity. During refueling operations, the fuel

pool cooling and filter demineralizer system may be used to maintain the water clarity of the

reactor refueling cavity also. Using the methodology described in LRA Section 2.1.4.1 for

identifying the mechanical components within the scope of license renewal, the applicant

identified the following fuel pool cooling and filter demineralizer system intended function:

preclude adverse effects on safety-related SSCs - maintain sufficient integrity of

components that could be a hazard to safety-related SSCs so that the intended function of

safety-related SSCs is not adversely affected

The spent fuel pool cooling and filter demineralizer system which is a non-safety-related closedloop system consists of two circulating pumps, two heat exchangers, two skimmer surge tanks,

a filter, a deep-bed demineralizer, and the required piping, valves, and instrumentation. Water

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from the fuel storage pool overflows via scuppers and an adjustable weir into two crosstie

skimmer surge tanks. The skimmer surge tanks drain into a common suction header for the

fuel pool cooling pumps. Two parallel flow paths exist from the header, each with a fuel pool

cooling pump taking suction from the header and discharging through a fuel pool cooling heat

exchanger. Cooling water to the heat exchangers is supplied from the RBCCW system. A

crosstie line exists on the pump discharge piping in order to operate either pump with either

heat exchanger. The heat exchangers discharge into a common header that first flows through

the fuel pool filter, and then through the fuel pool demineralizer. The fuel pool demineralizer

discharges back into the fuel storage pool through two lines and spargers within the pool. The

return lines to the fuel storage pool enter near the top and have openings in the piping about 6

in. below the pool surface to act as anti-siphon devices, to preclude uncontrolled draining of the

pool during a pipe break. During refueling operations, the system may be aligned via manual

valves to discharge into the reactor refueling cavity. The shutdown cooling system may be

connected in parallel with the fuel pool cooling and filter demineralizer system during periods of

extremely high heat loads, such as immediately after refueling or a full core discharge into the

fuel storage pool. A clean demineralized water supply passes through a safety-related primary

containment isolation valve that is part of the fuel pool cooling and filter demineralized system,

to supply makeup water.

In LRA Section 2.3.3.23, the applicant described the evaluation boundary for the fuel pool

cooling and filter demineralizer system. In addition, the applicant highlighted those portions of

the fuel pool cooling and filter demineralizer system within the scope of the Rule in the P&l

drawings listed as references in LRA Section 2.3.3.23. Also, based on the methodology

described in LRA Section 2.1.5 for identifying the mechanical components subject to an AMR,

the applicant initially identified the following component groups and their intended functions

within the fuel pool cooling and filter demineralizer system in LRA Table 2.3.3-23 as being

within the scope of license renewal and subject to an AMR for Dresden only:

* closure bolting (pressure boundary)

* piping and fittings (pressure boundary)

* piping and fittings (spatial interaction)

* sight glasses (spatial interaction)

* valves (pressure boundary)

* valves (spatial interaction)

Resulting from the revised methodology described in the May 18, 2004 response to the draft

SER Open Item 2.1-1, the boundaries of the fuel pool cooling and filter demineralizer system at

Dresden were expanded and highlighted as shown on the revised boundary diagrams and an

additional boundary diagram. Additional piping and components from the fuel pool cooling and

filter demineralizer system at Dresden were added to the scope of license renewal.

At Quad Cities, the fuel pool cooling system was initially excluded from the scope of license

renewal. However, the system has been added to the scope of license renewal as a result of

the scoping methodology change due to the potential for spatial interaction with safety-related

components in the same general area. The applicant provided boundary diagrams in the May

18, 2004 response to the draft SER Open Item 2.1-1 and highlighted those portions of the fuel

pool cooling system in these boundary diagrams as within the scope of the Rule.

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Fuel pool cooling filters, demineralizer, and skimmer surge tanksiire not highlighted on the

boundary diagrams for both Dresden and Quad Cities as within the scope of the Rule. These

components reside in their own vaulted areas, physically isolated from safety-related equipment

such that they can not spatially interact.

The in LRA Table 2.3.3-23, which previously listed component groups as being within the scope

of license renewal and subject to an AMR at Dresden only, has been revised to include

component groups as being within the scope of license renewal and subject to an AMR at both

Dresden and Quad Cities.

Since the fuel pool cooling and filter demineralizer system is a non-safety-related system,

regarding to the heat exchangers only the "Spatial Interaction" function requires aging

management. Also, by a letter, dated June 22, 2004, the applicant clarified that the leakage

boundary of these heat exchangers is comprised of the same materials and experiences the

same environment as the component group evaluated under the "piping and fittings (spatial

interaction)," therefore, the piping and fitting component group with spatial interaction listed in

LRA Table 2.3.3-23 was revised to include heat exchanger as following:

* piping and fittings (spatial interaction) (includes heat exchanger shells)

In addition, the following new component group has been added to LRA Table 2.3.3-23 being

subject to an AMR:

* pumps (spatial interaction)

2.3.3.23.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.23, Dresden UFSAR Section 9.1.3, and Quad Cities

UFSAR Section 9.1.3 to determine whether there is reasonable assurance that the fuel pool

cooling and filter demineralizer system components within the scope of license renewal and

subject to an AMR have been identified in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1). The staff's review was conducted in accordance with Section 2.3 of NUREG-1 800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the fuel pool cooling and filter demineralizer system in the LRA. The

staff did not identify any omissions.

Also, the staff selected system functions described in the UFSARs that were set forth in 10

CFR 54.4 to verify that components having intended functions were not omitted from the scope

of the Rule. The staff also focused on components that were not identified as being subject to

an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the fuel pool cooling and filter

demineralizer system that are within the scope of license renewal and subject to an AMR in

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accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1), respectively, the staff compared the

referenced P&l drawings to the system drawings and system descriptions in the UFSARs to

ensure that the referenced P&I drawings were representative of the fuel pool cooling and filter

demineralizer system. The staff then reviewed the referenced P&l drawings to verify that those

portions of the fuel pool cooling and filter demineralizer system that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal and are identified

as such by the applicant in LRA Section 2.3.3.23, and that the applicant identified all fuel pool

cooling and filter demineralizer system components within the scope of license renewal and

subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff's review of the LRA identified areas in which additional information is necessary to

complete the staff's review of the applicant's scoping and screening results. Therefore, by the

August 4, 2003, letter, the staff issued RAls to the applicant concerning the specific items to

determine whether the applicant has properly applied the scoping and screening criteria of

10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's RAls and the applicant's responses by letter,

dated October 3, 2003, are described below.

RAI 2.3.3.23-1. The design objectives of the spent fuel pool cooling and cleanup system for

Dresden Units 2 and 3 are to handle the spent fuel pool cooling load and to maintain pool water

clarity. Spent fuel pool cooling pumps take suction from the skimmer surge tanks, circulate the

warm pool water to the heat exchanger, filter, and demineralizer, and discharge the cooled

water back to the spent fuel pool through two parallel lines (2-1910A-6N-K and 2-191 0B-6'-K).

In the Dresden Units 2 and 3 P&l drawings (LR-DRE-M-31 and LR-DRE-M-362), Exelon only

highlighted the following:

* a portion of one (2-1910B-6"-K) of the two lines as within the scope of license renewal per

10 CFR 54.4(a)(2)-parallel line (2-1910A-6"-K) was not highlighted as within the scope of

license renewal

* a portion of the drain line (from the globe valve, 3-1901 -11, to the 6'x4" reducer), which

collects the drains from the reactor well and the reactor well seal rupture drain, as within the

scope of license renewal per 10 CFR 54.4(a)(2)

Exelon did not provide discussion to justify why only the above-cited portions of the spent fuel

pool cooling and cleanup system are included in the scope of license renewal and subject to an

AMR. The staff believes that the entire spent fuel pool cooling and cleanup system is within the

scope of license renewal per 10 CFR 54.4(a)(2), and the passive and long-lived components of

the system should be subject to an AMR. The staff asked the applicant to provide detailed

discussion to clarify and justify why only the above-cited portions of the spent fuel pool cooling

and cleanup system are included in the scope of license renewal and subject to an AMR.

Applicant's Response and Staff's Evaluation

The applicant stated that a plant walkdown determined the following:

* The red-highlighted portion of line 2-1910B-6"-K shown on boundary diagram LR-DRE-M-31

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is in scope of license renewal because it is physically located such that leakage or spray

from this line could spatially interact with safety-related primary containment isolation valve

AOV 2-1601-23. Because of this spatial relationship, the highlighted portion of the line was

determined to be in scope of license renewal per 10 CFR 54.4(a)(2). The pipe line 2-

1910A-6"-K, which is shown as a parallel line on boundary diagram LR-DRE-M31, does not - -

have a similar spatial relationship to any safety-related components. Consequently, it was

not identified as within the scope of license renewal per 10 CFR 54.4(a)(2).

The red-highlighted portion of the drain line (from globe valve 3-1901-11 to the 6"x4W

reducer), as shown on boundary diagram LR-DRE-M-362, is physically located such that

leakage from this line could spatially interact with safety-related primary containment

isolation valve AOV 3-1601-23. Because of this spatial relationship, the highlighted portion

of the line was determined to be in scope of license renewal per 10 CFR 54.4(a)(2).

The applicant further stated that Exelon does not consider the entire Dresden spent fuel pool

cooling and cleanup system to be within the scope of license renewal per 10 CFR 54.4(a)(2).

The fuel pool cooling and cleanup system is a non-safety-related closed-loop system that is

normally in continuous operation. Except as discussed in the above paragraphs, the fuel pool

cooling and cleanup system is not located near safety-related equipment that could be affected

by failure of fuel pool cooling and cleanup system components. Thus, the Dresden fuel pool

cooling system is not, in general, classified as a system within the scope of license renewal

under the criterion of 10 CFR 54.4(a)(2).

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.23-1 acceptable because the fuel pool cooling and cleanup

system is a non-safety-related closed-loop system that is normally in continuous operation, and

the only intended function of the system is to preclude adverse effects from failure of segments

of piping and components on safety-related SSCs. The staff agrees with the applicant that

except as discussed in the above paragraphs, the Dresden fuel pool cooling and cleanup

system is not located near safety-related equipment that could be affected by failure of fuel pool

cooling and cleanup system components. Thus, only the segments of piping and components.

discussed above need to conform with the criteria set forth in 10 CFR 54.4 and 10 CFR

54.21(a)(2). Therefore, the staff considers its concern described in RAI 2.3.3.23-1 resolved.

RAI 2.3.3.23-2. In LRA Table 2.2-1, Exelon stated that because of differences in plant

equipment layout, some of the fuel pool cooling system piping at Dresden can potentially fall in..

a way to cause failure of nearby safety-related equipment. A similar equipment layout does not

exist at the Quad Cities plant.

The design objectives of the spent fuel pool cooling and cleanup system for the Quad Cities

plant are to handle the spent fuel pool cooling load and to maintain pool water clarity. The staff

believes that the entire spent fuel pool cooling and cleanup system is within the scope of

license renewal per 10 CFR 54.4(a)(2), and the passive and long-lived components of the

system should be subject to an AMR. The staff asked the applicant to provide detailed

discussion to justify why the spent fuel pool cooling and cleanup system is not within the scope

of license renewal per 10 CFR 54.4(a)(2), and the justification for excluding the passive and

long-lived components of the system from an AMR.

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Applicant's Response and Staff's Evaluation

The applicant stated that Exelon does not consider the Quad Cities spent fuel pool cooling and

cleanup system to be within the scope of license renewal per 10 CFR 54.4(a)(2). The fuel pool

cooling and cleanup system is a non-safety-related closed-loop system that is normally in

continuous operation. A plant walkdown during scoping and screening did not identify any

safety-related components that could be spatially affected by failure of Quad Cities fuel pool

cooling and cleanup system piping or components. Thus, the Quad Cities fuel pool cooling

system is not classified as a system within the scope of license renewal under the criterion of

10 CFR 54.4(a)(2).

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.23-2 acceptable because the Quad Cities spent fuel pool

cooling and cleanup system is a non-safety-related closed-loop system that is normally in

continuous operation, and the only intended function of the system is to preclude adverse

effects from failure of segments of piping and components on safety-related SSCs. However, a

plant walkdown by the applicant during scoping and screening did not identify any safety-related

components that could be spatially affected by failure of Quad Cities fuel pool cooling and

cleanup system piping or components. The staff agrees with the applicant that the Quad Cities

fuel pool cooling system is not within the scope of license renewal under the criterion of 10 CFR

54.4(a)(2). Therefore, the staff considers its concern described in RAI 2.3.3.23-2 resolved.

2.3.3.23.3 Conclusions

The staff reviewed LRA Section 2.3.3.23, the accompanying scoping boundary drawings, and

the applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. In addition, the staff performed an

independent assessment to determine whether any components that should be subject to an

AMR were not identified by the applicant. The staff did not identify any omissions. On the

basis of its review, the staff concludes that the applicant has adequately identified the

components of the fuel pool cooling and filter demineralizer system that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the fuel pool cooling and filter demineralizer system that are

subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.24 Plant Heating System

2.3.3.24.1 Summary of Technical Information in the Application

The applicant described the plant heating system in LRA Section 2.3.3.24 and provided a list of

components subject to an AMR in LRA Table 2.3-24.

The purpose of the plant heating system is to supply steam for plant and area heating during

cold weather periods, and for miscellaneous functions such as steam cleaning and carbon

dioxide or nitrogen vaporizing. Additionally, the Dresden plant heating system supplies steam

to the shutdown cooling system during its operation in the reactor heating mode.

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Using the methodology described in LRA Section 2.1.4.1 for identifying the mechanical

components within the scope of license renewal, the applicant identified the following plant

heating system intended function:..

preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be'a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected

The plant heating boiler feedwater pumps take suction from the heating system deaerating tank

and discharge into the plant heating boilers. In addition, Quad Cities has a small, summer

boiler with its own feedwater pumps taking suction from the deaerating tank. The boilers

produce steam that flows into a common distribution header. The header discharges steam

through a pressure control valve to various loops throughout the plant. Separate loops supply

loads in each major building, such as the turbine buildings, reactor buildings, crib house, and

radwaste building. From these loops, steam .flows to loads such as ventilation heating coils,

area space heaters, vaporizers, and steam drops for uses such as steam cleaning. The

condensate from the loads passes through steam traps to condensate return units located in

the major building areas. The condensate return units pump the condensate back to the

heating system deaerating tank at Dresden, and to the condensate receiving tank at Quad

Cities. At Quad Cities, the condensate receiving tank pumps then pump the condensate back

to the deaerating tank. At Dresden, each reactor building heating steam supply loop also

provides steam to its unit's shutdown heat exchangers (evaluated with the shutdown cooling

system) for use in the reactor heating mode. As the steam supplied to the shutdown heat

exchangers condenses, it drains via a steam trap to the reactor building equipment drain tank.

In LRA Section 2.3.3.24, the applicant described the plant heating system evaluation boundary.

In addition, the applicant highlighted those portions of the plant heating system within the scope

of the Rule in the P&l drawings listed as references in LRA Section 2.3.3.24. Also, based on

the methodology described in LRA Section 2.1.5 for identifying the mechanical components

subject to an AMR, the applicant identified the following component groups and their intended

functions within the plant heating system in LRA Table 2.3.3-24 as being within the scope of

license renewal and subject to an AMR:

* filters/strainers (spatial interaction)

* non-safety-related vents or drains, piping, and valves (spatial interaction, Dresden only)

* piping and fittings (spatial interaction)

* pumps (spatial interaction)

* sight glasses (spatial interaction, Quad Cities)

* tanks (spatial interaction)

* thermowells (spatial interaction,) (Dresden only), -

* traps (spatial interaction)

* tubing (spatial interaction)

* valves (spatial interaction)

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2.3.3.24.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.24 and various parts of the Dresden UFSAR and Quad

Cities UFSAR regarding the plant heating system to determine whether there is reasonable

assurance that the plant heating system components within the scope of license renewal and

subject to an AMR have been identified in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1). The staff's review was conducted in accordance with Section 2.3 of NUREG-1 800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the plant heating system in the LRA. The staff did not identify any

omissions.

Also, the staff selected system functions described in the UFSAR that were set forth in 10 CFR

54.4 to verify that components having intended functions were not omitted from the scope of

the Rule. The staff also focused on components that were not identified as being subject to an

AMR to determine if any components were omitted.

To verify that the applicant identified the components of the plant heating system that are within

the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10

CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the system

drawings and system descriptions in the UFSARs to ensure that the referenced P&l drawings

were representative of the plant heating system. The staff then reviewed the referenced P&l

drawings to verify that those portions of the plant heating system that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal and are identified

as such by the applicant in LRA Section 2.3.3.24, and that the applicant identified all plant

heating system components within the scope of license renewal and subject to an AMR in

accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1).

The staff found that those portions of the plant heating system that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal and are identified

as such by the applicant in LRA Section 2.3.3.24, and that the plant heating system

components that are subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1) are included in LRA Table 2.3.3-24. The staff did not identify any omissions.

2.3.3.24.3 Conclusions

The staff reviewed LRA Section 2.3.3.24 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. The

staff did not identify any omissions. On the basis of this review, the staff concludes that the

applicant has appropriately identified the components of the plant heating system that are within

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has

appropriately identified the components of the plant heating system that are subject to an AMR,

as required by 10 CFR 54.21 (a)(1).

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2.3.3.25 Containment Atmosphere Monitoring System

2.3.3.25.1 Summary of Technical Information in the Application

The applicant described the containment atmosphere monitoring (CAM) system in LRA Section

2.3.3.25 and provided a list of components subject to an AMR in LRA Table 2.3.3-25.

The CAM system provides the ability to monitor hydrogen, oxygen, and gross gamma radiation

levels in the containment following a LOCA, and provides necessary indication and trip signals.

Using the methodology described in LRA Section 2.1.4.1 for identifying the mechanical

components within the scope of license renewal, the applicant identified the following intended

CAM system functions:

* provide primary containment isolation

* support ESF function(s)

* preclude adverse effects on safety-related systems, structures and components

* credited in regulated events-components relied upon for compliance with 10 CFR 50.49

(EQ)

During CAM system operation, containment atmosphere is withdrawn through piping connected

to primary containment penetrations for obtaining both a drywell and suppression chamber air

sample. Hydrogen and oxygen concentration are measured outside the primary containment

(evaluated with the primary containment structure) and the sample returned to the primary

containment. The sample withdrawal lines in both cases are heat traced to prevent

condensation in the sample lines which would cause measurement inaccuracies. A check valve

is installed in the return discharge line for primary containment. In addition, a check valve is

installed in each reagent and calibration gas line for primary containment. The containment

atmosphere monitoring system consists of oxygen and hydrogen analyzer process

instrumentation and various indication and annunciation instruments, primary containment

monitoring panels, and gross gamma detector channels (from detector to annunciator and

computer points). The system is automatically activated upon the occurrence of a LOCA, or

manually by an operator. The system initiates a primary containment group 2 isolation on high

radiation.

In LRA Section 2.3.3.25, the applicant described the evaluation boundary of the CAM system.

In addition, the applicant highlighted those portions of the CAM and its structures and

components that are within the scope of the Rule in the P&l drawings listed as references in

LRA Section 2.3.3.25. Also, based on the methodology described in LRA Section 2.1.5 for

identifying the mechanical components subject to an AMR, the applicant identified the following

component groups and their intended functions within the CAM system in LRA Table 2.3.3.25

as being within the scope of license renewal and subject to an AMR:

* closure bolting (pressure boundary)

* filters/strainers (filter)

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* flexible hoses (pressure boundary)

* NSR vents or drains, piping, and valves (structure integrity/attached support)

* piping and fittings (structure integrity/attached support)

* piping and fittings (pressure boundary)

* pumps (pressure boundary)

* restricted orifices (pressure boundary) '

* sample pumps (pressure boundary)

* tubing (pressure boundary)

* valves (pressure boundary)

* valves (structure integrity/attached support)

2.3.3.25.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.25, Dresden UFSAR Sections 6.2.5.3.2 and 7.3.2.2.7,

and Quad Cities UFSAR Section 6.2.5.2 to determine whether there is reasonable assurance

that the CAM system components within the scope of license renewal and subject to an AMR

have been identified in accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff review

was conducted in accordance with Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the CAM system in the LRA. The staff did not identify any

omissions.

Also, the staff selected system functions described in the UFSAR that were set forth in 10 CFR

54.4 to verify that components having intended functions were not omitted from the scope of

the Rule. The staff also focused on components that were not identified as being subject to an

AMR to determine if any components were omitted.

To verify that the applicant identified the components of the CAM system that are within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the system

drawings and system descriptions in the UFSARs to ensure that the referenced P&l drawings

were representative of the CAM system. The staff then reviewed the referenced P&l drawings

to verify that those portions of the CAM system that meet the scoping requirements of 10 CFR

54.4 are included within the scope of license renewal and are identified as such by the applicant

in LRA Section 2.3.3.25, and that the applicant identified all CAM system components within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1).

2.3.3.25.3 Conclusions

The staff reviewed LRA Section 2.3.3.25 and accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

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any components that should be subject to an AMR were not identified by the applicant. The

staff did not identify any omissions. On the basis of its review, the staff concludes that the

applicant has adequately identified the components of the CAM system that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the CAM system that are subject to an AMR, as required by 10

CFR 54.21 (a)(1).

2.3.3.26 Nitrogen Containment Atmosphere Dilution System

2.3.3.26.1 Summary of Technical Information in the Application

The applicant described the nitrogen containment atmosphere dilution (NCAD) system in LRA

Section 2.3.3.26 and provided a list of components subject to an AMR in LRA Table 2.3.3-26.

The NCAD system provides two redundant, single failure proof, independent flow paths for

purging the primary containment with nitrogen to provide postaccident combustible gas control.

The NCAD system injects gaseous nitrogen into the primary containment to purge the

containment of oxygen and hydrogen to maintain the mixture below combustible levels.

Using the methodology described in LRA Section 2.1.4.1 for identifying the mechanical

components within the scope of license renewal, the applicant identified the following intended

NCAD system functions:

* support ESF function(s)-provides capability to maintain a nonexplosive atmosphere in the

primary containment following a design basis accident (backup to nitrogen inerting system

for post-LOCA operations (Quad Cities only))

The NCAD system is a manually operated system comprised of redundant flow paths. It is

operated locally by opening a manual valve near the nitrogen supply equipment. The

containment purge and vent valves can be aligned to inject nitrogen into the drywell or

suppression chamber (evaluated with the primary containment structure) for either flowpath. At

Quad Cities, the NCAD system is made up of two independent, redundant flowpaths for each

unit. Each flow path in turn can supply gaseous nitrogen to either the drywell or suppression

chamber. One flow path runs from the unit's'corresponding electric vaporizer and taps back

into the nitrogen inerting system piping just upstream of the nitrogen purge vaporization valve,

on the non-safety-related side. The other flow path' runs from the opposite unit's electric

vaporizer and taps back into the normal nitrogen makeup system just upstream of the nitrogen

makeup valve. Either flowpath can be supplied by the nitrogen atmospheric vaporizer. At

Dresden, there is a normal and emergency supply line. The normal NCAD line begins with the

drywell nitrogen purge and inerting system (DNPIS) (evaluated with the drywell nitrogen inerting

system) connection downstream of the pressure regulating station at the discharge side of the

makeup line atmospheric vaporizer; then, from the pressure regulating stations to the nitrogen

supply header. The emergency NCAD line begins with the discharge of the nitrogen auxiliary

tank and taps into the emergency truck connection upstream of the makeup line atmospheric

vaporizer.

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The NCAD system at Dresden includes the normal and emergency supply lines. The NCAD

system at Quad Cities includes the two independent, redundant flow paths. All associated

piping, components, and instrumentation contained within the flow paths and systems

described above are included in the NCAD system.

In LRA Section 2.3.3.26, the applicant described the evaluation boundary of the NCAD system.

In addition, the applicant highlighted those portions of the NCAD system and its structures and

components that are within the scope of the Rule in the P&I drawings listed as reference in LRA

Section 2.3.3.26. Also, based on the methodology described in LRA Section 2.1.5 for

identifying the mechanical components subject to an AMR, the applicant identified the following

component groups and their intended functions within the NCAD system in LRA Table 2.3.3.26

as being within the scope of license renewal and subject to an AMR:

* closure bolting (pressure boundary)

* restricted orifices (pressure boundary, Dresden only)

* restricted orifices (throttle, Dresden only)

* tubing (pressure boundary)

* valves (pressure boundary)

2.3.3.26.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.26, Dresden UFSAR Section 6.2.5.3.3, and Quad Cities

UFSAR Section 6.2.5.3 to determine whether there is reasonable assurance that the NCAD

system components within the scope of license renewal and subject to an AMR have been

identified in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff review was

conducted in accordance with Section 2.3 of NUREG-1 800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the NCAD system in the LRA. The staff did not identify any

omissions.

Also, the staff selected system functions described in the UFSAR that were set forth in 10 CFR

54.4 to verify that components having intended functions were not omitted from the scope of

the Rule. The staff also focused on components that were not identified as being subject to an

AMR to determine if any components were omitted.

To verify that the applicant identified the components of the NCAD system that are within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21(a)(1), respectively, the staff compared the referenced P&l drawings to the system

drawings and system descriptions in the UFSARs to ensure that the referenced P&l drawings

were representative of the NCAD system. The staff then reviewed the referenced P&l drawings

to verify that those portions of the NCAD system that meet the scoping requirements of 10 CFR

54.4 are included within the scope of license renewal and are identified as such by the applicant

in LRA Section 2.3.3.26, and that the applicant identified all NCAD components within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

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10 CFR 54.21(a)(1).

2.3.3.26.3 Conclusions

The staff reviewed LRA Section 2.3.3.26 and accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant.The staff

did not identify any omissions. On the basis of its review, the staff concludes that the applicant

has adequately identified the components of the NCAD system that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the NCAD system that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.3.27 Drywell Nitrogen Inerting System

2.3.3.27.1 Summary of Technical Information in the Application

The applicant described the drywell nitrogen inerting (DNI) system in LRA Section 2.3.3.27 and

provided a list of components subject to an AMR in LRA Table 2.3.3-27.

The DNI system, also known as the DNPIS, is provided to maintain the drywell in a nitrogen

inerted condition as a means of inhibiting the formation of a combustible gas mixture under

LOCA conditions. The system is not safety- related; however, it can be used for post-LOCA

hydrogen control. The system also serves as a backup to the pump-back system to maintain

the required drywell-to-suppression chamber differential pressure and provide nitrogen to the

NCAD system.

Using the methodology described in LRA Section 2.1.4.1 for identifying the mechanical

components within the scope of license renewal, the applicant identified the following intended

NCAD system functions:

a supports ESF function(s)-reduces and maintains a low concentration of oxygen in the

primary containment(can also be used, if available, for post-LOCA hydrogen concentration

control)

* credited in regulated event(s)-credited in mitigation of the Appendix R fire event by

establishing the inert drywell environment in which a design basis fire cannot occur

The DNI system consists of a liquid nitrogen storage tank, nitrogen vaporizers, associated

piping, isolation valves, and pressure regulators. Nitrogen is supplied to three possible types of

vaporizers. Steam powered vaporizers, which use plant heating steam (evaluated with plant'

heating system) to ensure supply temperatures do not damage nitrogen piping during periods

of large demand, exist at both Dresden and Quad Cities, although Quad Cities typically uses

electrically powered vaporizers installed for the same purpose. Additionally, each site has

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atmospheric vaporizers for periods of low demand. Flow regulating valves are also installed to

limit low nitrogen supply temperatures. Nitrogen to the drywell is supplied through the drywell

purge inlet line while air is vented to the reactor building ventilation system (evaluated with

RBH-HVAC) or the standby gas treatment system (evaluated with standby gas treatment

system). A similar method is used for inerting the suppression chamber. The containment is

deinerted by admitting air into the containment as the containment atmosphere is vented to the

reactor building ventilation system or the standby gas treatment system.

In LRA Section 2.3.3.27, the applicant described the evaluation boundary of the DNI system. In

addition, the applicant highlighted those portions of the DNI system and its structures and

components that are within the scope of the Rule in the P&l drawings listed as reference in LRA

Section 2.3.3.27. Also, based on the methodology described in LRA Section 2.1.5 for

identifying the mechanical components subject to an AMR, the applicant identified the following

component groups and their intended functions within the DNI system in LRA Table 2.3.3.27 as

being within the scope of license renewal and subject to an AMR:

* closure bolting (pressure boundary)

* filter/strainers (pressure boundary, Dresden only)

* filter/strainers (filter, Dresden only)

* flow elements (pressure boundary)

* isolation barriers (pressure boundary)

* piping and fittings (pressure boundary)

* tanks/vaporizers (pressure boundary)

* thermowells (pressure boundary)

* traps (pressure boundary)

* tubing (pressure boundary)

* valves (pressure boundary)

2.3.3.27.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.27, and Dresden and Quad Cities UFSAR Sections 6.2.5,

to determine whether there is reasonable assurance that the DNI system components within the

scope of license renewal and subject to an AMR have been identified in accordance with 10

CFR 54.4 and 10 CFR 54.21 (a)(1). The staff review was conducted in accordance with Section

2.3 of NUREG-1 800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the DNI system in the LRA. The staff did not identify any omissions.

Also, the staff selected system functions described in the UFSAR that were set forth in 10 CFR

54.4 to verify that components having intended functions were not omitted from the scope of

the Rule. The staff also focused on components that were not identified as being subject to an

AMR to determine if any components were omitted.

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To verify that the applicant identified the components of the DNI system that are within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the system

drawings and system descriptions in the UFSARs to ensure that the referenced P&l drawings

were representative of the DNI system. The staff then reviewed the referenced P&l drawings to

verify that those portions of the DNI system that meet the scoping requirements of 10 CFR 54.4

are included within the scope of license renewal and are identified as such by the applicant in

LRA Section 2.3.3.27, and that the applicant identified all DNI components within the scope of

license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1).

The staff's review of LRA Section 2.3.3.27 identified areas in which additional information is

necessary to complete the staff's review of the applicant's scoping and screening results.

Therefore, by the August 4, 2003, letter, the staff issued RAls to the applicant concerning the

specific items to determine whether the applicant has properly applied the scoping and.

screening criteria of 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's RAls and the applicant

responses, dated October 3, 2003, are described below.

RAI 2.3.3.27-1. Nitrogen auxiliary tank 2/3-8554, shown on diagram LR-DRE-M-4215 in the -

drywell nitrogen inerting system, requires an AMR because this tank provides a pressureretaining function for the safety-related components. Valve 2/3-8599-761 (D-7) and associated

1-inch line which connects to above tank is shown as not requiring an AMR. Also, valves 2/3-

8599-807 and -803, and connecting pipe and muffler (E-6), are shown as not requiring an AMR.

The staff asked the applicant to indicate where the LRA addresses the AMR of these

components or provide a justification for excluding these components from an AMR.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.27-1 stated that Exelon has reviewed boundary diagram

LR-DRE-M-4215 for the DNI system and the following clarification is provided.

Valve 2/3-8599-761 (D-7) and its associated 1 in. line are in the scope of license renewal and

are managed for aging. Boundary diagram LR-DRE-M-4215 should have highlighted this

component within the scope of license renewal. Similarly, valves 2/3-8599-807 and 2/3-8599-

803 and the connecting piping should have been highlighted indicating that they are within the

scope of license renewal. The muffler and piping beyond the safety relief valve, 2/3-8599-803,

are not in the scope of license renewal since these components do not support the pressure

boundary intended function.

Aging management references for these components can be found in LRA Table 2.3.3-27

under the component group 'valves" and "piping and fittings," with "pressure boundary" as the

component intended function.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.27-1 acceptable because it conforms with the criteria set forth

in 10 CFR 54.4 and 10 CFR 54.21(a)(1). Therefore, the staff considers its concern described in

RAI 2.3.3.27-1 resolved.

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RAI 2.3.3.27-2. Nitrogen purge vaporizer 1/2-8713 is shown on diagram LR-QDC-M-34-3 (C-2)

in the drywell nitrogen inerting system to require an AMR because this tank provides a

pressure-retaining function for the safety-related components. Lines 1/2-57163 and 1/2 -57522

which connects to the vaporizer tank, are shown as not requiring an AMR. The staff asked the

applicant to indicate where the LRA addresses the AMR of these components or provide a

justification for excluding these components from an AMR.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.27-2 stated that boundary diagram LR-QDC-M-34-3

should have highlighted the piping as being within the scope of license renewal. LRA Section

2.3.3.24 addresses the aging management of lines 1/2-57522-3"-O and 1/2-57163-11/4"-O.

Lines 1/2-57522-3"-O and 1/2-57163-11/4*-O to the steam vaporizer are within the scope of

license renewal and have an intended function of 'spatial interaction." LRA Table 2.3.3-24

includes the piping under the component group "piping and fittings (spatial interaction)."

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.27-2 acceptable because it conforms with the criteria set forth

in 10 CFR 54.4 and 10 CFR 54.21 (a)(1). Therefore, the staff considers its concern described in

RAI 2.3.3.27-2 resolved.

2.3.3.27.3 Conclusions

The staff reviewed LRA Section 2.3.3.27, accompanying scoping boundary drawings, and the

applicant's response to the RAls, dated October 3, 2003, to determine whether any SSCs within

the scope of license renewal had not been identified by the applicant. In addition, the staff

performed an independent assessment to determine whether any components that should be

subject to an AMR were not identified by the applicant. The staff did not identify any omissions.

On the basis of its review, the staff concludes that the applicant has adequately identified the

components of the DNI system that are within the scope of license renewal, as required by 10

CFR 54.4(a), and that the applicant has adequately identified the components of the DNI

system that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.28 Safe Shutdown Makeup Pump System (Quad Cities Only)

2.3.3.28.1 Summary of Technical Information in the Application

The applicant described the safe shutdown makeup pump (SSMP) system in LRA Section

2.3.3.28 and provided a list of components subject to an AMR in LRA Table 2.3.3-28.

The function of the SSMP system, which is a common system to Unit 1 or Unit 2, is to provide

cooling water to the reactor core in the event that the reactor becomes isolated from the main

condenser simultaneously with a loss of the feedwater system. Using the methodology

described in LRA Section 2.1.4.1 for identifying the mechanical components within the scope of

license renewal, the applicant identified the following SSMP system intended functions:

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* pressure boundary-maintains pressure boundary integrity at interface with HPCI system

piping to support injection of cooling water to the reactor pressure vessel (RPV)

* credited for regulated event(s)-provides cooling water injection into the reactor pressure

vessel credited for the mitigation of fire events in accordance with Appendix R to

10 CFR Part 50

The SSMP system consists of a motor-driven pump, associated valves, piping, and

instrumentation. The preferred water source to the pump is the contaminated condensate

storage tank (evaluated with the condensate and condensate storage system). An alternate

source of makeup water is available from the fire header (evaluated with the FP system). The

SSMP discharge is delivered to the reactor vessel (evaluated with the reactor vessel) via the

HPCI system pump discharge line (evaluated with the HPCI system).

In LRA Section 2.3.3.28, the applicant described the SSMP system evaluation boundary. In

addition, the applicant highlighted those portions of the SSMP system within the scope of the

Rule in the P&l drawings listed as references in LRA Section 2.3.3.28. Also, based on the

methodology described in LRA Section 2.1.5 for identifying the mechanical components subject

to an AMR, the applicant identified the following component groups and their intended functions

within the SSMP system in LRA Table 2.3.3-28 as being within the scope of license renewal

and subject to an AMR:

* auxiliary and RW HVAC air handlers heating/cooling (pressure boundary)

* auxiliary and RW HVAC air handlers heating/cooling (heat transfer)

* closure bolting (pressure boundary)

* ducts and fittings, access doors, closure bolts, and equipment frames (pressure boundary)

* filters/strainers (pressure boundary) -.

* filters/strainers (filter)

* piping and fittings, including spectacle flanges (pressure boundary)

* pumps (pressure boundary)

* restricting orifices (pressure boundary)

* restricting orifices (throttle)

* valves (pressure boundary)

2.3.3.28.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.28 and Quad Cities UFSAR Section 5.4.6.5 to determine

whether there is reasonable assurance that the SSMP system components within the scope of

license renewal and subject to an AMR have been identified in accordance with 10 CFR 54.4

and 10 CFR 54.21 (a)(1). The staff's review was coriducted in accordance with the Section 2.3

of NUREG-1800.

In the performance of the review, the staff reviewed the UFSAR to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the SSMP system in the LRA. The staff did not identify any

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omissions.

Also, the staff selected system functions described in the UFSAR that were set forth in 10 CFR

54.4 to verify that components having intended functions were not omitted from the scope of

the Rule. The staff also focused on components that were not identified as being subject to an

AMR to determine if any components were omitted.

To verify that the applicant identified the components of the SSMP system that are within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the system drawings and system descriptions in the UFSARs to ensure that the referenced P&l drawings

were representative of the SSMP system. The staff then reviewed the referenced P&l drawings

to verify that those portions of the SSMP system that meet the scoping requirements of 10 CFR

54.4 are included within the scope of license renewal and are identified as such by the applicant

in LRA Section 2.3.3.28, and that the applicant identified all SSMP system components within

the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10

CFR 54.21 (a)(1).

The staff's review of the LRA identified areas in which additional information is necessary to

complete the staff's review of the applicant's scoping and screening results. Therefore, by the

August 4, 2003, letter, the staff issued RAls to the applicant concerning the specific items to

determine whether the applicant has properly applied the scoping and screening criteria of

10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff's RAls and the applicant's responses by letter,

dated October 3, 2003, are described below.

RAI 2.3.3.28-1. In RAI 2.3.3.28-1, the staff observed that boundary drawing LR-QDC-M-70 (B8), SSMP system, shows a 2-inch pipe that is in scope (green) that comes from the SW system (LR-QDC-M-69-1, F-8) indicating that the water supply for the SSMP room cooler is supplied

from SW. LRA scoping and screening results, Section 2.3.3.28, states that the SSMP room

coolers are evaluated with the SW system, and LRA Section 2.3.3.16 states that the SW loads

include the SSMP room cooler for Quad Cities. However, on SW scoping drawing LR-QDC-M69-1 (F-8), that portion of the SW system is not shown in scope.

Since the SW system shown on LR-QDC-M-69-1, which can supply SW to the SSMP system at

the tie-in at F-7, is shown not in scope, the staff requested the applicant to identify the in-scope

source of water for the SSMP room cooler and any resultant changes to Table 2.3.3-16 and

affected AMPs.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.28-1 states that although SW is supplied to the SSMP

room cooler during routine operation, the SW system is not credited for compliance with 10

CFR 50.48. When the room cooler is credited during a fire, the SW supply is isolated by

closing valve 1/2-2901-25, and a fire water system source (evaluated in Section 2.3.3.5) is then

provided by opening valve 1/2-2901-9 (see LR-QDC-M-70, coordinates B-8 and C-8). These

valves are included in Table 2.3.3-28, under the component group 'valves (Quad Cities only)."

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The staff finds the applicant's respohse to RAI 2.3.3.28-1 acceptable because the SW system

is not credited for compliance with 10 CFR 50.48. When the room cooler is credited during a

fire, the SW supply is isolated and a fire water system source is then provided. The fire water

system source is the within scope water source for the SSMP room cooler and is evaluated

under LRA Section 2.3.3.5. Therefore, the staff finds the applicant's response acceptable and

considers its concern described in RAI 2.3.3.28-1 resolved.

RAI 2.3.3.28-2. The staff observed that the license renewal boundary drawing LR-QDC-M-70

(B-8), SSMP system, shows a 2 in. pipe that is in scope (green) that goes to the SW system

(LR-QDC-M-69-1, D-6) indicating that the water return from the SSMP room cooler goes to the

SW system and eventually to the circulating water system (LR-QDC-M-28-1, D-5). LRA

scoping and screening results, Section 2.3.3.28, states that the SSMP room coolers are

evaluated with the SW system. However, on LR-QDC-M-69-1 (D-6), the SW system piping from

the tie-in from the SSMP system to the tie-in to the circulating water system is shown not in

scope.

Service water, as shown on LR-QDC-M-69-1, from where the pipe from the SSMP ties in at D-6

to where it goes to the circulating water system (LR-QDC-M-28-1, D-5) at G-6, is not shown in

scope. The staff requested the applicant to identify the in-scope water discharge path for the

SSMP room cooler and any resultant changes to Table 2.3.3-16 and affected AMPs.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.28-2 states that although SW is supplied to the SSMP

room cooler during routine operation, the SW system is not credited for compliance with 10

CFR 50.48. When the room cooler is credited during a fire, the SW supply is isolated, and a

fire water system source is then provided. The room cooler cooling water discharge piping is

not reconfigured during a fire. The discharge line (line 1/2-2908-2'-L) exits the SSMP room and

connects to the SW discharge line from the 0-4709 instrument air compressor (line 0-39115-2"-

0), which in turn discharges into the Unit 2 42" standpipe (line 2-4407-42"-L). 'The standpipe

then connects to the discharge flume via the Unit 2 circulating water discharge piping. Only the

SSMP room cooler discharge piping and components within the SSMP room, as highlighted on

boundary diagram LR-QDC-M-70, are within the scope of license renewal. The SSMP room

cooler discharge piping and components are evaluated in LRA Section 2.3.3.28, "Safe

Shutdown Makeup Pump System (Quad Cities Only)," and are included in Table 2.3.3-28, -

under component groups "piping and fittings (Quad Cities only) (includes spectacle flanges)"

and "valves (Quad Cities only)," with component intended functions of "pressure boundary."

The loss of the component function of "pressure boundary" for cooling water discharge piping

and components outside of the SSMP room would not prevent the SSMP system from

performing its intended functions.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.28-2 acceptable because the SSMP room cooler water

discharge piping is not a safety-related component and a failure of the component outside of

the SSMP room would not prevent the SSMP system from performing its intended functions. A

failure of the pipe inside the SSMP room could prevent the SSMP system from performing its

intended functions; this section of the pipe is within the scope of license renewal and the piping

and components are included in LRA Table 2.3.3-28, subject to an AMR. Therefore, the staff

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considers its concern described in RAI 2.3.3.28-2 resolved.

RAI 2.3.3.28-3. In RAI 2.3.3.28-3, the staff identified that the boundary diagram LR-QDC-M-70

depicts the safe shutdown makeup system. At grid location F-2, piping line 1-2905-4"-B is

shown as continuing at grid location D-9 on diagram LR-QDC-M-46-1. Although the staff

examined diagram LR-QDC-M-46-1, this line could not be located. In the place where the staff

expected to find the SSMP system discharge line (based upon the staff's examination of LRQDC-M-87-1), an end-capped line is depicted on LR-QDC-M-46-1. The staff requested the

applicant to clarify where the SSMP system discharge line connects to the high pressure

injection system discharge line, so that the staff may verify that the LR scoping boundaries for

this system comply with 10 CFR 54.4(a).

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.28-3 states that when the SSMP system was initially

installed at Quad Cities, the SSMP discharged into the HPCI pump discharge line on both units.

The HPCI pump discharge line connects into the 'B" reactor feedwater line on both units. A

recent modification on Unit 1 moved the SSMP discharge line to connect directly into the "B"

reactor feedwater line and capped the stub where it used to connect to the HPCI pump

discharge line.

Quad Cities UFSAR Section 5.4.6.5, "Safe Shutdown Makeup Pump System," and LRA Section

2.3.3.28, "Safe Shutdown Makeup Pump System (Quad Cities Only)," accurately describe the

different flow paths for the two units, but because of the timing of the modification installation

and issuance of the "For Record" drawings, not all LR boundary diagrams associated with the

SSMP system reflected the change in the Unit 1 flow path prior to issuance of the LRA to the

NRC. The continuation flag for line 1-2905-4"-B on LR-QDC-M-70, coordinate F-2, should point

to M-15-1 (LR-QDC-M-15-1), coordinate F-1. LR-QDC-M-15-1, coordinate F-1, should show

line 1-2905-4"-B continuing from M-70 (LR-QDC-M-70) and connecting to the "B" reactor

feedwater line between the discharge side of check valve 1-0220-59B and the HPCI line 1-

2304-14"-C connection to the "B" reactor feedwater. LR-QDC-M-46-1 correctly depicts the

capped line for the original connection to the HPCI line.

Based on its review of the applicant's clarification discussed above, the staff finds its response

to RAI 2.3.3.28-3 acceptable because the inconsistency between the drawings and the system

description is caused by an outdated drawing. The current drawing is in accordance with the

system description given in the LRA. All the system components in the scope of license

renewal were identified in the system description in accordance with the criteria set forth in

10 CFR 54.4(a). Therefore, the staff considers its concern described in RAI 2.3.3.28-3

resolved.

RAI 2.3.3.28-4. The LRA includes flow elements as an individual entry in the AMR results

tables for many of the systems in which they are depicted as being within the scope of license

renewal on the associated LR boundary diagrams (e.g., DWM system and CCSW system).

However, for the SSMP system, the AMR results in LRA Table 2.3.3-28 do not include an entry

for flow elements, despite the fact that they are depicted as being within scope on boundary

diagram LR-QDC-M-70 (grid location D-5). Therefore, in light of the screening criteria set forth

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in 10 CFR 54.21 (a)(1), the staff requested the applicant to provide the basis for not including

flow elements as an entry in LRA Table 2.3.3-28.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.28-4 states that there are four components in the SSMP

system with an assigned plant component type of "flow element." These four components are

: included in different component groups in LRA Table 2.3.3-28. Refer to boundary diagram LRQDC-M-70.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.28-4 acceptable because the flow elements cited above were

identified as being within scope of license renewal in accordance with the criteria set forth in

10 CFR 54.4(a) and were included in different component groups in LRA Table 2.3.3-28.

Therefore, the staff considers its concern described in RAI 2.3.3.28-4 resolved.

RAI 2.3.3.28-5. In RAI 2.3.3.28-5, the staff identified that on boundary diagram LR-QDC-M-70

(grid location F-4), a segment of piping connected to in-scope piping is not highlighted as being

within the scope of license renewal. This segment of piping is part of a piping line that is

highlighted as being within the scope of license renewal on either side of the unhighlighted

segment, and there are no valves or other pressure boundaries that isolate the unhighlighted

segment. It is not apparent to the staff why the unhighlighted segment of piping is not

considered to be within scope to ensure that the in-scope portions of the piping line are capable

of performing their intended function for license renewal. Therefore, in light of 10 CFR 54.4(a),

the staff requested the applicant to provide the basis for not including the unhighlighted piping

segment within the scope of license renewal.

Applicant's Response and Staff's Evaluation

The applicant's response to RAI 2.3.3.28-5 states that the piping segment in question on LRQDC-M-70 (F-4) is actually an instrument electrical lead. See LR-QDC-M-12-2 (E-7) for a

clarification of boundary diagram symbols. It was correct not to highlight the questioned

section. There are more sections of instrument electrical leads on LR-QDC-M-70 that are

highlighted, but which should not have been. One example is the connection between the

motor operators for MO 2-2901-08 (C-3), MO 1-2901-08 (D-3), and MO 1/2-2901-07 (E-4).

When creating boundary diagrams for mechanical systems, it was the convention not to

highlight instrument electrical leads. Based on this, LR-QDC-M-70 should not have highlighted

the instrument electrical leads.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.3.28-5 acceptable because the component cited above is an

electrical lead and not a mechanical component. The applicant also stated that other electrical

leads were wrongfully highlighted. Component support commodity groups for the SSMP

system and electrical components that support the operation of the SSMP system are

described in LRA Sections 2.4.15 and 2.4.16. Therefore, the staff considers its concern

described in RAI 2.3.3.28-5 resolved.

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2.3.3.28.3 Conclusions

The staff reviewed LRA Section 2.3.3.28, the accompanying scoping boundary drawings, and

the applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. In addition, the staff performed an

independent assessment to determine whether any components that should be subject to an

AMR were not identified by the applicant. The staff did not identify any omissions. On the

basis of its review, the staff concludes that the applicant has adequately identified the

components of the SSMP system that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant has adequately identified the components of the SSMP

system that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.29 Circulating Water System

Resulting from the revised scoping methodology described in the May 18, 2004 response to the

draft SER Open Item 2.1-1, portions of the circulating water systems at Dresden and Quad

Cities were added to the scope of license renewal. Previously, these systems were not

included in the original license renewal application. The circulating water (CW) system is a

non-safety-related system that could spatially interact with portions of the safety-related

emergency diesel cooling water system at both sites. At Quad Cities, only the Unit 1 CW

system can spatially interact with safety-related components; therefore, it is the only system

which is added to the scope of license renewal for Quad Cities. Thus, the applicant created

LRA Section 2.3.3.29 (to address the CW systems for Dresden Units 2 & 3 and Quad Cities

Unit 1) for NRC staff review.

2.3.3.29.1 Summary of Technical Information in the Application

The applicant described the CW system in LRA Section 2.3.3.29 and provided a list of

components subject to an AMR in LRA Table 2.3.3-29.

The primary function of the CW system is to remove the heat rejected from the main

condenser. Using the methodology described in LRA Section 2.1.4.1 for identifying the

mechanical components within the scope of license renewal, the applicant identified the

following CW system intended functions:

Preclude adverse effects on safety-related SSCs- Non-safety-related components that

could be a hazard to safety-related SSCs maintain sufficient integrity so that the intended

function of safety-related SSCs is not adversely affected.

At Dresden, the CW system takes supply from the Dresden cooling lake (with makeup from

Kankakee River) or directly from the Kankakee River, directs the flow through the main

condenser, and discharges it back to the Dresden cooling lake andlor the Illinois River system.

Whereas at Quad Cities, the CW system takes suction directly from the Mississippi River,

discharges the flow through the condenser, and directs it back to the river.

The CW system on each unit has three vertical, drypit, centrifugal, removable element CW

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pumps which deliver water from the crib house intake to the condenser water boxes. Each :

pump suction is sectionalized to permit dewatering of one pit for maintenance while the

remaining two pumps are in operation. Upstream of each CW pump there is a bar-grille trash

rack with a rake for periodic removal of river debris followed by traveling screens for removal of

debris. Each pump is provided with a shutoff valve at its discharge. At the condenser pit the

CW pipe becomes a supply header to the main condenser.

The applicant described the evaluation boundary for the CW system in LRA Section 2.3.3.29.

In addition, the applicant highlighted on the P&I drawings those portions of the CW system that

are within the scope of the Rule. These drawings are listed as 'License Renewal Boundary

Diagram References" in the LRA Section 2.3.3.29. Also, based on the methodolgy described in

LRA Section 2.1.5 for identifying the mechanical components subject to an AMR, the applicant

identified the following component groups and their intended functions within the CW system in

LRA Table 2.3.3-29 as being within the scope of license renewal and subject an AMR:

* Piping and fittings (spatial interaction)

* Valves (spatial interaction)

* Pumps (spatial interaction - Dresden only)

2.3.3.29.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.29, Dresden UFSAR Section 10.4.5, and Quad Cities

UFSAR Section 10.4.5 to determine whether there is reasonable assurance that the CW

system components within the scope of license renewal and subject to an AMR have been

identified in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff's review was

conducted in accordance with Section 2.3 of the NUREG-1 800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the CW system in the LRA. The staff did not identify any omissions.

Also, the staff selected system functions described in the UFSARs that were set forth in

10 CFR 54.4 to verify that components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the CW system that are within the

scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the

system drawings and system descriptions in the UFSARs. The staff then reviewed the

referenced P&l drawings to verify that those portions of the CW system that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal and are identified

as such by the applicant in LRA Section 2.3.3.29, and that the applicant identified all CW

system components within the scope of license renewal and subject to an AMR in accordance

with 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

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The staff found that those portions of the CW system that meet the scoping requirements of

10 CFR 54.4 are included within the scope of license renewal and are identified as such by the

applicant in LRA Section 2.3.3.29. The CW system components that are subject to an AMR in

accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1) are included in LRA Table 2.3.3-29. The

staff did not identify any omissions.

2.3.3.29.3 Conclusions

The staff reviewed LRA Section 2.3.3.29 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. No

omissions were found. On the basis of its review, the staff concludes that the applicant has

adequately identified the components of the CW system that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the

components of the CW system that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.30 Dresden Laundry Treatment System

Resulting from the revised scoping methodology described in the May 18, 2004 response to the

draft SER Open Item 2.1-1, a portion of the laundry waste treatment system at Dresden was

added to the scope of license renewal. Non-safety-related laundry waste treatment system

piping could spatially interact with safety-related electrical switchgear at Dresden. As a result,

Section 2.3.3.30, Laundry Waste Treatment System has been created (for Dresden only) by the

applicant and submitted for NRC staff review. Previously, this system was not included in the

original license renewal application.

2.3.3.30.1 Summary of Technical Information in the Application

The applicant described the laundry waste treatment system in LRA Section 2.3.3.30 and

provided a list of components subject to an AMR in LRA Table 2.3.3-30.

The function of the laundry waste treatment system is to collect potentially radioactive water for

liquid radwaste processing. Using the methodology described in LRA Section 2.1.4.1 for

identifying the mechanical components within the scope of license renewal, the applicant

identified the following laundry waste treatment system intended functions:

* Preclude adverse effects on safety-related SSCs - Non-safety-related components that

could be a hazard to safety-related SSCs maintain sufficient integrity so that the intended

function of safety-related SSCs is not adversely affected.

At Dresden, the laundry drain tank of the laundry waste treatment system collects liquid waste

generated from the laundry facility which includes the Dresden Unit 1 laundry room, the

maintenance shop floor drains, and the access control building personnel decontamination

station drains. The liquid waste is pumped to the Dresden Unit 2/3 liquid radwaste system for

sampling.

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The applicant described the evaluation boundary for the laundry waste treatment system in LRA

Section 2.3.3.30. In addition, the applicant highlighted those portions of the laundry waste

treatment system within the scope of the Rule on the P&l drawing listed as references in the

LRA Section 2.3.3.30. Also, based on the methodolgy described in LRA Section 2.1.5 for

identifying the mechanical components subject to an AMR, the applicant identified the following

component groups and their intended functions within the laundry waste treatment system in

LRA Table 2.3.3-30 as being within the scope of license renewal and subject to an AMR:

Piping and fittings (spatial interaction - Dresden only)

According to the applicant, while the laundry waste treatment system includes the laundry

accumulator tank, drain tank vault sump eductor, laundry drain tank, laundry drain pump, and

associated piping, valves and instruments, only discharge piping transferring water to radwaste

is located in the same general area that includes safety-related electrical switchgear. For that

reason, only piping and fittings require aging management.

2.3.3.30.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.30 and Dresden UFSAR Section 1.2.4.4.11 to determine

whether there is reasonable assurance that the laundry waste treatment system components

within the scope of license renewal and subject to an AMR have been identified in accordance

with 10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff's review was conducted in accordance

with Section 2.3 of the NUREG-1800.

In the performance of the review, the staff reviewed the UFSAR to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the laundry waste treatment system in the LRA. The staff did not

identify any omissions.

The staff also focused on components that were not identified as being subject to an AMR to

determine if any components were omitted.,-

To verify that the applicant identified the components of the laundry waste treatment system

that are within the scope of license renewal and subject to an AMR in accordance with 10 CFR

54.4 and 10 CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l drawing to

the system drawing in the UFSAR to ensure that the referenced P&i drawing was

representative of the laundry waste treatment system. The staff then reviewed the referenced

P&l drawing to verify that those portions of the laundry waste treatment system that meet the

scoping requirements of 10 CFR 54.4 are included within the scope of license renewal and are

identified as such by the applicant in LRA Section 2.3.3.30, and that the applicant identified all

laundry waste treatment system components within the scope of license renewal and subject to

an AMR in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff found that those portions of the laundry waste treatment system that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal and are identified

as such by the applicant in LRA Section 2.3.3.30. The laundry waste treatment system

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components that are subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR f

54.21 (a)(1) are included in LRA Table 2.3.3-29. The staff did not identify any omissions.

2.3.3.30.3 Conclusions

The staff reviewed LRA Section 2.3.3.30 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. No

omissions were found. On the basis of its review, the staff concludes that the applicant has

adequately identified the components of the laundry waste treatment system that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the laundry waste treatment system that are subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

2.3.3.31 Zinc Injection System

Resulting from the revised scoping methodology described in the May 18, 2004 response to the

draft SER Open Item 2.1-1, the zinc injection system at both sites was added to the scope of

license renewal. Previously, this system was not included in the original license renewal

application. The zinc injection system is a non-safety-related system that could spatially interact

with safety-related piping. As a result, Section 2.3.3.31, Zinc Injection System has been

created by the applicant and submitted for NRC staff review.

2.3.3.31.1 Summary of Technical Information in the Application

The applicant described the zinc injection system in LRA Section 2.3.3.31 and provided a list of

components subject to an AMR in LRA Table 2.3.3-31.

The function of the zinc injection system is to reduce the amount of Cobalt-60 buildup on

recirculation piping in the primary containment and reduce dose rates in the drywell during

outages. Using the methodology described in LRA Section 2.1.4.1 for identifying the

mechanical components within the scope of license renewal, the applicant identified the

following zinc injection system intended functions:

* Preclude adverse effects on safety-related SSCs - Non-safety-related components that

could be a hazard to safety-related SSCs maintain sufficient integrity so that the intended

function of safety-related SSCs is not adversely affected.

The zinc injection system is mounted on a skid near the reactor feedwater pumps. A tap on the

feedwater pump discharge header provides flow to a vessel on the skid which contain zinc

oxide pellets and returns to the feedwater pump suction header. The driving force for the

injection is the differential pressure between the discharge and suction of the feedwater pumps.

The zinc oxide dilution rate is controlled by varying the flow through the skid with a manually

operated flow control valve.

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The applicant described the evaluation boundary for the zinc injection system in LRA Section

2.3.3.31. In addition, the applicant highlighted on the P&l drawings those portions of the zinc

injection system that are within the scope of the Rule. These drawings are listed as 'License

Renewal Boundary Diagram References" in the LRA Section 2.3.3.31. Also, based on the

methodology described in LRA Section 2.1.5 for identifying the mechanical components subject

to an AMR, the applicant identified the following component groups and their intended functions

within the zinc injection system in LRA Table 2.3.3-31 as being within the scope of license

renewal and subject an AMR:

* Piping and fittings (spatial interaction)(includes dissolution columns, strainers and flow

elements)

* Tubing (spatial interaction)

* Valves (spatial interaction)

The licensee included the dissolution columns, strainers, and flow elements to LRA

Table 2.3.3-31 as part of the piping and fittings for aging management, because the leakage

boundary for these components is comprised of the same material and experiences the same

environment as the components evaluated under the "Piping and Fittings (spatial interaction)"

group.

2.3.3.31.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.31, Dresden UFSAR Section 5.4.3.7, and Quad Cities

UFSAR Section 10.4.7.2 to determine whether there is reasonable assurance that the zinc

injection system components within the scope of license renewal and subject to an AMR have

been identified in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff's review

was conducted in accordance with Section 2.3 of the NUREG-1800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the zinc injection system in the LRA. The staff did not identify any

omissions.

Also, the staff selected system functions described in the UFSARs that were set forth in

10 CFR 54.4 to verify that components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the zinc injection system that are within

the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the

* system drawings and system descriptions in the UFSARs to ensure that the referenced P&l

drawings were representative of the zinc injection system. The staff then reviewed the

referenced P&l drawings to verify that those portions of the zinc injection system that meet the

scoping requirements of 10 CFR 54.4 are included within the scope of license renewal and are

identified as such by the applicant in LRA Section 2.3.3.31, and that the applicant identified all

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zinc injection system components within the scope of license renewal and subject to an AMR in

accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff found that those portions of the zinc injection system that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal and are identified

as such by the applicant in LRA Section 2.3.3.31. The zinc injection system components that

are subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1) are included in

LRA Table 2.3.3-31. The staff did not identify any omissions.

2.3.3.31.3 Conclusions

The staff reviewed LRA Section 2.3.3.31 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. No

omissions were found. On the basis of its review, the staff concludes that the applicant has

adequately identified the components of the zinc injection system that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the zinc injection system that are subject to an AMR, as required

by 10 CFR 54.21 (a)(1).

2.3.4 Steam and Power Conversion Systems

The steam and power conversion systems consist of the main steam, feed water, condensate

and condensate storage systems, main condenser, main turbine and auxiliaries, turbine oil

(Quad Cities only), and main generator and auxiliaries (Quad Cities only), and the associated

components.

2.3.4.1 Main Steam System

2.3.4.1.1 Summary of Technical Information in the Application

The applicant described the main steam system in LRA Section 2.3.4.1 and provided a list of

components subject to AMR in LRA Table 2.3.4-1.

The function of the main steam system is to direct steam from the reactor pressure vessel to

the main turbine and balance of plant auxiliary steam loads. In performing this function, it

serves as part of the primary boundary to prevent radioactive release to the surrounding

environment. The system also provides the ability to bypass steam directly to the main

condenser, and provides overpressure protection for the reactor vessel.

Using the methodology described in LRA Section 2.1.4.1 for identifying the mechanical

components within the scope of license renewal, the applicant identified the following main

steam system intended functions:

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* pressure boundary-maintains the integrity of the reactor coolant pressure boundary and

provides steam-line isolation to support the reactor coolant pressure boundary

* core cooling-in conjunction with the automatic depressurization system, supports

emergency core cooling by depressurizing the reactor pressure vessel as required to

support low pressure coolant injection and core spray operation

* overpressure protection-provides overpressure protection in transient or accident events

that increase pressure in the reactor pressure vessel

* primary containment isolation-provides containment isolation for those portions of the

system that interface with the primary containment

* supports ESF function(s)-provides process signals for initiation of ESF functions, limits

coolant inventory loss rate in some LOCA events, and (at Quad Cities only) provides steam

supply for operation of the HPCI and RCIC systems

* credited in regulated event(s)-provides overpressure protection, reactor vessel isolation

capability, and pressure control capability credited in mitigation of the Appendix R fire,

ATWS, and SBO events (The system also contains components that are relied upon for

compliance with 10 CFR 50.49, (EQ).)

* post accident plateout of MSIV seat leakage-provides surfaces for plateout of iodine

releases resulting from MSIV bypass leakage

* limit steam line flow-limits potential radioactive release by restricting steam flow during a

steam line rupture outside of primary containment: flow is also limited to ensure integrity of

dryers in order to prevent restriction of MSIV closure

* steam flow measurement-provides main steam flow input for primary containment isolation

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected

The main steam system consists of four main steam lines that deliver steam from the reactor to

the main turbine. Each line is equipped with safety valves, at least one relief valve, a venrturitype flow restrictor, followed by an MSIV inside and outside the primary containment. Also

connected to the main steam lines are tail pipes to the suppression pool for the safety/relief

valves, main steam line drain piping, turbine main stop and bypass valves, and the associated

main steam bypass piping to the condenser.

At Dresden, the main steam system downstream of the outboard isolation valve is described in

Section 10.3 of the Dresden UFSAR. In'addition to providing steam to drive the main turbine, it

also provides steam to the turbine gland seal system, steam jet air-ejectors, off-gas recombiner

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system, main condenser low load reheat coils, and the liquid radwaste reboiler. The system

can be aligned to bypass the main turbine via bypass valves to the main condenser when

required. This is done by directing steam from the turbine bypass manifold, through nine 8-inch

lines connected to the turbine bypass valves, which discharge to the main condenser. Drains

are provided at several locations along the main steam system to drain condensate from the

line and return it to the condenser.

At Quad Cities, the main steam system supplies steam to the main turbine, the turbine gland seal system, steam jet air-ejector system, booster air ejector (2B train only), off-gas preheater,

and the condenser low load reheat coil supply. Also, it supplies steam to the HPCI and RCIC

pump turbines as described in LRA Section 2.3.4.1. The main steam system downstream of

the outboard isolation valve is described in Section 10.3 of the Quad Cities UFSAR. Low

points of each of the main steam lines are provided with drains through a valved line to the

main condenser.

In LRA Section 2.3.4.1, the applicant described the main steam system evaluation boundary. In

addition, the applicant highlighted those portions of the main steam system within the scope of

the Rule in the P&l drawings listed as references in LRA Section 2.3.4.1. Also, based on the

methodology described in LRA Section 2.1.5 for identifying the mechanical components subject

to an AMR, the applicant initially identified the following component groups and their intended

functions within the main steam system in LRA Table 2.3.4-1 as being within the scope of

license renewal and subject to an AMR:

* accumulators (pressure boundary)

* closure bolting (pressure boundary)

* dampeners (pressure boundary, Quad Cities only)

* filters/strainers (filter, Quad Cities only)

* flexible hoses (pressure boundary)

* flow elements (pressure boundary)

* NSR vents or drains, piping, and valves (spatial interaction)

* NSR vents or drains, piping, and valves (structural integrity/attached support)

* piping and fittings (pressure boundary)

* small bore piping and fittings (pressure boundary)

* restricting orifices (pressure boundary)

* rupture discs (pressure boundary)

* tanks (pressure boundary, Quad Cities only)

* thermowells (pressure boundary)

* tubing (structural integrity/attached support)

* vacuum breakers (pressure boundary)

* valves (pressure boundary)

* valves (structural integrity/attached support, Dresden only)

Resulting from the revised methodology described in the May18, 2004 response to the draft

SER Open Item 2.1-1, the boundaries of non-safety-related sections of the main steam system

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at Dresden and Quad Cities were expanded and highlighted as shown on the revised boundary

diagrams, and the new boundary diagrams added for Quad Cities. Additional piping

components associated with main steam instrumentation racks that contain small bore piping

and tubing that could spatially interact with safety-related equipment in the same general area

was added to the scope of license renewal for both Dresden and Quad Cities. Walkdowns of

the turbine building at Dresden identified several main steam lines which supply steam to the

radwaste reboiler routed in the same general areas containing safety-related components. The

main steam line piping and associated components located in these areas were also added to

the scope of license renewal due to potential spatial interaction with safety-related equipment.

Quad Cities does not have a radwaste reboiler subsystem. As such, the scoping of the main

steam supply lines to the radwaste reboiler only applies to Dresden.

The applicant identified the following additional component groups and their intended functions

within the main steam system as being within scope of license renewal, and added them to LRA

table 2.3.4.1.

* Piping and Fittings (spatial interaction)

* Tubing (spatial interaction)

* Valves (spatial interaction)

2.3.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.1, Dresden UFSAR Section 10.3, and Quad Cities

UFSAR Section 10.3 to determine whether there is a reasonable assurance that the main

steam system components within the scope of license renewal and subject to AMR have been

identified in accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's review was

conducted in accordance with the Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the main steam system in the LRA.

Also, the staff selected system functions described in the UFSARs that were set forth in 10

CFR 54.4 to verify that the components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any component were omitted.

To verify that the applicant identified the components of the main steam system that are within

the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10

CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the system

drawings and system descriptions in the UFSARs to ensure that the referenced P&l drawings

were representative of the main steam system. The staff then reviewed the referenced P&l

drawings to verify that those portions of the main steam system that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal and are identified

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as such by the applicant in LRA Section 2.3.4.1, and that the applicant identified all main steam

system components within the scope of license renewal and subject to an AMR in accordance

with 10 CFR 54.4 and 10 CFR 54.21(a)(1).

The staff's review of the LRA identified areas in which additional information is necessary to

complete the staff's review of the applicant's scoping and screening results. Therefore, by the

August 4, 2003, letter, the staff issued RAls to the applicant concerning the specific items to

determine whether the applicant has properly applied the scoping and screening criteria of

10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff's RAls and the applicant's responses by letter,

dated October 3, 2003, are described below.

RAI 2.3.4.1-1. UFSAR Section 15.6.5.5 contains a discussion of the radiological dose analysis

performed for the control room in accordance with guidance of NUREG-0737, Item III.D.3.4.

Credit is taken for iodine plateout on surfaces of steam lines and condenser and radioactive

decay prior to release. In assessing radioactive releases via the MSIV leakage pathway, MSIV

leakage is assumed to pass through three different volumes which provide holdup and plateout.

The volumes are the main steam piping section between the inboard and outboard isolation

valves, the piping between the outboard isolation valves and the turbine stop valves, and the

piping between the turbine stop valves and the turbine condenser complex. The licensee has

identified postaccident plateout of MSIV seat leakage as a system intended function of the main

steam system. The staff believes that in addition to the plateout function, the main steam

system also provides for postaccident containment and holdup of MSIV bypass leakage, and

that pressure boundary integrity for portions of the main steam system that are required to

contain bypass leakage must be maintained during the postaccident period. The staff askerd

the applicant to clarify whether postaccident containment and holdup should be included as an

intended function for the main steam system, and if not, please provide justification for its

exclusion.

Applicant's Response and Staff's Evaluation

The main steam system intended function, identified in Section 2.3.4.1 of the LRA as "Post

accident plateout of MSIV seat leakage," should have read as follows:

Post accident holdup and plateout of MSIV seat leakage-provides volumes for holdup and

surfaces for plateout of elemental and particulate iodine resulting from MSIV bypass leakage

Based on its review, the staff finds the applicant's response acceptable because the applicant

revised the intended function to clearly include post accident holdup and plateout of MSIV seat

leakage. Therefore, the staff considers its concern described in RAI 2.3.4.1-1 resolved.

RAI 2.3.4.1-2. As stated in RAI 2.3.4.1-1, the staff believes that post accident containment,

plateout, and holdup of MSIV bypass leakage is a system intended function of the main steam

system. Therefore, the SSCs necessary to ensure this intended function are in scope of

license renewal per 10 CFR 54.4(a). Hence, the steam drain lines and turbine bypass piping

should be in scope of license renewal and subject to an AMR. License renewal boundary

drawings LR-DRE-M-12-2, LR-DRE-M-345-2, LR-QDC-M-13-2, and LR-QDC-M-60-2 indicate

that turbine bypass piping from the main steam line equalization header to the condenser, and

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the main steam piping from the equalization header up to and including the main steam stop

valves, are not in scope. The staff asked the applicant to provide a justification for the

exclusion of these sections of main steam system piping and their associated components.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.4.1-2, the applicant agreed that the subject sections of piping and

their components are within the scope of license renewal, and identified the applicable revisions

to boundary drawings LR-DRE-M-12-2, LR-DRE-M-345-2, LR-QDC-M-13-2, and LR-QDC-M60-2. In addition, the applicant stated that these changes will result in additional main steam

line piping and fittings, valves, and restricting orifices being added to the scope of license

renewal with an intended function of "containment, hold up and plateout." These newly

identified components are the same types of components as have already been evaluated and

will be included in the AMPs currently applicable for the main steam system piping and piping

components. The applicant further stated that LRA Table 2.3.4-1 should have included these

additional components and their corresponding intended functions as subject to an AMR.

Based on its review, the staff finds the applicant's response acceptable because the applicant

has (1) added the main steam line bypass piping sections to the scope of license renewal in

accordance with the criteria set forth in 1 OCFR 54.4, and (2) acknowledged that LRA Table

2.3.4-1 should have included these additional components and their corresponding intended

functions subject to an AMR. Therefore, the staff considers its concern described in RAI

2.3.4.1-2 resolved.

RAI 2.3.4.1-3. The main steam line drain lines provide an MSIV leakage pathway to the

condenser which has an intended function of postaccident containment, holdup, and plateout of

MSIV bypass leakage. Therefore, the main steam drain piping from the main steam line to the

condenser is in scope of license renewal per 10 CFR 54.4(a). However, only the Dresden Unit

2 boundary drawing shows the entire drain line to the condenser as being in scope of license

renewal. Dresden Unit 3, and Quad Cities Units 1 and 2, shows only drain line sections on

drawings LR-DRE-M-345-2, LR-QDC-M-13-2, and LR-QDC-M-60-2, respectively, as being in

scope of license renewal. A review of these drawings indicate that the drain lines are continued

on Dresden Unit 3 drawing M-370, and Quad Cities drawings M-26 and M-73 for Units 1 and 2,

respectively. The staff believes that the main steam drain line section that goes to the

condenser, shown on the above-mentioned drawing, should be included as in scope of license

renewal. The staff asked the applicant to provide a justification for the exclusion of the main

steam drain line piping shown on drawing LR-DRE-M-370, and Quad Cities drawings M-26 and

M-73, for which no boundary drawings were provided. The staff also asked the applicant

whether boundary drawings exist for Quad Cities drawings M-26 and M-73, and, if so, to

provide these drawings.

Applicant's Response and Staff's Evaluation

The applicant agreed that the continuation of the in-scope drain line to its point of interface with

the main condenser is within the scope of license renewal and has identified the applicable

revisions to boundary drawings LR-DRE-M-345-2, LR-QDC-M-13-2, and LR QDC-M-60-2. In

addition, the applicant stated that these changes will result in additional main steam line piping

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I

and fittings with an intended function of "containment, hold up and plateout' being added to

LRA Table 2.3.4-1 as being within the scope of license renewal and subject to an AMR. This

newly identified piping is the same type of piping that has already been evaluated and is

included in the AMPs currently applicable for the main steam system piping. The applicant

further stated that LRA Table 2.3.4-1 should have included the additional piping and fittings and

their corresponding intended functions as subject to an AMR.

Based on its review, the staff finds the applicant's response acceptable because the applicant

has identified and included additional main steam line piping in the boundary drawings as within

the scope of license renewal and subject to an AMR, and has stated that additional main steam

line piping and fittings with an intended function of 'containment, hold up and plateout" are

being added to LRA Table 2.3.4-1 as being subject to an AMR. Therefore, the staff considers

its concern described in RAI 2.3.4.1-3 resolved.

RAI 2.3.4.1-4. Acoustic flow sensoring devices, flow elements FE-261-60A and FE-261-60D,

on boundary drawing LR-DRE-M-12-1, for Dresden Unit 2, are not shown to be within scope.

However, the corresponding devices for the B and C steam lines, flow elements FE-261-60B

and FE-261-60C, are included in scope. The staff asked the applicant to provide justification

for the exclusion of these components.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.4.1-4, the applicant stated that boundary diagram LR-DRE-M-12-1

should have highlighted acoustic flow sensing devices, flow elements 2-261-60A and 2-261-

60D. Flow elements 2-261-60A and 2-261-60D are within the scope of license renewal.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.1-4 acceptable

because the two flow elements, 2-261-60A and 2-261-60D, are identified as being in scope of

license renewal and subject to an AMR, and they were inadvertently not highlighted in the LR

boundary diagram. Therefore, the staff considers its concern described in RAI 2.3.4.1-4

resolved.

RAI 2.3.4.1-5. The portion of the safety relief valve (SRV) discharge lines inside the wetwell,

and their associated T-quenchers, are not identified as in scope in Dresden drawings LR-DREM-25 and LR-DRE-M-356. In addition, the T-quenchers for Dresden or Quad Cities have not

been included in Table 2.3.4-1. The staff believes that the SRV discharge lines and Tquenchers are in scope of license renewal per 10 CFR 54.4(a)(1). The staff asked the

applicant to provide a justification for exclusion of these components.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.4.1-5, the applicant stated that the complete SRV discharge lines

and the associated T-quenchers shown on boundary diagrams LR-DRE-M-25 and LR-DRE-M356 should have been highlighted. The SRV discharge lines and T-quenchers are within the

scope of license renewal. The SRV discharge lines and T-quenchers were not explicitly called

out, but they are included in LRA Table 2.3.4-1 under component group upiping and fittings."

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Based on its review, the staff finds the applicant's response to RAI 2.3.4.1-5 acceptable

because the complete SRV discharge lines and their associated T-quenchers are identified as

being in scope of license renewal and subject to an AMR, and they were inadvertently not

highlighted in the LR boundary diagram. And also, because the components associated with

the SRV discharge lines and T-quenchers are included in LRA Table 2.3.4-1 under component

group 'piping and fittings." Therefore, the staff considers its concern described in RAI 2.3.4.1-5

resolved.

2.3.4.1.3 Conclusions

The staff reviewed LRA Section 2.3.4.1, the accompanying scoping boundary drawings, and

the applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. In addition, the staff performed an

independent assessment to determine whether any components that should be subject to an

AMR were not identified by the applicant. The staff did not identify any omissions. On the

basis of its review, the staff concludes that the applicant has adequately identified the

components of the main steam system that are within the scope of license renewal, as required

by 10 CFR 54.4(a), and that the applicant has adequately identified the components of the main

steam system that are subject to an AMR, as required by 10 CFR 54.4(a)(1).

2.3.4.2 Feedwater System

2.3.4.2.1 Summary of Technical Information in the Application

The applicant described the feedwater system in LRA Section 2.3.4.2 and provided a list of

components subject to AMR in LRA Table 2.3.4-2.

The function of the feedwater system is to deliver condensate from the condenser to the reactor

at a rate of water equivalent to what is being generated into steam by boil-off and removal by

the main steam system. Using the methodology described in LRA Section 2.1.4.1 for

identifying the mechanical components within the scope of license renewal, the applicant

identified the following feedwater system intended functions:

* flowpath-provide flowpath into the reactor pressure vessel for high pressure coolant

injection, reactor water cleanup, and, for Quad Cities only, reactor core isolation cooling and

safe shutdown makeup pump flow

* pressure boundary-maintain the integrity of the reactor coolant pressure boundary

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected

The feedwater system is a two train system consisting of the reactor feed pumps (RFPs),

feedwater regulating valves (FWRVs), high pressure feedwater heaters, piping, isolation valves,

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controls and instrumentation, and subsystems that supply the reactor with regenerative

feedwater heating in a closed steam cycle. The portion of the system from the reactor pressure

vessel to the outermost primary containment isolation valve is safety-related. During normal

plant operation, feedwater is supplied to the system from the outlet of the condensate

demineralizers. The feedwater passes through the RFP and out the discharge check valve into

a common header upstream of the FWRVs. It then passes through FWRVs, which are

mounted in parallel and then again combines into a common header upstream of the high

pressure feedwater heaters. The feedwater is then directed through the high pressure

feedwater heaters and the associated inlet and outlet isolation motor operated valves (MOVs)

to a common header. Flow then passes through the A and B feedwater headers in parallel

through two outboard isolation check valves, one inboard isolation check valve, and an inboard

main isolation valve in each line. Feedwater flow is finally directed into the reactor vessel.

The feedwater system lines are also used to provide a flow path to the reactor vessel for the

HPCI system and the RWCU system.

At Dresden, the HPCI system and RWCU system tap into the "B" feedwater line to inject fluid

during emergency operations (HPCI) or as a return path for water removed from the vessel

(RWCU).

At Quad Cities, the RCIC system and the RWCU system tap into the "A" feedwater line to either

inject fluid during emergency operations or as a return path for water removed from the vessel

(RWCU). Also the Quad Cities HPCI and safe shutdown makeup pump system tap into the B

feedwater line to either inject fluid during emergency operations (HPCI) or as an injection path

for the discharge of the safe shutdown makeup pump.

In LRA Section 2.3.4.2, the applicant described the feedwater system evaluation boundary. In

addition, the applicant highlighted those portions of the feedwater system within the scope of

the Rule in the P&l drawings listed as references in LRA Section 2.3.4.2. Also, based on the

methodology described in LRA Section 2.1.5 for identifying the mechanical components subject

to an AMR, the applicant initially identified the following component groups and their intended

functions within the feedwater system in LRA Table 2.3.4-2 as being within the scope of license

renewal and subject to an AMR:

* closure bolting (pressure boundary)

* NSR vents or drains, piping, and valves (structural integrity/attached support)

* piping and fittings (spatial interaction)

* piping and fittings (structural integrity/attached support)

* small bore piping and fittings (pressure boundary, Quad Cities only)

* valves (pressure boundary)

* valves (structural integrity/attached support)

Resulting from the revised methodology described in the May 18, 2004 response to the draft

SER Open Item 2.1-1, and the licensee response to RAI 2.1-2b, the boundaries of non-safetyrelated sections of the feedwater system at Dresden and Quad Cities were expanded and

highlighted as shown on the revised boundary diagrams. As a result of the scoping

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methodology change the entire feedwater system at both Dreseden' and Quad Cities are

included in the scope of license renewal.

The applicant identified the following additional component groups and their intended functions

within the feedwater system as being within scope of license renewal, and added them to LRA

table 2.3.4.2.

* Piping and Fittings (spatial interaction)

* Pumps (spatial interaction)

* Tubing (spatial interaction)

* Valves (spatial interaction)

2.3.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.2, Dresden UFSAR Section 10.4.7, and Quad Cities

UFSAR Section 10.4.7 to determine whether there is a reasonable assurance that the

feedwater system components within the scope of license renewal and subject to an AMR have

been identified in accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's review

was conducted in accordance with Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the feedwater system in the LRA.

Also, the staff selected system functions described in the UFSARs that were set forth in 10

CFR 54.4 to verify that components having intended functions were not omitted from the scope

of the Rule. The staff also focused on components that were not identified as being subject to

an AMR to determine if any component were omitted.

To verify that the applicant identified the components of the feedwater system that are within

the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10

CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the system

drawings and system descriptions in the UFSARs to ensure that the referenced P&l drawings

were representative of the feedwater system. The staff then reviewed the referenced P&l

drawings to verify that those portions of the feedwater system that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal and are identified

as such by the applicant in LRA Section 2.3.4.2, and that the applicant identified all feedwater

system components within the scope of license renewal and subject to an AMR in accordance

with 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff's review of the LRA identified areas in which additional information is necessary to

complete the staff's review of the applicant's scoping and screening results. Therefore, by the

August 4, 2003, letter, the staff issued RAls to the applicant concerning the specific items to

determine whether the applicant has properly applied the scoping and screening criteria of

10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's RAls and the applicant's responses by letter,

dated October 3, 2003, are described below.

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RAI 2.3.4.2-1. Section 2.3.4-2 of the LRA lists the intended functions for the feedwater system.

The feedwater system interfaces with the primary containment and is safety-related for the

portion of the system from the reactor vessel to the outermost primary containment isolation

valve. Containment isolation is not listed as an intended function. The staff asked the applicant

to provide justification for not including containment isolation as an intended function for the

feedwater system.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.4.2-1, the applicant stated that the portion of the feedwater system from the RPV to the outermost safety-related check valve (primary containment isolation valve)

has the intended function of containment isolation. The containment isolation intended function

should have been included in LRA Section 2.3.4.2 for Dresden and Quad Cities. This does not

affect the aging management of the in-scope components for the feedwater system. The

components providing primary containment isolation also have an intended function of pressure

boundary. Aging management for these affected components is discussed in LRA Section

2.3.4.2, Table 2.3.4-2.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.4.2-1 acceptable because the portion of the feedwater system from the RPV to the outermost safety-related check valve containment isolation is identified as

having an intended function of containment isolation in accordance with the criteria set forth in

10 CFR 54.4 (a)(1). Therefore, the staff considers its concern described in RAI 2.3.4.2-1

resolved.

RAI 2.3.4.2-2. In Dresden Unit 3 drawing LR-DRE-M-347 (E-2), the 0.75 in. line just inside the

outermost check valve shows to be in scope only through valve 3-3299-54; valve 3-3299-120

and the corresponding piping section after the valve is not shown to be in scope. In all other

similar piping sections connected to safety-related piping, the section of piping immediately downstream of the safety-related piping is included in scope per 10 CFR 54.4 (a)(2). The staff

asked the applicant to justify the exclusion of this section of piping from the scope for license

renewal.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.4.2-2, the applicant stated that line 3-32142-3/4*-C on boundary diagram LR-DRE-M-347 (E-2) is a feedwater drain line that includes drain valve 3-3299-54

(inboard, safety-related) and 3-3299-120 (outboard, non-safety-related). Non-safety-related

outboard drain valve 3-3299-120 and the associated piping beyond the safety boundary are in

scope of license renewal for 10 CFR 54.4 (a)(2) criteria. Boundary diagram LR-DRE-M-347

should have highlighted these components to include the outboard drain valve 3-3299-120 and

the associated piping beyond the safety boundary within the scope of license renewal.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.2-2 to be acceptable

because the applicant, in accordance with the criteria set forth in 10 CFR 54.4 identifies drain

valve 3-3299-120 and its associated piping to be within the scope of license renewal, and they

were inadvertently not highlighted in the LR boundary diagrams. Therefore, the staff considers

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its concern described in RAI 2.3.4.2-2 resolved.

2.3.4.2.3 Conclusions

The staff reviewed LRA Section 2.3.4.2, the accompanying scoping boundary drawings, and the

applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. In addition, the staff performed an

independent assessment to determine whether any components that should be subject to an

AMR were not identified by the applicant. The staff did not identify any omissions. On the

basis of its review, the staff concludes that the applicant has adequately identified the

components of the feedwater system that are within the scope of license renewal, as required

by 10 CFR 54.4(a), and that the applicant has adequately identified the components of the

feedwater system that are subject to an AMR, as required by 10 CFR 54.4(a)(1).

2.3.4.3 Condensate and Condensate Storage Systems

2.3.4.3.1 Summary of Technical Information in the Application

The applicant described the condensate and condensate storage systems in LRA Section

2.3.4.3 and provided a list of components subject to AMR in LRA Table 2.3.4-3.

The function of the condensate and condensate storage systems (in conjunction with the

feedwater system) is to provide water of quality and quantity required for operation of the power

plant. Using the methodology described in LRA Section 2.1.4.1 for identifying the mechanical

components within the scope of license renewal, the applicant identified the following

condensate and condensate storage systems intended functions:

* support ESF function(s)-provide reactor grade water to HPCI, RCIC (at Quad Cities), core

spray, LPCI (at Dresden), and RHR (at Quad Cities)

* credited in regulated event(s)-provide water to support mitigating actions for Appendix R

fire, SBO, and ATWS

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected

The condensate and condensate booster pump portion of the system supply reactor quality

demineralized water to the suction of the reactor feedwater pumps. The condensate storage

system's contaminated condensate storage tanks (CCSTs) ensure reactor quality water is

available for makeup requirements, and are designed to ensure a minimum of 90,000 gallons of

water is available from each CCST for use by HPCI. The CCSTs are credited for providing

makeup to the reactor via the CRD pumps (at Dresden) or the RCIC and SSMP systems (at

Quad Cities) for safe shutdown scenarios in the FP Plan. The condensate and systems

pumping functions are not credited to support safe shutdown or to perform any reactor safety

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function.

In LRA Section 2.3.4.3, the applicant described the condensate and condensate storage

system evaluation boundary. In addition, the applicant highlighted those portions of the

systems within the scope of the Rule in the P&l drawings listed as references in LRA Section

2.3.4.3. Also, based on the methodology described in LRA Section 2.1.5 for identifying the

mechanical components subject to an AMR, the applicant initially identified the following

component groups and their intended functions within the condensate and condensate storage

system in LRA Table 2.3.4-3 as being within the scope of license renewal and subject to an

AMR:

* closure bolting (pressure boundary)

* piping and fittings (pressure boundary)

* piping and fittings (spatial interaction, Dresden only)

* piping and fittings (structural integrity/attached support, Quad Cities only)

* tanks (pressure boundary)

* thermowells (pressure boundary, Dresden only)

* tubing (pressure boundary)

* valves (pressure boundary)

* valves (structural integrity/attached support, Quad Cities only)

Resulting from the revised methodology described in the May 18, 2004 response to the draft

SER Open Item 2.1-1, the boundaries of non-safety-related sections of the condensate and

condensate storage system at Dresden and Quad Cities were expanded and highlighted as

shown on the revised boundary diagrams, and the newly added boundary diagrams. With the

exception of the condensate demineralizers, steam jet air ejectors, and gland steam

condensers, which reside in their own rooms isolated from safety-related equipment, the entire

condensate and condensate storage systems at Dresden and Quad Cities were added to the

scope of license renewal. This included condensate transfer pumps, condensate jocky pumps,

and associated suction and discharge piping. The only component not included is the Dresden

Unit 1 contaminated demineralized water storage tank which the applicant states was not

included in the scope of license renewal because it is located outside the plant away from

safety-related equipment.

The applicant identified the following additional component groups and their intended functions

within the condensate and condensate storage system as being within scope of license

renewal, and added them to LRA table 2.3.4.3.

* Piping and Fittings (includes strainers, flow elements, thermocouples and heat exchangers)

(spatial interaction)

* Pumps (spatial interaction)

* Tanks (spatial interaction)

* Tubing (spatial interaction)

* Valves (spatial interaction)

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Components that were added to scope only because of their leakage boundary (spatial)

function were grouped such that those that are comprised of the same material and exposed to

the same environment were grouped together. This grouping results in the inclusion of drain

coolers (heat exchangers), feedwater heaters (heat exchangers), strainers, flow elements, and

thermocouples in the component group for piping and fittings. This grouping is valid since for

these components only the leakage boundary (spatial) function must be maintained and require

aging management.

2.3.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.3, Dresden UFSAR Sections 9.2.6 and 10.4.7, and Quad

Cities UFSAR Sections 9.2.6 and 10.4.7 to determine whether there is a reasonable assurance

that the condensate and condensate storage system components within the scope of license

renewal and subject to an AMR have been identified in accordance with 10 CFR 54.4 and 10

CFR 54.21(a)(1). The staff's review was conducted in accordance with Section 2.3 of NUREG1800.

In performance of the review, the staff reviewed the UFSARs to determine if there were any -

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the condensate and condensate storage system in the LRA. The

staff did not identify any omissions.

Also, the staff selected system functions described in the UFSARs that were set forth in 10

CFR 54.4 to verify that components having intended functions were not omitted from the scope

of the Rule. The staff also focused on components that were not identified as being subject to

an AMR to determine if any components were omitted.

To verify that the applicant identified the components of the condensate and condensate

storage system that are within the scope of license renewal and subject to an AMR in

accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1), respectively, the staff compared the

referenced P&l drawings to the system drawings and system descriptions in the UFSARs to

ensure that the referenced P&l drawings were representative of the condensate and

condensate storage system. The staff then reviewed the referenced P&l drawings to verify that

those portions of the condensate and condensate storage system that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal and are identified

as such by the applicant in LRA Section 2.3.4.3, and that the applicant identified all condensate

and condensate storage system components within the scope of license renewal and subject to

an AMR in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff's review of the LRA identified one area in which additional information is necessary to

complete the staff's review of the applicant's scoping and screening results. Therefore, by the

August 4, 2003, letter, the staff issued an RAI to the applicant concerning the specific item to

determine whether the applicant has properly applied the scoping and screening criteria of

10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff's RAI, and the applicant's responses by letter,

dated October 3, 2003, are described below.

RAI 2.3.4.3-1. In Quad Cities drawing LR-QDC-M-16-5 (D-5), lines 0-33107A and 0-33108A,

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and valves 0-3399-227A and 0-3399-228A, are identified as not in scope for license renewal.

These lines connect level switch LS 0-3341-71 A, which is shown as in scope, to line 0-3348,

which is also shown to be in scope. The staff asked the applicant to clarify whether these SSCs

should be included in scope for license review.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.4.3-1, the applicant stated that isolation valves 0-3399-227A and 0-

3399-228A for LS-0-3341-71 A and the connecting piping 0-33107A-1 " and 0-33108A-1" are in

scope of license renewal. Boundary diagram LR-QDC-M-16-5 should have highlighted these

components designating them within the scope of license renewal. Aging management for the

valves is addressed in LRA Table 2.3.4-3, under the component group "valves," and component

intended function of "pressure boundary." Aging management for the connecting piping is

addressed in LRA Table 2.3.4-3, under component group "piping and fittings," and component

intended function of "pressure boundary."

Based on its review of the applicant's clarification discussed above, the staff concurs with the

applicant's clarification that the above-cited segments of piping and their associated

components are within the scope of the Rule, and were inadvertently not highlighted in the LR

boundary diagram. The staff also concurs with the applicant that the components associated

with the cited segments of piping are included in LRA Table 2.3.4-3, subject to an AMR, in

accordance with the criteria set forth in 10 CFR 54.21(a)(1). Therefore, the staff finds the

applicant's response to RAI 2.3.4.3-1 acceptable and considers its concern described in RAI

2.3.4.3-1 resolved.

2.3.4.3.3 Conclusions

The staff reviewed LRA Section 2.3.4.3, the accompanying scoping boundary drawings, and the

applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. In addition, the staff performed an

independent assessment to determine whether any components that should be subject to AMR

were not identified by the applicant. The staff did not identify any omissions. On the basis of its

review, the staff concludes that the applicant has adequately identified the components of the

condensate and condensate storage system that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and that the applicant has adequately identified the components of

the condensate and condensate storage system that are subject to an AMR, as required by 10

CFR 54.4(a)(1).

2.3.4.4 Main Condenser

2.3.4.4.1 Summary of Technical Information in the Application

The applicant described the main condenser in LRA Section 2.3.4.4 and provided a list of

components subject to AMR in LRA Table 2.3.4-4.

The function of the main condenser is to-provide a heat sink for the turbine exhaust steam;

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condense the bypass steam after a turbine trip; accommodate feedwater heater drains,

extraction steam, and steam line'condensate routed to the condenser during operation with

feedwater heaters out of service; retain the condensate for a brief time to allow for the decay of

short-lived isotopes; deaerate the condensate and remove fission product gases, hydrogen,

and oxygen; provide adequate net positive suction head for condensate pumps; and provide for

iodine plateout and radioactive decay prior to release.

Using the methodology described in LRA Section 2.1.4.1 for identifying the mechanical

components within the scope of license renewal, the applicant identified the following main

condenser intended function:

post accident containment, holdup and plateout of MSIV bypass leakage-the main

condenser provides for post accident containment, holdup and plateout of MSIV bypass

leakage

The main condenser is a divided water flow, single-pass, multipressure, deaerating type

condenser, with capacity for reverse flow for each half of the condenser. The divided water flow

permits circulating water to be reversed periodically through each bank of tubes in each half of

the condenser for cleaning purposes. The condenser shell is supported on the turbine

foundation mat. An expansion joint is fitted between each low-pressure turbine exhaust hood

and condenser inlet connection. The condenser is divided into three separate compartments by

two division plates.

The main condenser is credited in Dresden UFSAR Section 15.6 and Quad Cities UFSAR

Section 15.6 for providing post accident containment, holdup and plateout of MSIV bypass

leakage. The radiological consequences for the control room LOCA dose analysis assumes

MSIV leakage travels down the steam piping to the turbine-condenser complex where it is

released as a ground level release at a rate of 1 percent of the turbine condenser volume per

day to the turbine building and then exhausted by the HVAC system if it was operating.

In LRA Section 2.3.4.4, the applicant described the main condenser evaluation boundary. In

addition, the applicant highlighted those portions of the main condenser within the scope of the

Rule in the P&l drawings listed as references in LRA Section 2.3.4.4. Also, based on the

methodology described in LRA Section 2.1.5 for identifying the mechanical components subject

to an AMR, the applicant initially identified the following component groups and their intended

functions within the main condenser system in LRA Table 2.3.4-4 as being within the scope of

license renewal and subject to an AMR:

* main condenser hotwells and false floors, including hatches (containment holdup and

plateout)

* main condenser tubes, including tubesheets and hatches (containment holdup and plateout)

* main condenser waterboxes and hatches (containment holdup and plateout)

Resulting from the revised methodology described in the May 18, 2004 response to the draft

SER Open Item 2.1-1 the main condenser, which was originally included within the scope of

license renewal at both Dresden and Quad Cities for post accident containment holdup and

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plateout, has also been brought into scope of license renewal for spatial interaction at Quad

Cities station . The main condenser at Quad Cities is a non-safety-related component that

resides in the same general area as the discharge piping from the emergency diesel cooling

water system and thus the potential for spatial interaction could occur. The licensee states that

this change only applies to Quad Cities as the same physical equipment configuration does not

exist at Dresden.

The applicant has added the following system intended function to LRA section 2.3.4.4

Preclude adverse effects on safety-related SSCs - Non-safety-related components that could

be hazard to safety-related SSCs maintain sufficient integrity so that the intended function of

safety-related SSCs is not adversely affected.

The applicant identified the following additional component groups and their intended functions

for the Quad Cities Main Condenser as being within scope of license renewal, and added them

to LRA table 2.3.4.4.

* Main Condenser Hotwells, False Floors (spatial interaction, Quad Cities only)

(includes hatches)

* Main Condenser Waterboxes, hatches (spatial interaction, Quad Cities only)

2.3.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.4, Dresden UFSAR Sections 10.4 and 15.6.5.5.2, and

Quad Cities UFSAR Sections 10.4 and 15.6.5.5.3 to determine whether there is a reasonable

assurance that the main condenser system components within the scope of license renewal

and subject to an AMR have been identified in accordance with 10 CFR 54.4 and 10 CFR

54.21(a)(1). The staff's review was conducted in accordance with Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the main condenser system in the LRA.

Also, the staff selected system functions described in the UFSARs that were set forth in 10

CFR 54.4 to verify that components having intended functions were not omitted from the scope

of the Rule. The staff also focused on components that were not identified as being subject to

an AMR to determine if any component were omitted.

To verify that the applicant identified the components of the main condenser system that are

within the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and

10 CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the

system drawings and system descriptions in the UFSARs to ensure that the referenced P&l

drawings were representative of the main condenser system. The staff then reviewed the

referenced P&l drawings to verify that those portions of the main condenser system that meet

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the scoping requirements of 10 CFR 54.4 are included within the scope of license renewal and

are identified as such by the applicant in LRA Section 2.3.4.4, and that the applicant identified

all main condenser system components within the scope of license renewal and subject to an

* AMR in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff's review of the LRA identified areas in which additional information is necessary to

complete the staff's review of the applicant's scoping and screening results. Therefore, by the

August 4, 2003, letter, the staff issued RAls to the applicant concerning the specific items to

determine whether the applicant has properly applied the scoping and screening criteria of

10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's RAls and the applicant's responses by letter,

dated October 3, 2003, are described below.

RAI 2.3.4.4-1. In Section 2.3.4.4 of the LRA, it is indicated that an expansion joint is fitted

between each low-pressure turbine exhaust hood and condenser inlet connection. These

expansion joints are not included as a component group requiring AMR in Table 2.3.4-4. The

staff asked the applicant to justify the exclusion of the expansion joints from the list of

components requiring AMR.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.4.4-1, the applicant stated that the condenser does not need a

"pressure boundary" function. Holdup of radioiodines and noble 'gases that leak past the closed

MSIVs is credited in the Dresden and Quad Cities LOCA and control rod drop accident (CRDA)

analyses. Holdup is a function of the main condenser volume and leak rate. The Dresden and

Quad Cities analyses assume the main condensers leak to the atmosphere at a rate of 1

percent per day throughout the accident. This value is a generic licensing basis assumption in

SRP Section 15.4.9, "Radiological Consequences of Control Rod Drop Accident." This

assumed leakage is larger than the actual leakage past the closed MSIVs into the main

condenser. Therefore the condenser does not have to be leak tight.

The staff finds the applicant's response to RAI 2.3.4.4-1 acceptable since the limiting leak rate

of the MSIV leakage from the condenser, used in the radiological analyses, did not credit the

expansion joint between the turbine and the condenser inlet with providing a leak tight seal.

Therefore, the staff considers its concern described in RAI 2.3.4.4-1 resolved.

RAI 2.3.4.4-2. In Table 2.3.4-4 the condenser shell is not included as a component group

requiring AMR. The staff feels that this component is necessary to support the system intended

function, and provides the component intended function of containment holdup and plateout,

and thus should be included in Table 2.3.4-4.- The staff asked the applicant to justify the

exclusion of the condenser shell from the list of components requiring AMR.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.4.4-2, the applicant stated that the condenser shell is included in

LRA Table 2.3.4-4, in the component group "main condenser hotwells, false floors (including

hatches)."

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The staff finds the applicant's clarification described above acceptable because the condenser

shell is included in LRA Table 2.3.4-4, as subject to an AMR. Therefore, the staff considers its

concern described in RAI 2.3.4.4-2 resolved.

2.3.4.4.3 Conclusions

The staff reviewed LRA Section 2.3.4.4 , the accompanying scoping boundary drawings, and

the applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. In addition, the staff performed an

independent assessment to determine whether any components that should be subject to AMR

were not identified by the applicant. The staff did not identify any omissions. On the basis of its

review, the staff concludes that the applicant has adequately identified the components of the

main condenser system that are within the scope of license renewal, as required by 10 CFR

54.4(a), and that the applicant has adequately identified the components of the main condenser

system that are subject to an AMR, as required by 10 CFR 54.4(a)(1).

2.3.4.5 Main Turbine and Auxiliary Systems

2.3.4.5.1 Summary of Technical Information in the Application

The applicant described the main turbine and auxiliary systems in LRA Section 2.3.4.5 and

provided a list of components subject to AMR in LRA Table 2.3.4-5.

The function of the main turbine is to convert the thermodynamic energy of reactor steam into

rotational mechanical energy to drive the main generator. Using the methodology described in

LRA Section 2.1.4.1 for identifying the mechanical components within the scope of license

renewal, the applicant identified the following main turbine and auxiliary system intended

function:

preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected

The main turbine and auxiliary systems consist of one high-pressure section and three lowpressure sections. Turbine steam flow is controlled by a set of four turbine control valves on

the high-pressure element main steam supply. Steam is delivered from the reactor pressure

vessel through four main steam lines and the turbine throttle to the main stop valves, or to other

loads of the main steam system. From the main stop valved, steam is passed through the

steam chest (the area from below the seats of the main stop valves to the turbine control valve

seats), through the turbine control valves, and then through the high-pressure turbine section.

The steam is then routed to four moisture separators, where steam drying occurs. The dry

steam is admitted through six combined intercept valves to the low-pressure turbine sections

and exhausted to the main condenser.

The main turbine is supported by auxiliary systems. The gland sealing system provides glandsealing steam to the high-pressure and low-pressure turbine glands to prevent steam from

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entering the turbine building and norcondensables from entering the condenser. The exhaust

hood spray system provides cooling water to the condenser exhaust hood at low load, when

steam flow through the last few turbine stages is low and insufficient cooling is provided. The

turbine electrohydraulic control system provides high-pressure fluid and logic to control the

turbine main stop valves, turbine control valves, combined intermediate valves, bypass valves,

and the reactor pressure through pressure regulators.

The main turbine and auxiliary system starts with the steam chest (after the main stop valves)

and ends at the condenser. Main turbine includes the steam chest, turbine control valves,

turbine bypass valves, main turbine, moisture separator tanks, combined intermediate valves,

low-pressure turbines, and associated piping, valves, instrumentation, and controls. Auxiliary

systems include electrohydraulic control, off-gas booster air ejectors, turbine gland sealing,

exhaust hood spray, gland seal exhaust, steam supply to steam jet air ejectors, and associated

piping, valves, instrumentation, and controls.

In LRA Section 2.3.4.5, the applicant described the main turbine and auxiliary system

evaluation boundary. In addition, the applicant highlighted those portions of the main turbine

and auxiliary systems within the scope of the Rule in the P&l drawings listed as references in

LRA Section 2.3.4.5. Also, based on the methodology described in LRA Section 2.1.5 for

identifying the mechanical components subject to an AMR, the applicant identified the following

component groups and their intended functions within the main turbine and auxiliary system in

LRA Table 2.3.4-5 as being within the scope of license renewal and subject to an AMR:

* accumulators (spatial interaction)

* closure bolting (pressure boundary)

* piping and fittings (spatial interaction)

* tubing, including flex hoses (spatial interaction)

* valves, including flex hoses (spatial interaction)

Resulting from the revised methodology described in the May 18, 2004 response to the draft

SER Open Item 2.1-1, the boundaries of non-safety-related sections of the main turbine and

auxiliary system at Dresden and Quad Cities were expanded and highlighted as shown on the

revised boundary diagrams and additional new boundary diagrams. Based on the revised

methodology the entire main turbine and auxiliary system is within the scope of license renewal

at both plants. The expanded scope adds portions of the electohydraulic control (EHC) system

that had previously been excluded from scope based on the original methodology. Additional

components such as ECH pumps, coolers, strainers, filters, accumulators and the EHC fluid

reservoir are now brought into scope of license renewal.

The applicant identified the following additional component groups and their intended functions

within the main turbine and auxiliary system as being within scope of license renewal, and

added them to LRA table 2.3.4.5.

Filters/Strainers (spatial interaction)(includes oil mist eliminators and vapor extractors)

! Pump Casing (spatial interaction)

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* Tanks (spatial interaction)

The applicant states that EHC coolers, strainers, and filters were evaluated with the

"Filter/Strainers' component group for aging management and that the EHC reservoirs were

evaluated with an existing component group already included in Table 2.3.4-5 titled

Accumulators. The EHC coolers (Heat Exchangers) were added to the scope of license renewal

for spatial interaction only; therefore, only the leakage boundary (spatial) function must be

maintained and require aging management. The EHC coolers were included in the

Filter/Strainers component group because the leakage boundary of the EHC coolers (Heat

Exchangers) is comprised of the same materials and experience the same environment as the

components evaluated under the "Filter/Strainers (spatial interaction)" component group.

2.3.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.5, Dresden UFSAR Sections 7.7.4 and 10.2, and Quad

Cities UFSAR Sections 7.7.4 and 10.2 to determine whether there is a reasonable assurance

that the main turbine and auxiliary system components within the scope of license renewal and

subject to an AMR have been identified in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1). The staff's review was conducted in accordance with Section 2.3 of NUREG-1 800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the main turbine and auxiliary system in the LRA. The staff did not

identify any omissions.

Also, the staff selected system functions described in the UFSARs that were set forth in 10

CFR 54.4 to verify that components having intended functions were not omitted from the scope

of the Rule. The staff also focused on components that were not identified as being subject to

an AMR to determine if any component were omitted.

To verify that the applicant identified the components of the main turbine and auxiliary system

that are within the scope of license renewal and subject to an AMR in accordance with 10 CFR

54.4 and 10 CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to

the system drawings and system descriptions in the UFSARs to ensure that the referenced P&l

drawings were representative of the main turbine and auxiliary system. The staff then reviewed

the referenced P&l drawings to verify that those portions of the main turbine and auxiliary

system that meet the scoping requirements of 10 CFR 54.4 are included within the scope of

license renewal and are identified as such by the applicant in LRA Section 2.3.4.5, and that the

applicant identified all main turbine and auxiliary system components within the scope of license

renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff found that those portions of the main turbine and auxiliary systems that meet the

scoping requirements of 10 CFR 54.4 are included within the scope of license renewal and are

identified as such by the applicant in LRA 2.3.4.5. The main turbine and auxiliary systems

components that are subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1) are included in LRA Table 2.3.4-5. The staff did not identify any omissions.

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2.3.4.5.3 Conclusions

The staff reviewed LRA Section 2.3.4.5 and accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. The

staff did not identify any omissions. On the basis of its review, the staff concludes that the

applicant has adequately identified the components of the main turbine and auxiliary systems

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the

applicant has adequately identified the components of the main turbine and auxiliary systems

that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.4.6 Turbine Oil System

2.3.4.6.1 Summary of Technical Information in the Application

The applicant described the turbine oil system in LRA Section 2.3.4.6 and provided a list of

components subject to AMR in LRA Table 2.3.4-6.

The function of the turbine oil system is to supply all the necessary lubricating oil to the main

turbine and its support systems to allow the turbine to operate properly. Using the methodology

described in LRA Section 2.1.4.1 for identifying the mechanical components within the scope of

license renewal, the applicant identified the following turbine oil system intended function:

preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function -of safety-related SSCs is not adversely affected

The system is required to be in service during startups, normal operations, shutdowns, and at

any time the turbine is on the turning gear. Depending upon the operating status of the turbine,

the turbine oil system uses one of six oil pumps to transfer oil from the lube oil reservoir to the

turbine generator components. The oil is cooled and filtered as necessary prior to delivery to

the components.

Major system components include main turbine oil reservoir, oil driven turbine and booster

pump, turbine oil coolers, vapor extractor, and the turbine oil filter and pumps. Also included

are the turbine bearing oil lift pumps, emergency seal oil pump, main seal oil pump,

recirculating seal oil pump, seal oil vacuum pump, hydrogen seal oil vacuum tank, and the bulk

lubricating oil storage and transfer system. Additionally included are the system piping, valves,

and instrumentation and controls to fill the turbine oil tank, and to supply oil from the turbine oil

tank to the main turbine lubricating oil system, hydrogen seal oil system, reactor feed pumps,

and HPCI turbine lubricating oil and recirculation MG set lubricating oil systems.

In LRA Section 2.3.4.6, the applicant described the turbine oil system evaluation boundary. In

addition, the applicant highlighted those portions of the turbine oil system within the scope of

the Rule in the P&l drawings listed as references in LRA Section 2.3.4.6. Also, based on the

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methodology described in LRA Section 2.1.5 for identifying the mechanical components subject

to an AMR, the applicant initially identified the following component groups and their intended

functions within the plant heating system in LRA Table 2.3.4-6 as being within the scope of

license renewal and subject to an AMR:

* closure bolting (pressure boundary)

* filters/strainers (spatial interaction)

* piping and fittings (spatial interaction)

* piping and fittings (structural integrity/attached support)

* pump casings (spatial interaction)

* tanks (spatial interaction)

* valves (spatial interaction)

* valves (structural integrity/attached support)

Resulting from the revised methodology described in the May 18, 2004 response to the draft

SER Open Item 2.1-1, the boundaries of non-safety-related sections of the turbine oil system at

Quad Cities were expanded and highlighted as shown on the revised boundary diagrams and

the newly added boundary diagrams. In addition, the turbine oil system, including the hydrogen

seal oil subsystem was brought into scope of license renewal at Dresden station and new

boundary drawing identifying the SSCs in scope of licensee renewal were provided by the

licensee.

The applicant identified the following additional component groups for Dresden and their

intended functions within the turbine oil system as being within scope of license renewal, and

added them to LRA table 2.3.4.6.

* Closure Bolting (pressure boundary)

* Filters/Strainers (spatial interaction)

* Piping and Fittings (includes oil mist eliminator and vapor extractor) (spatial interaction)

* Pump Casings (spatial interaction)

* Tanks (spatial interaction)

* Valves (spatial interaction)

Aging management references for the components added to the scope of license renewal

based on the revised methodology are already included in LRA Table 2.3.4-6, because the

scope is no longer limited to Quad Cities, and now include both Dresden and Quad Cities, the

additional components were added to the table by removing the Quad Cities only notation for

the components identified in Table 2.3.4-6.

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The lube oil mist eliminator and Vapor Extractor were added to the scope of license renewal for

spatial interaction, typical component functions such as "Filtration" or "Pressure Boundary' do

not require aging management and only the "Leakage boundary (spatial) function must be

maintained and requires aging management. Since the leakage boundary of the lube oil mist

eliminator and vapor extractor are comprised of the same material and experience the same

environment as the components evaluated under the "Piping and Fitting (spatial interaction)"

component group, they have been included as part of the "Piping and Fitting (spatial

interaction)" component group in Table 2.3.4-6.

2.3.4.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.6 to determine whether there is a reasonable assurance

that the turbine oil system components within the scope of license renewal and subject to an

AMR have been identified in accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff's

review was conducted in accordance with Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSARs to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the turbine oil system in the LRA. The staff did not identify any

omissions.

Also, the staff selected system functions described in the UFSAR that were set forth in 10 CFR

54.4 to verify that components having intended functions were not omitted from the scope of

the Rule. The staff also focused on components that were not identified as being subject to an

AMR to determine if any component were omitted.

To verify that the applicant identified the components of the turbine oil system that are within

the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10

CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l drawings to the system

drawings and system descriptions in the UFSARs to ensure that the referenced P&l drawings

were representative of the turbine oil system. The staff then reviewed the referenced P&I

drawings to verify that those portions of the turbine oil system that meet the scoping

requirements of 10 CFR 54.4 are included within the scope of license renewal and are identified

as such by the applicant in LRA Section 2.3.4.6, and that the applicant identified all turbine oil

system components within the scope of license renewal and subject to an AMR in accordance

with 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff's review of the LRA identified one area in which additional information is necessary to

complete the staff's review of the applicant's scoping and screening results. Therefore, by the

August 4, 2003, letter, the staff issued an RAI to the applicant concerning the specific item to

determine whether the applicant has properly applied the scoping and screening criteria of

10 CFR 54.4 and 10 CFR 54.21 (a)(1). The staff's RAI and the applicant's responses by letter,

dated October 3, 2003, are described below.

RAI 2.3.4.6-1. The portion of turbine oil system, line 2-2362-2 shown on drawing LR-QDC-M48-1 (GI) and continued on LR-QDC-M-87-3 (D6), that goes to the Unit 2 HPCI oil junction box

is not identified as being in scope. The corresponding line to the Unit 1 oil junction box is

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shown as in scope. The staff asked the applicant to indicate whether this portion of the line

should be included in scope and whether drawing LR-QDC-M-87 should be included as a

reference in LRA Section 2.3.4.6.

Applicant's Response and Staff's Evaluation

In the response to RAI 2.3.4.6-1, the applicant stated that at the time that Exelon was

completing the scoping and screening of the turbine oil system, a modification installation was

in progress to remove both the Quad Cities Unit 1 and Unit 2 HPCI dirty oil transfer pumps and

associated piping. As part of the modification, the 2 in. non-safety-related lines that penetrate

the HPCI oil junction box were to be cut and capped. At the time that the scoping and

screening was being performed, the HPCI turbine oil transfer line 2-2362-2" to the Unit 2 HPCI

system was cut and capped prior to entering the HPCI oil junction box. Therefore, the small

portion of non-safety-related turbine oil piping downstream of the cap was not included in scope

of license renewal. The Unit 1 line had not yet been cut and capped, and was therefore

included in scope. The present status is that the modification is complete and the lines on both

units have been cut and capped.

Based on its review of the applicant's clarification discussed above, the staff finds the

applicant's response to RAI 2.3.4.6-1 acceptable because a modification installation was

performed to remove both the Quad Cities Unit 1 and Unit 2 HPCI dirty oil transfer pumps and

associated piping. The subject lines on both units have been cut and capped. Therefore, the

staff considers its concern described in RAI 2.3.4.6-1 resolved.

2.3.4.6.3 Conclusions

The staff reviewed LRA Section 2.3.4.6 , the accompanying scoping boundary drawings, and

the applicant's response to RAls, to determine whether any SSCs within the scope of license

renewal had not been identified by the applicant. In addition, the staff performed an

independent assessment to determine whether any components that should be subject to AMR

were not identified by the applicant. The staff did not identify any omissions. On the basis of its

review, the staff concludes that the applicant has adequately identified the components of the

turbine oil system that are within the scope of license renewal, as required by 10 CFR 54.4(a),

and that the applicant has adequately identified the components of the turbine oil system that

are subject to an AMR, as required by 10 CFR 54.4(a)(1).

2.3.4.7 Main Generator and Auxiliary Systems

2.3.4.7.1 Summary of Technical Information in the Application

The applicant described the main generator and auxiliary systems in LRA Section 2.3.4.7 and

provided a list of components subject to AMR in LRA Table 2.3.4-7.

The function of the main generator is to convert the mechanical energy of the turbine into

electrical energy. Using the methodology described in LRA Section 2.1.4.1 for identifying the

mechanical components within the scope of license renewal, the applicant identified the

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following main generator and auxiliary systems intended function; s

* preclude adverse effects on safety-related SSCs-maintains sufficient integrity of nonsafety-related components that could be a hazard to safety-related SSCs so that the

intended function of safety-related SSCs is not adversely affected

The main generator and auxiliary systems consist of the main generator, main exciter, main

generator stator coolers, and the isolated phase bus system. The stator water cooling system

removes the heat produced by heating losses and removes the heat produced in the main

generator field rectifiers. The isolated phase bus system cools the conductors, which connect

the generator to the main transformer. The main generator exciter provides regulated

excitation to the generator field windings to control generator output voltage and current. The

main generator stator coolers provide clean, de-ionized cooling water to the stator and exciter

during plant operation. The isolated phase bus electrically connects the main generator and the

unit auxiliary transformer, and cools the main phase conductors.

In LRA Section 2.3.4.7, the applicant described the main generator and auxiliary systems

evaluation boundary. In addition, the applicant highlighted those portions of the main generator

and auxiliary systems within the scope of the Rule in the P&l drawings listed as references in

LRA Section 2.3.4.7. Also, based on the methodology described in LRA Section 2.1.5 for

identifying the mechanical components subject to an AMR, the applicant identified the following

component groups and their intended functions within the plant heating system in LRA Table

2.3.4-7 as being within the scope of license renewal and subject to an AMR:

* closure bolting (pressure boundary)

* heat exchangers (spatial interaction)

* housings heat exchangers (spatial interaction)

* piping and fittings (spatial interaction)

* pumps (spatial interaction)

* tanks (spatial interaction)

* valves (spatial interaction)

Resulting from the revised methodology described in the May 18, 2004 response to the draft

SER Open Item 2.1-1, the boundaries of non-safety-related sections of the main generator and

auxiliaries were expanded and highlighted as shown on the revised boundary diagrams and the

additional new boundary diagrams. The original scoping results described in section 2.3.4.7 of

the LRA only included a portion of the main generator and auxiliaries (Stator Cooling) at Quad

Cities. Portions of the stator cooling system were excluded under the old methodology has

been brought into scope of license renewal based on application of the revised methodology.

As a result of the change in methodology the entire main generator and auxiliaries system was

brought into scope of license renewal at Dresden station and new boundary drawing identifying

the SSCs in scope of licensee renewal were provided by the licensee. The change in

methodology has resulted in the addition of the entire main generator and auxiliaries system

within the scope of license renewal at both sites.

The applicant identified the following additional component groups for Dresden and their

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;I

intended functions within the turbine oil system as being within scope of license renewal, and

added them to LRA table 2.3.4.7.

* Heat Exchangers (spatial interaction)

* Housings (spatial interaction)

* Piping and Fittings (includes filters and demineralizers) (spatial interaction)

* Pump (spatial interaction)

* Tanks (spatial interaction)

* Valves (spatial interaction)

Aging management references for the components added to the scope of license renewal

bases on the revised methodology are already included in LRA Table 2.3.4-7, because the

scope is no longer limited to Quad Cities, and now include both Dresden and Quad Cities, the

additional components were added to the table by removing the Quad Cities only notation for

the components identified in Table 2.3.4-7.

The filters, generator filters, and stator water demineralizes highlighted on the boundary

diagrams were added to the scope of license renewal for spatial interaction. Typical component

functions such as "Filtration" or 'Pressure Boundary' do not require aging management and

only the "Leakage boundary (spatial) function must be maintained and requires aging

management. Since the leakage boundary of the these components are comprised of the

same material and experience the same environment as the components evaluated under the

"Piping and Fitting (spatial interaction)" component group they have been included as part of

the "Piping and Fitting (spatial interaction)" component group in Table 2.3.4-7.

2.3.4.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.7 and Quad Cities UFSAR Section 8.3 to determine

whether there is a reasonable assurance that the main generator and auxiliary systems

components within the scope of license renewal and subject to an AMR have been identified in

accordance with 10 CFR 54.4 and 10 CFR54.21 (a)(1). The staff's review was conducted in

accordance with Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSAR to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the main generator and auxiliary systems in the LRA. The staff did

not identify any omissions.

Also, the staff selected system functions described in the UFSAR that were set forth in 10 CFR

54.4 to verify that components having intended functions were not omitted from the scope of

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the Rule. The staff also focused on components that were not identified as being subject to an

AMR to determine if any component were omitted.

To verify that the applicant identified the components of the main generator and auxiliary

systems that are within the scope of license renewal and subject to an AMR in accordance with

10 CFR 54.4 and 10 CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l

drawings to the system drawings and system descriptions in the UFSARs to ensure that the

referenced P&l drawings were representative of the main generator and auxiliary systems. The

staff then reviewed the referenced P&l drawings to verify that those portions of the main

generator and auxiliary systems that meet the scoping requirements of 10 CFR 54.4 are

included within the scope of license renewal and are identified as such by the applicant in LRA

Section 2.3.4.7, and that the applicant identified all main generator and auxiliary systems

components within the scope of license renewal and subject to an AMR in accordance with 10

CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff found that those portions of the main generator and auxiliary systems that meet the

scoping requirements of 10 CFR 54.4 are included within the scope of license renewal and are

identified as such by the applicant in LRA Section 2.3.4.7. The main generator and auxiliary

systems components that are subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1) are included in LRA Table 2.3.4-7. The staff did not identify any omissions.

2.3.4.7.3 Conclusions

The staff reviewed LRA Section 2.3.4.7 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. The

staff did not identify any omissions. On the basis of its review, the staff concludes that the

applicant has adequately identified the components of the main generator and auxiliary systems

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the

applicant has adequately identified the components of the main generator and auxiliary systems

that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.4.8 Extraction Steam System (Quad Cities Only)

As a result of the revised scoping methodology, the extraction steam was added to the scope of

license renewal at Quad Cities. Specifically, the entire extraction steam piping system was

added to the scope of license renewal because the system could spatially interact with safetyrelated pipe located in the feedwater heater area.

2.3.4.8.1 Summary of Technical Information in the Application

The applicant described the extraction steam system in LRA Section 2.3.4.8 and provided a list

of components subject to AMR in LRA Table 2.3.4-8. This LRA section was not included in the

original LRA but was added to the scope of license renewal at Quad Cities as a result of the

revised scoping methodology and was provided to the staff in the applicants response to the

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I

draft SER Open Item 2.1-1.

The function of the extraction steam system is to preheat feedwater as it passes through the

feedwater heaters prior to being returned to the reactor vessel. Using the methodology

described in LRA Section 2.1.4.1 for identifying the mechanical components within the scope of

license renewal, the applicant identified the following extraction steam system intended

function:

preclude adverse effects on safety-related SSCs- Non-safety-related components that

could be a hazard to safety-related SSCs maintain sufficient integrity so that the intended

function of safety-related SSCs is not adversely affected.

The extraction steam system extracts steam from various points on the main turbine and routes

it along with water from the moister separator drains to the feedwater heaters. The steam is

then added to heat the condensate and feedwater which flows through the tube side of the

feedwater heaters and flash tanks. Extraction steam provides the major heat source during

normal operation of the feedwater heaters.

The extraction steam system boundary includes piping and valves that supply extraction steam

from the low pressure turbine exhaust piping interface to the A, B, and C feedwater heaters and

flash tanks. This includes pipe, valves, and associated instrumentation.

In LRA Section 2.3.4.8, the applicant described the extraction steam system evaluation

boundary. In addition, the applicant highlighted those portions of the main generator and

auxiliary systems within the scope of the Rule in the P&I drawings listed as references in LRA

Section 2.3.4.8. Also, based on the methodology described in LRA Section 2.1.5 for identifying

the mechanical components subject to an AMR, the applicant identified the following

component groups and their intended functions within the plant heating system in LRA Table

2.3.4-8 as being within the scope of license renewal and subject to an AMR:

* Piping and Fittings (spatial interaction, Quad Cities only)

* Valves (spatial interaction, Quad Cities only))

The LP heaters and Heater Flash Tanks that are highlighted on the boundary drawings for this

system are in scope of license renewal and require aging management are evaluated as part of

the Condensate and Condensate Storage System which is discussed in LRA Section 2.3.4.3.

2.3.4.8.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.8 and Quad Cities UFSAR Sections 10.1 and 10.4 to

determine whether there is a reasonable assurance that the extraction steam system

components within the scope of license renewal and subject to an AMR have been identified in

accordance with 10 CFR 54.4 and 10 CFR54.21 (a)(1). The staff's review was conducted in

accordance with Section 2.3 of NUREG-1800.

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In the performance of the review, the staff reviewed the UFSAR to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the main generator and auxiliary systems in the LRA. The staff did

not identify any omissions.

Also, the staff selected system functions described in the UFSAR that were set forth'in 10 CFR

54.4 to verify that components having intended functions were not omitted from the scope of

the Rule. The staff also focused on components that were not identified as being subject to an

AMR to determine if any component were omitted.

To verify that the applicant identified the components of the main generator and auxiliary

systems that are within the scope of license renewal and subject to an AMR in accordance with

10 CFR 54.4 and 10 CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l

drawings to the system drawings and system descriptions in the UFSARs to ensure that the

referenced P&l drawings were representative of the main generator and auxiliary systems. The

staff then reviewed the referenced P&l drawings to verify that those portions of the main

generator and auxiliary systems that meet the scoping requirements of 10 CFR 54.4 are

included within the scope of license renewal and are identified as such by the applicant in LRA

Section 2.3.4.8, and that the applicant identified all main generator and auxiliary systems

components within the scope of license renewal and subject to an AMR in accordance with 10

CFR 54.4 and 10 CFR 54.21 (a)(1).

The staff found that those portions of the main generator and auxiliary systems that meet the

scoping requirements of 10 CFR 54.4 are included within the scope of license renewal and are

identified as such by the applicant in LRA Section 2.3.4.8. The main generator and auxiliary

systems components that are subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1) are included in LRA Table 2.3.4-8. The staff did not identify any omissions.

2.3.4.8.3 Conclusions

The staff reviewed LRA Section 2.3.4.8 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. No

omissions were found. On the basis of its review, the staff concludes that the applicant has

adequately identified the components of the main generator and auxiliary systems that are

within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has

adequately identified the components of the extraction steam system that are subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.3.4.9 Feedwater Heater Drains and Vents System

2.3.4.9.1 Summary of Technical Information in the Application

The applicant described the feedwater heater drains and vents steam system in LRA Section

2.3.4.9 and provided a list of components subject to AMR in LRA Table 2.3.4-9. This LRA

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section was not included in the original LRA but was added to the scope of license renewal at

Quad Cities as a result of the revised scoping methodology and was provided to the staff in the

applicants response to the draft SER Open Item 2.1-1.

The function of the feedwater heater drains is to establish and maintain the desired level of

condensate in the feedwater heater shells. The function of the feedwater heater vent system is

to remove non-condensible gases from the heater shells and tubes during start-up and power

generation. Using the methodology described in LRA Section 2.1.4.1 for identifying the

mechanical components within the scope of license renewal, the applicant identified the

following extraction steam system intended function:

preclude adverse effects on safety-related SSCs-Non-safety-related components that

could be a hazard to safety-related SSCs maintain sufficient integrity so that the intended

function of safety-related SSCs is not adversely affected.

The feedwater heater system is divided into three parallel strings. Each string contains three

low pressure heaters A, B, and C and one high pressure heater D. Condensate cascades from

the D high pressure heater to the A, B, and C low ressure heaters in each string. The

condensate exits the A low pressure feedwater heater and is routed through a heater flash tank

and low pressure feedwater heater drain coolers in each string. Drainage is ultimately routed to

the main condenser.

The feedwater heater drain and vent system is comprised of the piping and components that

connect each of the flash tanks, heaters, and coolers. The feedwater heater coolers, and tanks

were are evaluated in the feedwater system and in the condensate and condensate makeup

system.

In LRA Section 2.3.4.9, the applicant described the feedwater heater drains and vents system

evaluation boundary. In addition, the applicant highlighted those portions of the feedwater

heater vents and drains systems within the scope of the Rule in the P&l drawings listed as

references in LRA Section 2.3.4.9. Also, based on the methodology described in LRA Section

2.1.5 for identifying the mechanical components subject to an AMR, the applicant identified the

following component groups and their intended functions within the plant heating system in LRA

Table 2.3.4-9 as being within the scope of license renewal and subject to an AMR:

* Piping and Fittings (spatial interaction, Quad Cities only)

* Valves (spatial interaction, Quad Cities only)

The LP heaters and Heater Flash Tanks, and Condensing Chambers that are highlighted on

the boundary drawings for this system are in scope of license renewal and require aging

management .These components were evaluated as part of the Condensate and Condensate

Storage System which is discussed in LRA Section 2.3.4.3.

2.3.4.9.2 Staff Evaluation

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The staff reviewed LRA Section 2.3.4.9 and Quad Cities UFSAR Section 10.4.7.2 to determine

whether there is a reasonable assurance that the extraction steam system components within

the scope of license renewal and subject to an AMR have been identified in accordance with 10

CFR 54.4 and 10 CFR54.21 (a)(1). The staff's review was conducted in accordance with

Section 2.3 of NUREG-1800.

In the performance of the review, the staff reviewed the UFSAR to determine if there were any

system functions that were not identified in accordance with the requirements of 10 CFR 54.4

as an intended function of the main generator and auxiliary systems in the LRA. The staff did

not identify any omissions.

Also, the staff selected system functions described in the UFSAR that were set forth in 10 CFR

54.4 to verify that components having intended functions were not omitted from the scope of

the Rule. The staff also focused on components that were not identified as being subject to an

AMR to determine if any component were omitted.

To verify that the applicant identified the components of the main generator and auxiliary

systems that are within the scope of license renewal and subject to an AMR in accordance with

10 CFR 54.4 and 10 CFR 54.21 (a)(1), respectively, the staff compared the referenced P&l

drawings to the system drawings and system descriptions in the UFSARs to ensure that the

referenced P&l drawings were representative of the main generator and auxiliary systems. The

staff then reviewed the referenced P&l drawings to verify that those portions of the main

generator and auxiliary systems that meet the scoping requirements of 10 CFR 54.4 are

included within the scope of license renewal and are identified as such by the applicant in LRA

Section 2.3.4.9, and that the applicant identified all main generator and auxiliary systems

components within the scope of license renewal and subject to an AMR in accordance with 10

CFR 54.4 and 10 CFR 54.21(a)(1).

The staff found that those portions of the main generator and auxiliary systems that meet the

scoping requirements of 10 CFR 54.4 are included within the scope of license renewal and are

identified as such by the applicant in LRA Section 2.3.4.9. The main generator and auxiliary

systems components that are subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR

54.21 (a)(1) are included in LRA Table 2.3.4-9. The staff did not identify any omissions.

2.3.4.9.3 Conclusions

The staff reviewed LRA Section 2.3.4.9 and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. No

omissions were found. On the basis of its review, the staff concludes that the applicant has

adequately identified the components of the main generator and auxiliary systems that are

within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has

adequately identified the components of the extraction steam system that are subject to anAMR, as required by 10 CFR 54.21 (a)(1).

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2.4 Scoping and Screening Results: Structures

This section addresses the structure-related scoping and screening results for license renewal.

The structures identified in LRA Table 2.2-2 as being in the scope of license renewal are as

follows:

* Primary Containment (LRA 2.4.1)

* Reactor Building (LRA 2.4.2)

* Main Control Room and Auxiliary Electric Equipment Room (LRA 2.4.3)

* Turbine Building (LRA 2.4.4)

* Diesel Generator Buildings (LRA 2.4.5)

* Station Blackout Building and Yard Structures (LRA 2.4.6)

* Isolation Condenser Pump House (Dresden Only) (LRA 2.4.7)

* Makeup Demineralizer Building (Dresden Only) (LRA 2.4.8)

* Radwaste Floor Drain Surge Tank (LRA 2.4.9)

* Miscellaneous Foundations (LRA 2.4.10)

* Crib House (LRA 2.4.11)

* Unit 1 Crib House (Dresden Only) (LRA 2.4.12)

* Station Chimney (LRA 2.4.13)

* Cranes and Hoists (LRA 2.4.14)

In addition, the applicant has identified the following commodity groups as within the structures

scope:

* Component Supports Commodity Group (LRA 2.4.15)

* Insulation Commodity Group (LRA 2.4.16)

Section 54.21 (a)(1) of Title 10 of the Code of Federal Regulations requires an applicant to

identify and list structures and components subject to an AMR. These are passive, long-lived

structures and components that are within the scope of license renewal. To verify that the

applicant has properly implemented its methodology, the staff focuses its review on the

implementation results. Such a focus allows the staff to confirm that there is no omission of

structural components that are subject to an AMR. If the review identifies no omission, the staff

has the basis to find that the applicant has identified the structural components that are subject

to an AMR.

LRA Table 2.2-2 also identifies the following structures that are not in scope of license renewal.

* fuel oil pump house and oil storage tank foundation (Dresden)

* meteorological tower

* miscellaneous administrative buildings

* miscellaneous yard structures

* miscellaneous radwaste buildings

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* miscellaneous river water structures

* miscellaneous Dresden Unit i structures (Dresden)

* miscellaneous transmission and distribution structures

Except for the meteorological tower and miscellaneous administrative buildings (provided there

are no seismic 11/1 intended functions associated with these structures), the staff was unable to

evaluate whether these structures are correctly excluded from the license renewal scope.

As a result, the staff requested the applicant to provide additional descriptive information for the

remaining six structures before a determination can be made on their inclusion in the scope.

The staff asked the applicant the following in RAI 2.4-1:

* Submit a more detailed description of these six structures, define their function, and

describe the technical bases for exclusion from the license renewal scope.

* Verify that none of the eight structures serve a seismic I1/1 intended function.

In its response to this RAI, the applicant stated the following:

The eight (8) structures listed in RAI 2.4-1 are groups of non-safety-related structures and major

components that do not satisfy the requirements of 10 CFR 54.4(a). These structures provide

structural support and anchorage for non-safety-related equipment and equipment that is not

required to support regulated events (ATWS, FP, EQ, and SBO). None of structures and major

components in these structural groups serves a seismic 11/l intended function. This was the

technical basis for exclusion from the license renewal scope. With the exception of the

meteorological towers, a description of remaining structural groups along with their functions is

provided below.

Dresden-Fuel Oil Pump House and Oil Storage Tank Foundation

This structural group contains structures that support the non-safety-related plant fuel supply subsystem for the plant heating steam boilers.

Dresden and Quad Cities Stations-Miscellaneous Administrative Buildings

This structural group covers a number of administrative, warehouse, and miscellaneous structures.

Several of the structures provide protection for non-safety-related equipment from the outside

environment.

Dresden and Quad Cities Stations-Miscellaneous Yard and Tank Structures

This structural group is a collection of miscellaneous non-safety-related structures located

throughout the site. Several of the structures provide protection for equipment from the outside

environment and also provide a barrier to contain potentially environmentally hazardous materials.

Dresden and Quad Cities Stations-Miscellaneous Radwaste Buildings

This structural group is a collection of miscellaneous non-safety-related structures that provide

structural support and anchorage of non-safety-related equipment and systems and

treated/processed radwaste materials. Several of these structures provide protection of personnel

and non-safety-related facilities, equipment and components from the outside environment and

also provide radiation shielding.

Dresden Station-Miscellaneous River Water Structures

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This structural group is a collection of miscellaneous non-safety-related structures related to the

circulating water systems, cooling water canals, and reservoirs. These structures provide

protection of personnel and non-safety-related equipment from the outside environment and

provide structural support for non-safety-related equipment. A description of those structures and

components included within this structural group along with their functions are provided below.

Units 2 & 3 Circ Water Discharge Pipes-The circulating water discharge pipes

provide the means of discharge/dispersion of heated circulating water into the

Dresden cooling lake and/or the Illinois River. The circulating water discharge

also provides the means of discharge, dispersion and dilution of low level liquid

radwaste.

213 Circ Water Row Regulating Station-A structure with gates that distributes

the water returning from the lake to the river (indirect open-cycle operation), to

the intake flume to the crib house (closed cycle operation), or to a combination

of both.

Unit 2 & 3 Lake Lift Station-The lift station provides protection for all

non-safety-related systems and components contained within the structure from

the outside environment. The lift station provides structural support for station

cooling water system equipment. This equipment functions in controlling the

flow of cooling water from the cooling lake through the intake and discharge

canals. Additionally, the Lift Station maintains the hot canal and lake levels.

Circulating Water Cooling Towers (3)-The circulating water cooling towers

provide supplemental cooling of the circulating water.

Goose Lake Pumping Station-The Goose Lake Pumping Station provides

protection of pumps that control level in the adjacent retention pond.

Units 2 & 3 Cooling Lake, dikes and canals-The cooling lake provides cooling

of the circulating water and service water prior to discharge into the Illinois River

or return to the plant.

Quad Cities Station-Miscellaneous River Water Structures

This structural group is a collection of miscellaneous non-safety-related structures related to the

circulating river water system. The circulating water system takes suction directly from the

Mississippi River, discharges the flow through the condenser, and directs it back to the river. A

description of those structures and components included within this structural group along with

their functions are provided below.

Discharge Flume-The discharge flume controls direction of flow.

Discharge Flume Sample Pump (Structure)-The discharge flume sample pump

structure houses and protects the non-safety-related sample pump.

Dock-The dock provides access to river.

Floating Boom-The primary function of the floating boom is to prevent floating

river debris from entering the intake flume and/or the circulating water pumps.

Intake Flume-The intake flume directs water to Crib House.

Lift Station- Lift Station structure provides protection for the non-safety-related

pumps and associated components that support the circulating water system

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from the outside environment. This facility is no longer in use.

Spray Canal-The spray canal was previously used to convey heated circulation

water discharge for cooling. It is currently used in conjunction with the Fish

Study Facility Building to produce walleye and hybrid striped bass fingerlings for

stocking and release to the Mississippi River.

Spray Canal Blowdown Diffuser Pipe-The spray canal blowdown diffuser pipe

provides measures for dispersion of circulating water. The spray canal

blowdown south diffuser pipe and the discharge bay function as the three site

release points for liquid effluents.

Spray Canal Diversion Wall-The spray canal diversion wall provides flow

direction control.

Wing Dam (6)-Wing dams provide river flow control. Wing Dam 31 is located

between the intake and discharge canals and functions as a recirculation barrier

that helps preclude released radioactive materials from being introduced back

into the circulating water system. The top of this wing dam is about 2 feet below

the river surface which creates some downstream water flow to prevent stagnant

water areas from forming.

Dresden Station-Miscellaneous Dresden Unit 1 Structures

This structural group is a collection of miscellaneous non-safety-related structures associated with

Unit 1 at Dresden Station. Dresden Unit 1 shares the site and surrounding area with Units 2 and

3. Unit 1 has been placed in a safe storage condition until Units 2 and 3 are ready for

decommissioning. None of these structures provide functional support for Units 2 and 3 and none

of structures and major components in this structural group serves a seismic 11/1 intended function

that could affect Units 2 and 3.

Dresden Station-Miscellaneous Transmission and Distribution Structures

This structural group is a collection of miscellaneous non-safety-related structures associated with

the 138 KV and 345 KV switchyards. The purpose of the structures included in this group is to

provide support and protection of the non-safety-related components that are used for transmitting

electrical power generated by the plant. Those transmission towers necessary to provide offsite

power restoration as defined by 10 CFR 50.63 (SBO) are included in the scope of license renewal

and evaluated with the Station Blackout Building structure (See section 2.4.6 of the LRA). Those

switchyard foundations providing necessary support for equipment and structures (e.g., breaker,

end structures, and disconnect foundations) necessary to provide offsite power restoration as

defined by 10 CFR 50.63 (SBO) are included in the scope of license renewal and evaluated with

the Station Blackout Building structure (See section 2.4.6 of the LRA).

Quad Cities Station-Miscellaneous Transmission and Distribution Structures

This structural group is a collection of miscellaneous non-safety-related structures associated with

the 345 KV switchyard. The purpose of the structures included in this group is to provide support

and protection of the non-safety-related components that are used for transmitting electrical power

generated by the plant. Those transmission towers necessary to provide offsite power restoration

as defined by 10 CFR 50.63 (SBO) are included in the scope of license renewal and evaluated

with the Station Blackout Building structure (See section 2.4.6 of the LRA).

For each group listed above, the applicant also identified the specific structures and major

components within the group and the function of each structure or major component. The

applicant's response to RAI 2.4-1 is complete. Based on its review of the information in the RAI

response, the staff concludes that the applicant conducted a comprehensive study to identify

the structures and components that are within the scope of license renewal. RAI 2.4-1 is,

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therefore, resolved.

2.4.1 Primary Containment

2.4.1.1 Summary of Technical Information in the Application

The applicant described the primary containment in LRA Section 2.4.1 and provided a list of

components subject to an AMR in LRA Table 2.4-1.

The primary containment provides a barrier that controls the release of fission products to the

secondary containment in the event of a loss-of-coolant accident (LOCA). It also provides

structures and a water pool that limit the pressure increase in the containment in the event of a

LOCA.

The primary containment is a General Electric Mark I design. It consists of a drywell, a

pressure suppression chamber that is partially filled with water, and a vent system connecting

the drywell and the suppression chamber. The design, fabrication, and inspection of the

primary containment was in accordance with the requirements of the ASME Pressure Vessel

Code, Section III, Class B. It is a Class I structure.

The drywell is a steel pressure vessel with a spherical lower section and a cylindrical upper

section. A portion of the lower spherical section is embedded in concrete. This embedment, in

combination with upper lateral supports that are attached to the cylindrical section, forms the

reactor support system. The drywell houses the reactor vessel, the reactor coolant recirculation

system, and branch connections of the reactor primary system. It includes structural steel

framing, a concrete radiation shield wall between the reactor pressure vessel and the drywell

walls, a removable steel head, an equipment hatch and other access hatches, a personnel

airlock with two mechanically interlocked doors, and penetrations.

The drywell head is removed during refueling operations. The head is held in place by bolts

and is sealed with a double gasket, tongue-and-groove arrangement that permits checks for

leak tightness without pressurizing the entire containment.

The pressure suppression chamber is a toroidal-shaped, steel pressure vessel encircling the

base of the drywell. The suppression chamber is commonly called the torus and includes

internal steel framing, supports, access hatches, and penetrations. The suppression chamber

is mounted on support structures that transmit loads to the concrete foundation of the reactor

building.

Eight circular vent lines form a connection between the drywell and the pressure suppression

chamber. These drywell vent lines are connected to a header which is contained within the air

space of the suppression chamber. The header downcomers terminate below the suppression

chamber water level. The primary containment also contains structural interfacing components

of the electrical penetrations.

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The applicant identified the following UFSAR references for additional descriptive information

about the primary containment: - - -

* Dresden Station UFSAR Section(s): 6.2.1, 3.2.1 _

* Quad Cities Station UFSAR Section(s): 6.2.1, 3.2.1

rI

The applicant defined the following intended functions for the primary containment:

* Primary containment-controls the release of fission products to the secondary containment

in the event of design-basis LOCAs so that offsite consequences are within acceptable

limits.

* Physical support and protection-provides physical support and protection for safety-related

components and components relied upon to demonstrate compliance with fire protection,

ATWS, and SBO-regulated events. The structure also contains components that are relied

upon for compliance with 10 CFR 50.49, (EQ).

Pressure suppression-provides sufficient air and water volumes to absorb the energy

released to the containment in the event of design-basis events so that the pressure is

within acceptable limits.

* Water source-provides a source of water for emergency core cooling systems.

* Radiation shielding-biological shield wall between the reactor pressure vessel and the

drywell walls provides protection to personnel and components from radiation.

In LRA Table 2.4-1, the applicant listed the following component groups as requiring AMR for

the primary containment:

Component Component Intended Function LRA Aging Management Ref No.

Beam Seats Structural Support 3.5.1.20

Concrete and Grout Structural Support 3.5.1.29

Concrete Slabs Structural Support 3.5.1.20, 3.5.1.27

Concrete Walls Structural Support 3.5.1.20, 3.5.1.27

Concrete Walls Shelter, Protection, Shielding 3.5.1.20, 3.5.1.27

Containment Penetrations -; Structural Support 3.5.1.3

(Electrical)

Containment Penetrations Fission Product Barrier 3.5.1.3

(Electrical) . ._._._.-

Containment Penetrations Structural Pressure Barrier 3.5.1.3

(Electrical) . ._ . _.

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Component Component Intended Function LRA Aging Management Ref No.

Containment Penetrations Structural Support 3.5.1.3

(Mechanical)

Containment Penetrations Fission Product Barrier 3.5.1.3

(Mechanical)

Containment Penetrations Structural Pressure Barrier 3.5.1.3

(Mechanical)

Containment Penetrations Bellows Fission Product Barrier 3.5.1.2

Containment Penetrations Bellows Structural Pressure Barrier 3.5.1.2

Downcomers Structural Pressure Barrier 3.5.1.12, 3.5.1.14

Drywell Expansion Foam Expansion/Separation 3.5.2.8

Drywell Heads Structural Support 3.5.1.12, 3.5.1.14

Drywell Heads Fission Product Barrier 3.5.1.12, 3.5.1.14

Drywell Heads Structural Pressure Barrier 3.5.1.12,3.5.1.14

Drywells Structural Support 3.5.1.12,3.5.1.14

Drywells Fission Product Barrier 3.5.1.12, 3.5.1.14

Drywells Structural Pressure Barrier 3.5.1.12, 3.5.1.14

Hatches Structural Pressure Barrier 3.5.1.4, 3.5.1.5

Misc. Steel (includes Stairs, Non-S/R Structural Support 3.5.1.20

Ladders, Platforms, Gratings)

Penetration Sleeves, Penetration Structural Support 3.5.1.1

Bellows

Penetration Sleeves, Penetration Fission Product Barrier 3.5.1.1

Bellows

Penetration Sleeves, Penetration Structural Pressure Barrier 3.5.1.1

Bellows

Seals Structural Pressure Barrier 3.5.1.6

Steel Embedments Structural Support 3.5.1.20

Steel Panels and Cabinets Structural Support 3.5.1.20

Structural Steel Structural Support 3.5.1.20

Suppression Chambers Structural Support 3.5.1.12, 3.5.1.13, 3.5.1.14

Suppression Chambers Fission Product Barrier 3.5.1.12, 3.5.1.13, 3.5.1.14

Suppression Chambers Structural Pressure Barrier 3.5.1.12, 3.5.1.13, 3.5.1.14

Thermowells Structural Support 3.5.2.15

Thermowells Structural Pressure Barrier 3.5.2.15

Vent Headers Structural Support 3.5.1.13

Vent Headers Structural Pressure Barrier 3.5.1.12, 3.5.1.13, 3.5.1.14

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' 1 t o - I.. I: -?:.-. , '_-

Component Component Intended Function LRA Aging Management Ref No.

Vent Line Bellows Structural Support 3;5.1.13

Vent Line Bellows Structural Pressure Barrier 3.5.1.13,3.5.1.17

Vent Lines Structural Support 3.5.1.12, 3.5.1.14

Vent Lines Structural Pressure Barrier 3.5.1.12, 3.5.1.14

Wallis, Ceilings, Floors Fire Barrier 3.3.1.28

The applicant's AMR results for the primary containment are provided in LRA Sections 3.3 and

3.5.

2.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.1, Dresden Station UFSAR Sections 6.2.1 and 3.2.1, and

Quad Cities Station UFSAR Sections 6.2.1 and 3.2.1 to determine whether the primary

containment structural components within the scope of license renewal and subject to an AMR

have been identified in accordance with 10 CFR 54.4 and 54.21 (a)(1).

In the performance of the review, the staff selected system functions described in the UFSAR

that are required by 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

LRA Section 2.4.1 discusses the scoping and screening results for the primary containment. It

is the staff's understanding that this section of the LRA addresses not only the primary

containment (drywell, pressure suppression chamber, and the vent system connecting the two

structures), but also all the structures inside the containment, all attachments to the

containment, and the containment supports. LRA Table 2.4-1 identifies the primary

containment component groups requiring AMR, the associated component intended function(s),

and the AMR reference. Since LRA Table 2.4-1 combines many components under a single

component group, the staff requested (RAI 2.4-2) that the applicant identify which component

group is intended to cover the specific components listed in (a) through (k) below, or identify the

location in the LRA where these specific components are addressed. If these specific

components are not considered to be within the scope of license renewal, the applicant was

requested to provide the technical bases for their exclusion. To assist in the review, the staff

has noted figure numbers from either the Dresden or the Quad Cities UFSAR that identify

specific components. However, the component list applies to all four units.

(a) reactor vessel to biological shield stabilizers (D-UFSAR Figures 3.9-1 and 3.9-2)

(b) biological shield to containment stabilizer (D-UFSAR Figures 3.9-1 and 3.9-2 and

QC-UFSAR Figures 3.9-5 and 3.9-8)

(c) RPV male stabilizer attached to outside of drywell shell (QC-UFSAR Figures 3.9-5 and

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3.9-8)

(d) RPV female stabilizer and anchor rods (also referred to as gib) embedded in reactor

building concrete wall (D-UFSAR Figure 3.9-1 and QC-UFSAR Figures 3.9-8 and 3.9-9)

(e) biological shield wall and anchor bolts (D-UFSAR Figures 3.9-2 and 3.9-7 and

QC-UFSAR Figures 3.9-5 and 3.9-6)

(f) reactor vessel support skirt and anchor bolts (D-UFSAR Figures 3.9-2 and 3.9-3 and

QC-UFSAR Figures 3.9-5, 3.9-6, and 3.9-10)

(g) reactor vessel support ring girder and anchor bolts (D-UFSAR Figures 3.9-2 and 3.9-3 and

QC-UFSAR Figures 3.9-5, 3.9-6, and 3.9-10)

(h) reactor vessel support pedestal (D-UFSAR Figures 3.9-2 and 3.9-3 and QC-UFSAR

Figures 3.9-5 and 3.9-6)

(i) drywell internal 6x1 -in. steel shear ring (QC-UFSAR Figures 3.9-5 and 3.9-7)

() drywell steel support skirt and anchor bolts (QC-UFSAR Figures 3.9-5 and 3.9-7)

(k) drywell head closure bolts and double gasket, tongue-and-groove seal arrangement

(described in LRA Section 2.4.1)

In a letter dated December 5, 2003, in response to RAI 2.4-2, the applicant stated the following:

All of the components described below are included within the scope of license renewal. Items (a)

through (k) below provide the LRA Table number and Component Group that address each

specific component.

(a) Reactor Vessel to Biological Shield Stabilizers-Table 2.4-1, Primary Containment,

Component Group-Structural Steel

(b) Biological Shield to Containment Stabilizer-Table 2.4-1, Primary Containment, Component

Group-Structural Steel

(c) RPV Male Stabilizer Attached to Outside of Drywell Shell-Table 2.4-1, Primary Containment,

Component Group-Steel Embedments

(d) RPV Female Stabilizer and Anchor Rods (also referred to as Gib) embedded in Reactor

Building concrete wall-Table 2.4-1, Primary Containment, Component Group-Steel

Embedments

(e) Biological Shield Wall-Table 2.4-1, Primary Containment, Component Group-Concrete Walls (Structural Support and Shelter, Protection, Shielding)

(f) Anchor bolts-Table 2.4-15, Component Supports, Component Group-Anchorage to

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Buildings, Including BoltedNVelded Connections (Structural Support)

(g) Reactor Vessel Support Skirt-Table 2.3.1-1, Reactor Vessel, Component Group-Support

Skirts and Attachment Welds

Anchor bolts-Table 2.4-15, Component Supports, Component Group-Anchorage

to Buildings, Including Bolted/Welded Connections (Structural Support)

(h) Reactor Vessel Support Ring Girder-Table 2.4-1, Primary Containment, Component

Group-Support Members

Anchor bolts-Table 2.4-15, Component Supports, Component Group-Anchorage

to Buildings, Including Bolted/Welded Connections (Structural Support)

(i) Reactor Vessel Support Pedestal-Table 2.4-1, Primary Containment, Component

Group-Concrete Walls (Structural Support)

U) Drywell internal 6xl -inch steel shear ring-Table 2.4-1, Primary Containment, Component

Group-Steel Embedments

(k) Drywell steel support skirt-Table 2.4-1, Primary Containment, Component Group-Support

Members

Anchor bolts-Table 2.4-15, Component Supports, Component Group-Anchorage

to Buildings, Including Bolted/Welded Connections (Structural Support)

(I) The drywell head closure bolts-Table 2.4-1, Primary Containment, Component

Group-Drywell Heads

Double Gasket-Exelon procedure requires the gasket material to be replaced during reactor

reassembly (at least once per refuel cycle). These gaskets are not long lived and therefore do

not require aging management.

Tongue-and-groove Seal Arrangement-Table 2.4-1, Primary Containment, Component

Groups-Drywell Heads and Drywells

In its response, the applicant identified a specific component group for all items listed in the

RAI, except for the double gasket. Since the double gasket is on a regular replacement

schedule, the staff concurs that it does not require aging management for license renewal. The

staff finds the applicant's response acceptable and, therefore, RAI 2.4-2 is resolved.

Leakage through the refueling seals located at the top of the drywell potentially exposes the

carbon steel drywell shell inner and outer surfaces to loss of material due to corrosion. This is a

particular concern for the embedded portion of the drywell shell. Corrosion detected on the

outer shell surface in the sand pocket region in a number of Mark I steel containments has

been attributed to leakage past the drywell-to-reactor building refueling seal, coupled with

clogging of the sand pocket drains. Leakage into the drywell, past the reactor vessel-to-drywell

refueling seal, creates the potential for corrosion of the inaccessible portion of the inner surface

of the drywell shell embedded in the concrete floor.

From the information contained in the LRA, it was not clear to the staff (1) whether the refueling

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seals have been included in the license renewal scope, and (2) if included, how aging

management is being addressed. Therefore, the applicant was requested (RAI 2.4-3) to submit

the following information:

(a) verification that the refueling seals are included in the license renewal scope, or a detailed

explanation for their exclusion

(b) a detailed description of the plant-specific operating experience for the refueling seals in all

four units, including incidences of degradation, method of detection, root cause, corrective

actions, and current inspection procedures

(c) a detailed description of the scoping, screening, and aging management review for the

refueling seals

(d) the aging management program(s) credited to manage aging of the refueling seals

In a letter dated December 12, 2003, in response to RAI 2.4-3, the applicant stated the

following:

(a) The refueling seals are not within the scope of license renewal. Title 10, CFR 54, Section

54.4(a), sets forth the criteria that determine whether plant systems, structures, and

components are within the scope of license renewal. The refueling seals do not satisfy any of

the requirements set forth in 10 CFR 54.4(a).

The refueling seals are not safety-related and they are not relied upon to remain functional

during design basis events to ensure (I) the integrity of the reactor coolant pressure boundary, (ii) the capability to shutdown the reactor and maintain it in a safe shutdown condition, or (iii)

the capability to prevent or mitigate potential offsite exposures comparable to those referred to

in 10 CFR 50.34(a)(1), 50.67(b)(2), or 100.1 1. Thus, the refueling seals are not brought into

scope of license renewal by 10 CFR 54.4(a)(1).

Title 10 CFR 54.4(a)(2) sets forth the criterion that all non-safety-related systems, structures

and components whose failure could prevent satisfactory accomplishment of any of the

safety-related functions identified in 10 CFR 54.4(a)(1) are also within the scope of license

renewal.

The drywell-to-reactor building refueling seal and the reactor pressure vessel (RPV)-to-drywell

refueling seal, in conjunction with the refueling bulkhead, provides a watertight barrier to

permit flooding above the RPV flange while preventing water from entering the drywell.

Providing a watertight barrier to permit flooding above the RPV flange in support of refueling operations is not a safety-related function.

The NRC notified the nuclear industry of the potential for degradation of steel containments

due to leakage past the drywell to reactor building refueling seals in IE Information Notice

86-99 and NRC Generic Letter 87-05. The Dresden and Quad Cities responses to these NRC

communications are described in their respective UFSARs, Section 6.2.1.2.1.2 (Drywell Corrosion Potential). The UFSAR discussions include a commitment to monitor the sand

pocket drain lines during refuel activities and if leakage is detected during refuel flood-up, an

inspection to determine the source will take place and further corrective measures will be

initiated. Dresden/Quad Cities LRA Section 4.7.2.2 (Degradation Rates of Inaccessible

Exterior Drywell Plate Surfaces) describes the calculation that projected corrosion rates for the

steel drywell plates in the sand pocket area and determined that the wall thickness was

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sufficient for the remainder of the 40-year license period, and determines it to be a TLAA. The

TLAA disposition includes a commitment to confirm corrosion rate assumptions used in the

calculations by UT inspection prior to the period of extended operation and to revise the

corrosion calculation and validate that an acceptable wall thickness will remain to the end of

the 60-year license operating period. These commitments support a conclusion that even if

leakage past the drywell to reactor building refueling seal occurs, there will be no

consequential failure of any of the safety-related functions identified in 10 CFR 54.4(a)(1).

Thus, the drywell to reactor building refueling seal is not brought into license renewal scope by

10 CFR 54.4(a)(2).

Potential leakage of water past the RPV to drywell refueling seal can occur only when the

reactor is in a cold shutdown condition with the reactor cavity flooded to support refueling

operations. Leakage past the RPV-to-drywell seal would result in cold (c150 IF),

demineralized water entering the drywell. Leakage of cold, demineralized water into the

drywell cannot result in failure of any safety-related equipment because 1) there is no

equipment inside the drywell whose safety-related function is credited in support of refueling

operations, 2) the drywell contains a drainage system and sumps to collect and monitor

unidentified leakage inside the drywell, and 3) the frequent personnel entry into the drywell

that occurs during most refueling outages would result in any substantial leakage past the

RPV to drywell refueling seal being noticed and corrective actions being taken. These

considerations support a conclusion that even if leakage past the RPV-to-drywell refueling

seal occurs, there will be ho consequential failure of any of the safety-related functions

identified in 10 CFR 54.4(a)(1). Thus, the RPV-to-drywell refueling seal is not brought into

license renewal scope by 10 CFR 54.4(a)(2).

The refueling seals are not relied upon in safety analyses or plant evaluations to perform a

function that demonstrates compliance with the Commission's regulations for fire protection,

environmental qualification, pressurized thermal shock (N/A for BWRs), anticipated transients

without scram, or station blackout. Thus, the refueling seals are not brought into license

renewal scope by 10 CFR 54.4(a)(3).

(b) The refueling seals are not within the scope of license renewal. As such, evaluation of their

operating experience is not included within the scope of the license renewal application.

(c) The refueling seals are not within the scope of license renewal. A detailed explanation of the

scoping considerations is provided in response to question 1), above. The refueling seals are

passive components that are not within the scope of license renewal. As such, they have not

been included within the scope of aging management review.

(d) The refueling seals are not within the scope of license renewal. As such, the refueling seals

are not within the scope of an aging management program.

The staff finds the applicant's response acceptable and, therefore, RAI 2.4-3 is resolved.

2.4.1.3 Conclusions

The staff reviewed LRA Section 2.4.1 to determine whether any structural components of the

primary containment that should be within the scope of license renewal were not identified by

the applicant. In addition, the staff performed an independent assessment to determine

whether any components that should be subject to an AMR were not identified by the applicant.

On the basis of its review, the staff concludes that the applicant has adequately identified the

structural components of the primary containment that are within the scope of license renewal,

as required by 10 CFR 54(a), and that the applicant has adequately identified the structural

components of the primary containment that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

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2.4.2 Reactor Building

2.4.2.1 Summary of Technical Information in the Application

The applicant described the reactor building in LRA Section 2.4.2 and provided a list of

components subject to AMR in LRA Table 2.4-2.

The reactor building serves as the secondary containment. The secondary containment, in

conjunction with other engineered safeguards and nuclear safety systems, limits the release of

radioactive materials ensuring that site exposure resulting from a postulated design basis

accident will remain below 10 CFR Part 100 guideline values. The reactor building provides

secondary containment when the primary containment is in service, and provides primary

containment during reactor refueling and maintenance operations when the primary

containment system is open.

A single seismic Class I reactor building for each unit completely encloses both reactor and

primary containment structures and auxiliary systems of the nuclear steam supply system. A

major substructure within the reactor building is a reinforced concrete biological shield that

surrounds each reactor and drywell portion of the primary containment. Additionally, the

building houses the spent fuel pool, steam dryer/moisture separator storage pool, the new fuel

storage vault, reactor cavity, reactor auxiliary equipment, refueling equipment, and reactor

servicing equipment. The reactor building consists of monolithic reinforced concrete floors and

walls from its foundation to the refueling floor, with a separation wall between the two units.

Above this floor is the common refueling floor where the building superstructure, consisting of

structural steel framing, sealed sheet metal siding, and a precast concrete roof, provides

secondary containment integrity. The building is designed to contain positive internal pressure

without structural failure and without pressure relief. Blow-off panels are installed as part of the

reactor building superstructure siding to relieve pressure and control potential damage under

short-term tornado loads. Personnel interlock/airlock access control doors have seals and are

electrically controlled so that only one door in an "airlock" can be open at a time.

The containment barrier function of the reactor building is achieved through design and

construction low leakage of air through the interlock/airlock doors, pipe and electrical

penetration seals, and the building walls and roof. During normal operation, pressure in the

building is automatically maintained at a slight negative pressure by controlling the exhaust to

minimize exfiltration of airborne radioactive contamination, even under high wind conditions.

The reactor building ventilation system (evaluated with HVAC-reactor building) is isolated on a

secondary containment isolation signal.

Other structural components evaluated in this section include the reactor building penetrations

and doors, equipment access building, the spent fuel pool, high-density spent fuel racks, crane

rails, and the new fuel storage vault with associated components.

Reactor building structural items evaluated in other areas include the refueling platforms

(evaluated with refueling equipment) and reactor building cranes (evaluated with cranes and

hoists).

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The applicant identified the following UFSAR references for additional descriptive information

about the reactor building:

* Dresden Station UFSAR Section(s): 6.2.3, 3.2.1

* Quad Cities Station UFSAR Section(s): 6.2.3, 3.2.1

The applicant defined the following intended functions for the reactor building:

* Containment-controls the potential release of fission products to the external environment

so that offsite consequences of design-basis events are within acceptable limits. The

reactor building provides secondary containment function when the primary containment is

required to be in service and provides primary containment function during reactor refueling

and maintenance operations when the primary containment systems are open. -

* Physical support and protection-provides physical support for safety-related and nonsafety-related components, protection for all personnel and safety-related components, and

components relied upon to demonstrate compliance with regulated events.

• Protection and Radiation Shielding-provides leak-tight boundary to protect public health

and safety in the event of postulated design-basis events and radiation shielding.

Protection provides protection for safe storage of new fuel.

In LRA Table 2.4-2, the applicant listed the following component groups requiring AMR for the

reactor building:

Component Component Intended Function LRA Aging Management Ref No.

Blowout Panels Structural Pressure Barrier 3.5.1.20

Caulking/Sealants Structural Pressure Barrier 3.5.2.4

Concrete and Grout Structural Support 3.5.1.29

Concrete Beams Structural Support 3.5.1.20, 3.5.1.21

Concrete Columns Structural Support 3.5.1.20, 3.5.1.21, 3.5.1.27

Concrete Curbs Direct Flow 3.5.1.20

Concrete Slabs Structural Support 3.5.1.20, 3.5.1.21

Concrete Slabs Shelter, Protection, Shielding 3.5.1.20

Concrete Walls Structural Support 3.5.1.20, 3.5.1.21

Concrete Walls Shelter, Protection, Shielding 3.5.1.20

Concrete Walls Structural Pressure Barrier 3.5.1.20

Door Seals Flood Barrier 3.5.2.7

Fire Doors Fire Barrier 3.3.2.4

Fire Doors (Dresden) Shelter, Protection, Shielding 3.3.2.4

Fire Proofing Fire Barrier 3.3.2.62

Fire Wrap Fire Barrier 3.3.2.63

Foundations Structural Support 3.5.1.20, 3.5.1.21, 3.5.1.25, 3.5.1.26

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Component Component Intended Function LRA Aging Management Ref No.

Liners Structural Pressure Barrier 3.5.1.23

Masonry Walls Structural Support 3.5.1.24

Masonry Waits Fire Barrier 3.3.2.129

Masonry Walls Missile Barrier 3.5.1.24

Masonry Walls HELB Shielding 3.5.1.24

Metal Decking Structural Support 3.5.1.20

Metal Siding Shelter, Protection, Shielding 3.5.1.20

Metal Siding Structural Pressure Barrier 3.5.1.20

Misc. Steel (Grating, Ladders) Structural Support 3.5.1.20

Misc. Steel (Kick Plates, Ladders, Non-SIR Structural Support 3.5.1.20

Platforms, Stairs, Railing)

Neutron-Absorbing Sheets Absorb Neutrons 3.3.1.12, 3.3.1.9

New Fuel Racks Structural Support 3.5.2.10

Penetration Seals (includes Fire Barrier 3.3.1.18

Secondary Containment Boot Seal)

Penetration Sleeves Non-S/R Structural Support 3.5.1.20

Precast Concrete Panels Structural Support 3.5.1.20

Precast Concrete Panels Shelter, Protection, Shielding 3.5.1.20

Roofing Shelter, Protection, Shielding 3.5.2.11

Secondary Containment Boot Seals Structural Pressure Barrier 3.5.2.12

Steel Doors Shelter, Protection, Shielding 3.5.1.20

Steel Doors Flood Barrier 3.5.1.20

Steel Doors Structural Pressure Barrier 3.5.1.20

Steel Embedments Structural Support 3.5.1.20

Steel Panels and Cabinets Structural Support 3.5.1.20

Steel Plates Missile Barrier 3.5.1.20

Steel Plates HELB Shielding 3.5.1.20

Steel Plates Direct Flow 3.5.1.20

Storage Racks Structural Support 3.3.1.11

Structural Steel (includes flued head Structural Support 3.5.1.20

anchor support)

Structural Steel HELB Shielding 3.5.1.20

Structural Steel Pipe Whip Restraint 3.5.1.20

Walls, Ceilings, Floors Fire Barrier 3.3.1.28

The applicant's AMR results for the reactor building are provided in LRA Sections 3.3 and 3.5.

2.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2, Dresden Station UFSAR Sections 6.2.3 and 3.2.1, and

Quad Cities Station UFSAR Sections 6.2.3 and 3.2.1 to determine whether the reactor building

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structural components within the scope of license renewal and subject to an AMR have been

identified in accordance with 10 CFR 54.4 and 54.21(a)(1).

In the performance of the review, the staff selected system functions described in the UFSAR

that are required by 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

LRA Table 2.4-2 presents a comprehensive list of component groups. However, for certain

components the staff requires further explanation to complete its evaluation. The applicant was

requested to submit the following information in RAI 2.4-4.

(a) a description of "Neutron-Absorbing Sheets," and an explanation why it is included as a

structural component when the aging management results are documented in LRA

3.3-Auxiliary Systems

(b) a description of "Secondary Containment Boot Seals"

(c) verification that "Storage Racks" refers to spent fuel racks, and an explanation why it is

included as a structural component when the aging management results are documented in

LRA 3.3-Auxiliary Systems

In its response to RAI 2.4-4, the applicant stated the following:

(a) The spent fuel pool racks contain neutron absorbing sheets that maintain a ken no greater than

.95 when all of the spent fuel is in place. These neutron adsorbing sheets are made of boral

at Dresden and boraflex at Quad Cities and are evaluated in Sections VII.A2.1-b and

VII.A1.1-a of NUREG-1801, Generic Aging Lessons Learned Report, Volume 2. Exelon

assigned an aging management reference for these components to Table 3.3.1, Aging Management Programs Evaluated in NUREG-1801 That Are Relied Upon for License

Renewal for the Auxiliary Systems, because NUREG-1801 directs licensees to this same

reference. Table 3.3.1 of the Dresden and Quad Cities License Renewal Application is a

recreation of all BWR-related line items found in Table 3 of NUREG-1 801, Volume 1.

NUREG-1801 line items VII.A2.1-b and VII.A1.1-a are assigned to Table 3 of NUREG-1801,

Volume 1. Exelon assigned these structural components to aging management references for

auxiliary systems only because it is an expectation of NUREG-1801.

(b) The Reactor Building serves as the secondary containment whose primary purpose is to

minimize the ground level release of airborne radioactive materials and to provide for a

controlled, elevated release of the building atmosphere under accident conditions. To achieve

this function, the Reactor Building is designed to maintain an internal negative pressure 2Y4

inch H20 under neutral wind conditions. Reactor Building pipe penetrations are sealed as

necessary to minimize air in leakage and maintain the negative internal pressure. These pipe penetration seals are called 'Secondary Containment Boot Seals." Boot seals are fabricated

with a silicone rubber material that allows pipe movement while providing a seal between the

pipe and the Reactor Building.

(c) "Storage Racks' refer to Spent Fuel Storage Racks" and are consistent with the components

evaluated in Section VII.A2.1-c of NUREG-1801, Volume 2. At Dresden and Quad Cities,

Spent Fuel Storage Racks are treated as structures, rather than part of an auxiliary system. Therefore, they were included in Section 2.4 of the LRA, the scoping and screening results for

structures. The NUREG-1 801 line item for Spent Fuel Storage Racks (VII.A2.1-c) is assigned

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to Table 3 of NUREG-1 801, Volume 1 for Auxiliary Systems. Exelon credited the aging

management programs in NUREG-1801 for spent fuel storage racks. Therefore the aging

management reference for the spent fuel racks listed in Section 2.4 for structures

cross-references an aging management program in the NUREG-1801 section for auxiliary

systems.

The additional information provided by the applicant in its RAI response sufficiently describes

the three components and how each is covered in the AMR. The staff concludes that the

applicant has appropriately addressed the "Neutron-Absorbing Sheets," "Secondary

Containment Boot Seals," and "Storage Racks" in its scoping and screening review and,

therefore, considers RAI 2.4-4 resolved.

2.4.2.3 Conclusions

The staff reviewed LRA Section 2.4.2 to determine whether any structural components of the

reactor building that should be within the scope of license renewal were not identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. On the

basis of its review, the staff concludes that the applicant has adequately identified the structural

components of the reactor building that are within the scope of license renewal, as required by

10 CFR 54(a), and that the applicant has adequately identified the structural components of the

reactor building that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.3 Main Control Room and Auxiliary Electric Equipment Room

2.4.3.1 Summaiy of Technical Infornation in the Application

The applicant described the main control room and auxiliary electric equipment room in LRA

Section 2.4.3 and provided a list of components subject to an AMR in LRA Table 2.4-3.

The main control room and auxiliary electric equipment room provide protection and structural

support of the control equipment required for normal station operation and for shutdown of the

plant under abnormal conditions. The main control room provides protection to safety-related

components and to operating personnel from radiation exposure, high energy line break

(HELB), tornado, and internally generated missiles.

The main control room and auxiliary electric equipment room contain the controls for normal

station operation and for shutdown of the plant under abnormal conditions. This combined

structure is seismic Class I, primarily reinforced concrete, capable of accommodating loading

conditions imposed during any design-basis accident (DBA) without failure.

The Dresden main control room has reinforced concrete and reinforced concrete block walls,

with a reinforced concrete floor and ceiling. The Dresden auxiliary electric equipment room

serves as the cable spreading room for both units and houses the computer room. It is

classified as a Class II structure, which has been investigated to assure that the integrity of the

Class I items are not compromised. The auxiliary electrical equipment room is a reinforced

concrete structure with structural steel support elements, a reinforced concrete floor, and the

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control room floor above as its ceiling. -

The Quad Cities main control room, auxiliary electrical equipment room, and the cable

spreading room complex is a Class I structure designed to accommodate loading conditions

imposed during any DBA without failure. The control room is heavy-walled, constructed of

ordinary reinforced concrete and of magnetite (high-density) concrete, with ordinary reinforced

concrete for the control room and 'cable spreading room floor, and ordinary reinforced concrete

for the auxiliary electric equipment room floor slab and roof slab. The cable spreading room is

located directly below the main control room and above the auxiliary electrical equipment room

and is used solely for the routing of instrument and control cables. The auxiliary electrical

equipment room contains alternate safe shutdown equipment and the cabling from the tunnel

below to the cable spreading room.

The applicant identified the following UFSAR references for additional descriptive information

about the main control room and auxiliary electric equipment room:

* Dresden Station UFSAR Section(s): 3.1.1.3.1, 3.2.1, 3.2.6, and 6.4

* Quad Cities Station UFSAR Section(s): 3.1.3.1, 3.2.1, and 6.4

The applicant defined the following intended functions for the main control room and auxiliary

electric equipment room:

* Physical support and protection-provides physical support and protection for safety-related

components and components relied upon to demonstrate compliance with fire protection

and SBO-regulated events.

* Personnel protection-provides shelter, protection, and radiation shielding for essential

operating personnel.

In LRA Table 2.4-3, the applicant listed the following component groups requiring AMR for the

main control room and auxiliary electric equipment room:

Component Component Intended Function LRA Aging Management Ref No.

Concrete and Grout Structural Support 3.5.1.29

Concrete Beams (Quad Cities) Structural Support 3.5.1.20

Concrete Columns (Quad Cities) Structural Support 3.5.1.20

Concrete Curbs (Dresden) Direct Flow 3.5.1.20

Concrete Manholes (Dresden) Structural Support 3.5.1.20

Concrete Manholes (Dresden) Fire Barrier 3.3.1.28

Concrete Slabs Structural Support 3.5.1.20,3.5.1.21, 3.5.1.27

Concrete Slabs Shelter, Protection, Shielding 3.5.1.20, 3.5.1.21, 3.5.1.27

Concrete Walls Structural Support 3.5.1.20

Concrete Walls Shelter, Protection, Shielding 3.5.1.20, 3.5.1.27

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Component Component Intended Function LRA Aging Management Ref No.

Caulking/Sealants Structural Pressure Barrier 3.5.2.3

Fire Doors Fire Barrier 3.3.2.4

Fire Proofing Fire Barrier 3.3.2.62

Fire Wrap Fire Barrier 3.3.2.63

Foundations Structural Support 3.5.1.20, 3.5.1.21, 3.5.1.25, 3.5.1.26

Masonry Walls Structural Support 3.5.1.24

Masonry Walls Fire Barrier 3.3.2.129

Masonry Walls Shelter, Protection, Shielding 3.5.1.24

Masonry Walls Missile Barrier 3.5.1.24

Metal Decking (Dresden) Structural Support 3.5.1.20

Misc. Steel (Quad Cities) Structural Support 3.5.1.20

Penetration Seals Fire Barrier 3.3.1.18

Penetration Seals (Dresden) Non-S/R Structural Support 3.3.1.18

Penetration Sleeves Non-S/R Structural Support 3.5.1.20

Roofing (Quad Cities) Shelter, Protection, Shielding 3.5.2.11

Steel Embedments Structural Support 3.5.1.20

Steel Panels and Cabinets Structural Support 3.5.1.20

Structural Steel Structural Support 3.5.1.20

Walls, Ceilings, Floors Fire Barrier 3.3.1.28

The applicant's AMR results for the main control room and auxiliary electric equipment room

are provided in LRA Sections 3.3 and 3.5.

2.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3, Dresden Station UFSAR Sections 3.1.1.3.1, 3.2.1, 3.2.6,

and 6.4, and Quad Cities Station UFSAR Sections 3.1.3.1, 3.2.1, and 6.4 to determine whether

the main control room and auxiliary electric equipment room structural components within the

scope of license renewal and subject to an AMR have been identified in accordance with 10

CFR 54.4 and 54.21 (a)(1).

In the performance of the review, the staff selected system functions described in the UFSAR

that are required by 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR, to determine if any components were omitted.

LRA Table 2.4-3 presents a list of structural components for the main control room and auxiliary

electric equipment room. In response to RAI 2.3.2.9-3, the applicant added caulking/sealants

as a component to be in scope. The staff did not identity other omissions made by the

applicant.

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*- -. iJ:i. 

2.4.3.3 Conclusions

The staff reviewed LRA Section 2.4.3 to determine whether any structural components of the

main control room and auxiliary electric equipment room that should be within the scope of

license renewal were not identified by the applicant. In addition, the staff performed an

independent assessment to determine whether any components that should be subject to an

AMR were not identified by the applicant. On the basis of its review, the staff concludes that

the applicant has adequately identified the structural components of the main control room and

auxiliary electric equipment room that are within the scope of license renewal, as required by 10

CFR 54(a), and that the applicant has adequately identified the structural components of the

main control room and auxiliary electric equipment room that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.4.4 Turbine Building

2.4.4.1 Summary of Technical Information in the Application

The applicant described the turbine building in LRA Section 2.4.4 and provided a list of

components subject to an AMR in LRA Table 2.4-4.

The purpose of the turbine building is the protection of the main turbine generators and other

plant equipment from environmental hazards and missiles, as well as providing structural

support for equipment and radiation shielding.

The turbine building is a common structure shared by both units at each station. Located in one

side or half of the turbine building are the turbine-generator, exciter, condenser, feedwater

heaters, feedwater and condensate pumps, demineralizer system, condenser circulating

system, and electrical switchgear. Duplicate equipment and systems for the other unit are

located in the other half of the building. Each turbine building superstructure consists of a

structural steel frame-type design with metal siding from the turbine floor up. All Class I

components in the turbine building are located in levels below the turbine main floor within a

reinforced concrete structure with capabilities similar to the reactor building. Large equipment,

located in the superstructure, is designed and supported to preclude failure that could damage

equipment related to the ECCS systems or cause significant release of radioactivity.

The building is a Class II structure and provides Class I protection in areas where Class I items

and associated SSCs are located. Exceptions are the swing emergency diesel generators and

Quad Cities emergency diesel generators which are evaluated in the emergency diesel

generator room. The turbine building cranes are evaluated with cranes and hoists.

The applicant identified the following UFSAR references for additional descriptive information

about the turbine building:

* Dresden Station UFSAR Section(s): 1.2.2.2

* Quad Cities Station UFSAR Section(s): 1.2.2.2

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The applicant defined the following intended functions for the turbine building.

* Physical support and protection-provides physical support and protection for safety-related

components and components relied upon to demonstrate compliance with regulated events.

* Radiation shielding-provides shielding that protects personnel and components from

radiation.

* Protection-provides missile barrier protection for internally and externally generated events

and the flood protection for SSCs.

In LRA Table 2.4-4, the applicant listed the following component groups requiring AMR for the

turbine building:

Component Component Intended Function LRA Aging Management Ref No.

Caulking/Sealants Structural Pressure Barrier 3.5.2.3, 3.5.2.4

Concrete and Grout Structural Support 3.5.1.29

Concrete and Grout Non-S/R Structural Support 3.5.1.29

Concrete Beams Structural Support 3.5.1.20, 3.5.1.27

Concrete Columns Structural Support 3.5.1.20

Concrete Curbs Direct Flow 3.5.1.20

Concrete Manholes Structural Support 3.5.1.20

Concrete Manholes Shelter, Protection, Shielding 3.5.1.20

Concrete Slabs Structural Support 3.5.1.20

Concrete Walls Structural Support 3.5.1.20

Fire Doors Fire Barrier 3.3.1.18

Fire Proofing Fire Banier 3.3.2.62

Fire Wrap Fire Barrier 3.3.2.63

Foundations Structural Support 3.5.1.20, 3.5.1.25, 3.5.1.26

Masonry Walls Structural Support 3.5.1.24

Masonry Walls Fire Barrier 3.3.2.129

Masonry Walls Shelter, Protection, Shielding 3.5.1.24

Masonry Walls Non-S/R Structural Support 3.5.1.24

Metal Siding Shelter, Protection, Shielding 3.5.1.20

Misc. Steel (includes Gratings, Non-S/R Structural Support 3.5.1.20

Ladders, Platforms, Railings, Stairs,

Kickplates)

Penetration Seals Flood Barrier 3.3.1.18

Penetration Sleeves Non-S/R Structural Support 3.5.1.20

Precast Concrete Panels Structural Support 3.5.1.20

Precast Concrete Panels Non-S/R Structural Support 3.5.1.20

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'' . '-; ' I'' 

, I I .-r; , :. X,6

Component Component Intended Function LRA Aging Management Ref No.

Roofing . Shelter, Protection, Shielding 3.5.2.11

Steel Doors Flood Barrier 3.5.1.20

Steel Doors Non-S/R Structural Support 3.5.1.20

Steel Doors Structural Pressure Barrier 3.5.1.20

Steel Embedments Structural Support. 3.5.1.20

Steel Panels and Cabinets Structural Support 3.5.1.20

Steel Plates Shelter, Protection, Shielding 3.5.1.20

Steel Plates (Dresden) Flood Barrier 3.5.1.20

Structural Steel Structural Support 3.5.1.20

Structural Steel Pipe Whip Restraint 3.5.1.20

Walls, Ceilings, Floors Fire Barrier 3.3.1.28

The applicant's AMR results for the turbine building are provided in LRA Sections 3.3 and 3.5.

2.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.4.4, Dresden Station UFSAR Section 1.2.2.2, and Quad

Cities Station UFSAR Section 1.2.2.2 to determine whether the turbine building structural

components within the scope of license renewal and subject to an AMR have been identified in

accordance with 10 CFR 54.4 and 54.21(a)(1).

In the performance of the review, the staff selected system functions described in the UFSAR

that are required by 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

LRA Table 2.4-4 presents a comprehensive list of structural components for the turbine

building. The staff did not identify any omissions made by the applicant.

2.4.4.3 Conclusions

The staff reviewed LRA Section 2.4.4 to determine whether any structural components of the

turbine building that should be within the scope'of license renewal were not identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. On the

basis of its review, the staff concludes that the applicant has adequately'identified the structural

components of the turbine building that are within the scope of license renewal, as required by

10 CFR 54(a), and that the applicant has adequately identified the structural components of the

turbine building that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.4.5 Diesel Generator Buildings

2.4.5.1 Summary of Technical Information in the Application

The applicant described the diesel generator buildings in LRA Section 2.4.5 and provided a list

of components subject to an AMR in LRA Table 2.4-5. The purpose of the diesel generator

buildings is to provide structural support and protection of the emergency diesel generators and

HPCI system components (Dresden only).

The diesel generator buildings contain the Dresden Unit 2/3 (swing) emergency diesel

generator and HPCI building (a structure which includes both the swing diesel generator and

HPCI system components) and the Quad Cities Unit 1/2 and 1/2 (swing) emergency diesel

generator rooms.

The Dresden diesel generator and HPCI building is a Class I concrete structure that houses the

Unit 2/3 (swing) emergency diesel generator, HPCI system equipment, and other safe

shutdown equipment. It abuts the Unit 3 reactor building and shares the reactor building wall

on its north side. The Dresden Unit 2 and 3 emergency diesel generators are housed in the

turbine building.

The three Quad Cities diesel generator rooms are Class 11 concrete structures that have been

evaluated to ensure that they have the capability to protect safety-related components. The

rooms provide structural support and protection of the emergency diesel generators as well as

fire protection of adjacent safety-related structures. The Unit 1 diesel generator room is located

in the southeast corner of the Unit 1 section of the turbine building. The Unit 2 diesel generator

room is located in the northeast corner of the Unit 2 section of the turbine building. The Unit 1/2

(swing) diesel generator room is adjacent to the reactor building. It is centered on the reactor

building east wall, which is shared with the Unit 1/2 diesel generator room.

The applicant identified the following UFSAR references for additional descriptive information

about the diesel generator buildings:

* Dresden Station UFSAR Section(s): 3.2.6, 8.3

* Quad Cities Station UFSAR Section(s): 3.2.6, 8.3.1.6.1

The applicant defined the following intended functions for the diesel generator buildings.

* Physical support and protection-provides physical support and protection for safety-related

components and components relied upon to demonstrate compliance with fire protection

and SBO-regulated events (Dresden only).

* Containment-provides a leak-tight barrier protecting the health and safety of the public in

the event of any postulated design-basis events and also provides a secondary containment

boundary (Dresden 2/3 diesel generator room only)

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Protection-provides missile barrier for internally and externally generated events.

In LRA Table 2.4-5, the applicant listed the following component groups requiring AMR for the

diesel generator buildings:

Component Component Intended Function LRA Aging Management Ref No.

Concrete and Grout Structural Support 3.5.1.29

Concrete and Grout Non-S/R Structural Support 3.5.1.29

Concrete Beams (Dresden) Structural Support 3.5.1.20

Concrete Curbs Direct Flow 3.5.1.20

Concrete Shield Plugs (Dresden) Structural Support 3.5.1.20

Concrete Shield Plugs (Dresden) Fire Barrier 3.3.1.28

Concrete Shield Plugs (Dresden) Shelter, Protection, Shielding 3.5.1.20

Concrete Slabs Structural Support 3.5.1.20

Concrete Slabs Shelter, Protection, Shielding 3.5.1.20

Concrete Walls Structural Support 3.5.1.20, 3.5.1.21,3.5.1.27

Concrete Walls Shelter, Protection, Shielding 3.5.1.20

Concrete Walls Missile Barrier 3.5.1.20

Fire Doors Fire Barrier 3.3.1.18

Fire Proofing Fire Barrier 3.3.2.62

Fire Wrap Fire Barrier 3.3.2.63

Foundations (Dresden) Structural Support 3.5.1.20

Masonry Walls (Dresden) Structural Support 3.5.1.24

Masonry Walls (Dresden) Fire Barrier 3.3.2.129

Metal Decking (Quad Cities) Structural Support 3.5.1.20

Misc. Steel (includes Ladders, Non-S/R Structural Support 3.5.1.20

Railings, Stairs, Gratings, Kick

Plates, Platforms) ._ . _ . _ :

Penetration Seals (Dresden) Fire Barrier 3.3.1.18

Penetration Sleeves Non-S/R Structural Support 3.5.1.20

Penetration Sleeves (Quad Cities) Structural Pressure Barrier 3.5.1.20

Steel Doors (Dresden) Structural Pressure Barrier 3.5.1.20

Steel Embedments Structural Support - 3.5.1.20

Steel Panels and Cabinets Structural Support 3.5.1.20

Steel Plates (Dresden) Direct Flow 3.5.1.20

Structural Steel Structural Support 3.5.1.20

Walls, Ceilings, Floors Fire Barrier 3.3.1.28

The applicant's AMR results for the diesel generator buildings are provided in LRA Sections 3.3

and 3.5.

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2.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.4.5, Dresden Station UFSAR Sections 3.2.6 and 8.3, and

Quad Cities Station UFSAR Sections 3.2.6 and 8.3.1.6.1 to determine whether the diesel

generator buildings structural components within the scope of license renewal and subject to an

AMR have been identified in accordance with 10 CFR 54.4 and 54.21 (a)(1).

In the performance of the review, the staff selected system functions described in the UFSAR

that are required by 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR, to determine if any components were omitted.

LRA Table 2.4-5 presents a comprehensive list of structural components for the diesel

generator buildings. The staff did not identify any omissions made by the applicant.

2.4.5.3 Conclusions

The staff reviewed LRA Section 2.4.5 to determine whether any structural components of the

diesel generator buildings that should be within the scope of license renewal were not identified

by the applicant. In addition, the staff performed an independent assessment to determine

whether any components that should be subject to an AMR were not identified by the applicant.

On the basis of its review, the staff concludes that the applicant has adequately identified the

structural components of the diesel generator buildings that are within the scope of license

renewal, as required by 10 CFR 54(a), and that the applicant has adequately identified the

structural components of the diesel generator buildings that are subject to an AMR, as required

by 10 CFR 54.21 (a)(1).

2.4.6 Station Blackout Building and Yard Structures

2.4.6.1 Summary of Technical Information in the Application

The applicant described the station blackout (SBO) building and yard structures in LRA Section

2.4.6 and provided a list of components subject to an AMR in LRA Table 2.4-6.

The SBO building provides structural support and environmental protection for the SBO diesel

generators and associated components. The offsite power structures are to provide sufficient

capacity and capability to start and operate safety-related equipment.

Other structures grouped with the SBO building for evaluation are offsite power structures and

foundations associated with the reserve auxiliary transformers, dead-end structures, bus duct

supports and intermediate transmission towers. For both stations, the bus duct supports, dead

end structures, and intermediate transmission towers are either galvanized or coated steel with

reinforced concrete foundations. Foundations for supporting transformers and circuit breakers

are also reinforced concrete.

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Structural boundaries include the physical extent of the circuit breaker foundations in the

switchyards serving the reserve auxiliary transformer, 345-kV and 1 38-kV-dead end structures,

intermediate transmission towers serving the reserve auxiliary transformer, 345-kV and 138-kV

dead end structures serving adjacent to the reserve auxiliary trarisformer (Dresden only),

reserve auxiliary transformer foundations, and bus ducts and their supports and foundations

terminating at the turbine building (Dresden) and terminating at the diesel generator/turbine

building (Quad Cities).

The Dresden SBO building is a Class I structure that houses the SBO diesel generators and

safety-related components, including the Unit 2 alternate 125V DC batteries. It is a heavy--

walled, reinforced concrete structure capable of protecting its contents from weather-related

events that could initiate an SBO event. The underground diesel oil tank foundation on the

eastern side of the building supports the 1 5,000-gallon fuel tank.

The Quad Cities SBO building protects the diesel generators and associated components from

weather-related events, which could initiate an SBO event, and provides physical isolation from

safety-related components. It is a two-floor structure consisting of a reinforced concrete ground

floor slab/foundation, steel framed exterior walls with corrugated metal siding, metal deck

supported concrete slab second floor, and a roof consisting of a fully adhered single-ply system

on rigid insulation supported by metal decking. The SBO diesel generators are supported

within the building by independent reinforced concrete foundation slabs. Fire-rated block walls

separate the Unit 1 and 2 diesel generator rooms, the day tank rooms, and the second floor

battery rooms.

The applicant identified the following UFSAR references for additional descriptive information

about the SBO building and yard structures:

* Dresden Station UFSAR Section(s): 9.5.9, 8.2

* Quad Cities Station UFSAR Section(s): 8.3.1.9, 8.2

The applicant defined the following intended function for the SBO building and yard structures.

* Physical support and protection-provides physical support and protection for safety-related

components and components relied upon to demonstrate compliance with the SBO

regulated event. For Quad Cities only, the structure also provides protection for

components relied upon to demonstrate compliance with the fire protection regulated event.

In LRA Table 2.4-6, the applicant listed the following component groups requiring AMR for the

SBO building and yard structures:

Component Component Intended Function LRA Aging Management Ref No.

Bus Duct Covers Non-S/R Structural Support 3.5.2.1

Bus Duct Supports Non-S/R Structural Support 3.5.2.2

Caulking/Sealants Flood Barrier 13.5.2.4

Caulking/Sealants Expansion/Separation 13.5.2.4

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Component Component Intended Function LRA Aging Management Ref No.

Concrete and Grout Structural Support 3.5.1.29

Concrete and Grout Non-S/R Structural Support 3.5.1.29

Concrete Curbs Direct Flow 3.5.1.20

Concrete Manholes (Quad Cities) Structural Support 3.5.1.20

Concrete Manholes (Quad Cities) Non-S/R Structural Support 3.5.1.20. 3.5.1.21

Concrete Slabs Structural Support 3.5.1.20

Concrete Slabs Non-S/R Structural Support 3.5.1.20

Concrete Walls (Dresden) Structural Support 3.5.1.20, 3.5.1.21

Dead End Structures Non-S/R Structural Support 3.5.2.6

Doors Fire Barrier 3.3.1.18

Fire Proofing Fire Barrier 3.3.2.62

Fire Wrap Fire Barrier 3.3.2.63

Foundations Structural Support 3.5.1.20, 3.5.1.25, 3.5.1.26, 3.5.1.27

Foundations Non-S/R Structural Support 3.5.1.20

Masonry Walls Structural Support 3.5.1.24

Masonry Walls Fire Barrier 3.3.2.129

Masonry Walls Shelter, Protection, Shielding 3.5.1.24

Metal Decking Non-S/R Structural Support 3.5.1.20

Metal Decking (Dresden) Shelter, Protection, Shielding 3.5.1.20

Misc. Steel (Dresden-includes Non-SIR Structural Support 3.5.1.20

Gratings, Kick Plates, Ladders,

Platforms, Railings)

Penetration Seals (Quad Cities) Fire Barrier 3.3.1.18

Penetration Seals (Quad Cities) Expansion/Separation 3.3.1.18

Penetration Sleeves Non-S/R Structural Support 3.5.1.20

Steel Embedments Structural Support 3.5.1.20

Steel Panels and Cabinets Non-S/R Structural Support 3.5.1.20

Steel Piles (Dresden) Non-S/R Structural Support 3.3.2.207

Steel Plates (Dresden) Missile Barrier 3.5.1.20

Structural Steel Non-S/R Structural Support 3.5.1.20

Transmission Towers Non-S/R Structural Support 3.5.2.16

Walls, Ceilings, Floors Fire Barrier 3.3.1.28

The applicant's AMR results for the SBO building and yard structures are provided in LRA

Sections 3.3 and 3.5.

2.4.6.2 Staff Evaluation

The staff reviewed LRA Section 2.4.6, Dresden Station UFSAR Sections 9.5.9 and 8.2, and

Quad Cities Station UFSAR Sections 8.3.1.9 and 8.2 to determine whether the SBO building -

and yard structures structural components within the scope of license renewal and subject to an

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AMR have been identified in accordance with 10 CFR 54.4 and 54.21 (a)(1).

In the performance of the review, the staff selected system functions described in the UFSAR

that are required by 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

Based on information provided in LRA Section 2.4.6, the exact scope of structural components

included in this section was not clear to the staff. Also, clarification was needed for several

"Components" listed in Table 2.4-6.

In order to complete the screening review for the SBO building and yard structures, the staff

requested, in RAI 2.4-5, the applicant to submit the following information:

(a) LRA Table 2.4-6 lists the following components requiring an AMR-"bus duct covers," "bus

duct supports," "dead-end structures," and "transmission towers." These appear to be the

yard structures. The staff asked the applicant to verify that this interpretation is correct, or

to describe more completely the yard structures included in the scope of this section.

(b) The staff has assumed that the foundations for the bus duct supports, dead end structures,

and transmission towers, and also for the transformers and circuit breakers are included

with the SBO building foundation under the LRA Table 2.4-6 component group

'foundations." The staff asked the applicant to verify that this interpretation is correct, or to

describe more completely the foundations included in the scope of this section.

(c) The component "steel piles (Dresden only)" is also listed in LRA Table 2.4-6. LRA Section

2.4.6 provides no description of the steel piles. The staff asked the applicant to describe

the steel piles at Dresden and define their intended function(s). The applicant should also

explain why the "Aging Management Ref" for the steel piles is 3.3.2.207. LRA Section 3.3

covers Auxiliary Systems. The staff believes this may be a documentation error in the LRA.

In its response to RAI 2.4-5, the applicant stated the following:

Exelon has reviewed LRA Section 2.4.6, Table 2.4-6, and provides the following clarifications:

(a) Components Groups 'Bus Duct Covers,' "Bus Duct Supports," "Dead End Structures,' and

"Transmission Towers" are yard structures that require aging management review. Initially, these were not included within the scope of license renewal and were included in

Miscellaneous Yard Structures discussed in the response to RAI 2.4-1. The Station Blackout

offsite power feeds were not initially included in scope. However, these specific component

groups were later added to the scope of License Renewal to comply with interim staff

guidance concerning scoping of offsite power systems necessary to support the Station

Blackout Rule (10 CFR 50.63). As such, they were evaluated with the Station Blackout

Building in section 2.4.6 of the LRA. These component groups are not included in

"Miscellaneous Yard Structures" shown on Table 2.2-1, which is a grouping of yard structures

that do not satisfy the requirements of 10 CFR 54(a).

(b) Table 2.4-6, component Groups Requiring Aging Management Review - Station Blackout

Building, contains two foundation groups. The foundation group with the "Non-S/R Structural

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Support' component function includes the foundations for the bus duct supports, dead end

structures, and breaker foundations serving the Reserve Auxiliary Transformers and

Transmission Towers. The foundation group with the 'Structural Support component function

includes the Station Blackout Building foundations.

(c) The component group 'steel piles (Dresden only)" listed in LRA Table 2.4-6 are associated

with a transmission tower that carries power transmission cables from the switch yard to

Reserve Auxiliary Transformer 22 located outside of the Turbine Building. The concrete

foundation for this transmission tower is supported by seven steel "H' piles resting on

bedrock. The steel piles provide structural support for the transmission tower and associated

concrete foundation. Aging Management Reference 3.3.2.207 accurately evaluates the aging

of these steel piles. However, the aging management reference for these steel piles was

inadvertently included in LRA Table 3.3-2 and should have been included in LRA Table 3.5-2.

Table 2.4-6 line item for Steel Piles (Dresden only) should have read as follows:

Component Component Intended Function LRA Aging Management Ref No.

Steel Piles (Dresden only) Non-S/R Structural Support 3.5.2.17

Table 3.5-2 should have included a new line item that is identical to 3.3.2.207, as follows:

Ref No. Component Material Environment Aging Aging Discussion

Group Effect/Mechanism Management

Program

3.5.2.17 Steel Piles Carbon Soil and None None NUREG-1801 does

Steel groundwater not address carbon

steel piles in a soil and

ground water

environment. The

intended function of

steel piles driven in

undisturbed soils is

not affected by

corrosion.

The additional information provided by the applicant in its RAI response sufficiently answers the

three questions posed by the staff and how each is covered in the AMR. The staff concludes

that the applicant has appropriately addressed these components in its scoping and screening

review. The staff's evaluation of the AMR for "steel piles (Dresden only)" is in Section 3.5 of

this SER. Therefore, RAI 2.4-5, is resolved.

2.4.6.3 Conclusions

The staff reviewed LRA Section 2.4.6 to determine whether any structural components of the

SBO building and yard structures that should be within the scope of license renewal were not

identified by the applicant. In addition, the staff performed an independent assessment to

determine whether any components that should be subject to an AMR were not identified by the

applicant. On the basis of its review, the staff concludes that the applicant has adequately

identified the structural components of the SBO building and yard structures that are within the

scope of license renewal, as required by 10 CFR 54(a), and that the applicant has adequately

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. . ' A

identified the structural components of the SBO building and yard structures that are subject to

an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.7 Isolation Condenser Pump House (Dresden)

2.4.7.1 Summary of Technical Information in the Application

The applicant described the isolation condenser pump house (Dresden) in LRA Section 2.4.7

and provided a list of components subject to an AMR in LRA Table 2.4-7.

The isolation condenser pump house provides structural support and environmental protection

for the two diesel-driven isolation condenser makeup water pumps.

The isolation condenser pump house is a two-floor Class II structure with the first floor at grade

and the other floor being a reinforced concrete basement. The above-grade exterior north,

south, and east walls, as well as an interior center wall, are constructed of concrete block. The

west wall that borders the reactor building is reinforced concrete with Rodofoam seismic gap

separation at the reactor building wall. The first floor is a metal deck supported concrete slab.

The roof consists of a single-ply system on rigid insulation supported by metal decking on

structural steel.

The applicant identified the following UFSAR references for additional descriptive information

about the isolation condenser pump house (Dresden):

* Dresden Station UFSAR Section(s): 5.4.6

* Quad Cities UFSAR Section(s): Not Applicable

The applicant defined the following intended function for the isolation condenser pump house

(Dresden).

* Credited in regulated events-provides physical support and protection for components

relied upon to demonstrate compliance with the fire protection regulated event.

In LRA Table 2.4-7, the applicant listed the following component groups as requiring AMR for

the isolation condenser pump house (Dresden):

Component Component Intended Function LRA Aging Management Ref No.

Caulking/Sealants (Dresden) Expansion/Separation 3.5.2.4

Concrete Duct Banks (Dresden) Non-SIR Structural Support 3.5.1.21

Concrete Walls (Dresden) Structural Support 3.5.1.20

Concrete Walls (Dresden) Non-SIR Structural Support 3.5.1.20

Doors (Dresden) Fire Barrier 3.3.1.18

Foundations (Dresden) Structural Support .3.5.1.20, 3.5.1.21, 3.5.1.25, 3.5.1.26

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Component Component Intended Function LRA Aging Management Ref No.

Foundations (Dresden) Non-S/R Structural Support 3.5.1.20

Masonry Walls (Dresden) Structural Support 3.5.1.24

Masonry Walls (Dresden) Fire Barrier 3.3.2.129

Masonry Walls (Dresden) Non-S/R Structural Support 3.5.1.24

Metal Decking (Dresden) Shelter, Protection, Shielding 3.5.1.20

Metal Decking (Dresden) Non-SIR Structural Support 3.5.1.20

Penetration Seals (Dresden) Fire Barrier 3.3.1.18

Penetration Sleeves (Dresden) Non-S/R Structural Support 3.5.1.20

Roofing (Dresden) Shelter, Protection, Shielding 3.5.2.11

Seismic Gap Filler (Dresden) Expansion/Separation 3.5.2.13

Steel Doors (Dresden) Non-S/R Structural Support 3.5.1.20

Steel Embedments (Dresden) Structural Support 3.5.1.20

Steel Panels and Cabinets Non-S/R Structural Support 3.5.1.20

(Dresden)

Structural Steel (Dresden) Non-S/R Structural Support 3.5.1.20

Walls, Ceilings, Floors (Dresden) Fire Barrier 3.3.1.28

The applicant's AMR results for the isolation condenser pump house are provided in LRA

Sections 3.3 and 3.5.

2.4.7.2 Staff Evaluation

The staff reviewed LRA Section 2.4.7 and Dresden Station UFSAR Section 5.4.6 to determine

whether the isolation condenser pump house (Dresden only) structural components within the

scope of license renewal and subject to an AMR have been identified in accordance with 10

CFR 54.4 and 54.21 (a)(1).

In the performance of the review, the staff selected system functions described in the UFSAR

that are required by 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR, to determine if any components were omitted.

LRA Table 2.4-7 presents a comprehensive list of structural components for the isolation

condenser pump house (Dresden). The staff did not identify any omissions made by the

applicant.

2.4.7.3 Conclusions

The staff reviewed LRA Section 2.4.7 to determine whether any structural components of the

isolation condenser pump house (Dresden only) that should be within the scope of license

renewal were not identified by the applicant. In addition, the staff performed an independent

assessment to determine whether any components that should be subject to an AMR were not

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identified by the applicant. On the basis of its review, the staff concludes that the applicant has

adequately identified the structural components of the isolation condenser pump house

(Dresden only) that are within the scope of license renewal, as required by 10 CFR 54(a), and

that the applicant has adequately identified the structural components of the isolation

condenser pump house (Dresden only) that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.4.8 Makeup Demineralizer Building (Dresden)

2.4.8.1 Summary of Technical Information in the Application

The applicant described the makeup demineralizer building (Dresden) in LRA Section 2.4.8 and

provided a list of components subject to an AMR in LRA Table 2.4-8. The makeup

demineralizer building at Dresden provides support and protection for instrumentation required

for remote monitoring of water level of the "B" contaminated condensate storage tank in the

event that the main control room is evacuated due to fire.

The makeup demineralizer building is a preengineered steel building that includes an interior

reinforced concrete slab, anchor bolt hardware, instrument rack, and foundation support for the

level indicator.

The applicant did not identify any UFSAR references for the Dresden makeup demineralizer

building.

The applicant defined the following intended function for the makeup demineralizer building

(Dresden).

Physical support and protection-provides physical support and protection for components

relied upon to demonstrate compliance with the fire protection regulated event.

In LRA Table 2.4-8, the applicant listed the following component groups requiring AMR for the

makeup demineralizer building (Dresden):

Component Component Intended Function LRA Aging Management Ref No.

Concrete and Grout (Dresden) Structural Support 3.5.1.29

Concrete Slabs (Dresden) Structural Support 3.5.1.20

Concrete Slabs (Dresden) Non-SIR Structural Support 3.5.1.20

Foundations (Dresden) Structural Support 3.5.1.20, 3.5.1.21, 3.5.1.25, 3.5.1.26, _______ ___ ___ ____ ___ ___ 3.5.1.27

Foundations (Dresden) Non-S/R Structural Support 3.5.1.20

Metal Decking (Dresden) Shelter, Protection, Shielding 3.5.1.20

Metal Siding (Dresden) Shelter, Protection, Shielding 3.5.1.20

Steel Doors (Dresden) Shelter, Protection, Shielding 3.5.1.20

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Component Component Intended Function LRA Aging Management Ref No.

Steel Panels and Cabinets Structural Support 3.5.1.20

(Dresden) I

Structural Steel (Dresden) Non-S/R Structural Support 3.5.1.20

The applicant's AMR results for the makeup dernineralizer building are provided in LRA Section

3.5.

2.4.8.2 Staff Evaluation

The staff reviewed LRA Section 2.4.8 to determine whether the makeup demineralizer building

(Dresden) structural components within the scope of license renewal and subject to an AMR

have been identified in accordance with 10 CFR 54.4 and 54.21(a)(1).

In the performance of the review, the staff selected system functions that are required by

10 CFR 54.4 to verify that components having intended functions were not omitted from the

scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

LRA Table 2.4-8 presents a comprehensive list of structural components for the makeup

demineralizer building (Dresden). The staff did not identify any omissions made by the

applicant.

2.4.8.3 Conclusions

The staff reviewed LRA Section 2.4.8 to determine whether any structural components of the

makeup demineralizer building (Dresden) that should be within the scope of license renewal

were not identified by the applicant. In addition, the staff performed an independent

assessment to determine whether any components that should be subject to an AMR were not

identified by the applicant. On the basis of its review, the staff concludes that the applicant has

adequately identified the structural components of the makeup demineralizer building (Dresden)

that are within the scope of license renewal, as required by 10 CFR 54(a), and that the

applicant has adequately identified the structural components of the makeup demineralizer

building (Dresden) that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.9 Radwaste Floor Drain Surge Tank

2.4.9.1 Summary of Technical Information in the Application

The applicant described the radwaste floor drain surge tank in LRA Section 2.4.9 and provided

a list of components subject to an AMR in LRA Table 2.4-9. The floor drain surge tank provides

the necessary surge volume for the floor drain system, which collects potentially radioactive

liquids.

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The aboveground floor drain surge tank has thick reinforced concrete walls for shielding and

electric heaters to prevent freezing during cold weather. The tank bottom is sloped to reduce

sludge buildup. The floor drain surge tank is a Class I structure and is, therefore, not

considered an aboveground tank for the purpose of the curies content requirements. The floor

drain surge tank includes the attached pump house structure, foundations, floors, walls, roof,

and stainless steel liner.

The applicant identified the following UFSAR references for additional descriptive information

about the radwaste floor drain surge tank:

* Dresden Station UFSAR Section(s): 11.2, 3.2.1

* Quad Cities Station UFSAR Section(s): 11.2

The applicant defined the following intended function for the radwaste floor drain surge tank:

* Radioactive fluid containment-provides physical barrier and support to contain potentially

radioactive liquid waste.

In LRA Table 2.4-9, the applicant listed the following component groups requiring AMR for the

radwaste floor drain surge tank:

Component Component Intended Function LRA Aging Management Ref No.

Concrete Manholes Structural Support 3.5.1.20, 3.5.1.21

Concrete Manholes Shelter, Protection, Shielding 3.5.1.20

Concrete Slabs Structural Support 3.5.1.20

Concrete Slabs Shelter, Protection, Shielding 3.5.1.20

Concrete Walls Structural Support 3.5.1.20

Concrete Walls Shelter, Protection, Shielding 3.5.1.20

Foundations Structural Support 3.5.1.20, 3.5.1.21, 3.5.1.25, 3.5.1.26

Liners Structural Pressure Barrier 3.5.1.28

Steel Embedments Structural Support 3.5.1.20

The applicant's AMR results for the radwaste floor drain surge tank are provided in LRA Section

3.5.

2.4.9.2 Staff Evaluation

The staff reviewed LRA Section 2.4.9, Dresden Station UFSAR Sections 11.2 and 3.2.1, and

* Quad Cities Station UFSAR Section 11.2 to determine whether the radwaste floor drain surge

tank structural components within the scope of license renewal and subject to an AMR have

been identified in accordance with 10 CFR 54.4 and 54.21 (a)(1).

In the performance of the review, the staff selected system functions described in the UFSAR

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that are required by 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

LRA Table 2.4-9 presents a comprehensive list of structural components for the radwaste floor

drain surge tank. The staff did not identify any omissions, the component groups are clearly

identified, and all component groups reference LRA Section 3.5 for the AMR results.

2.4.9.3 Conclusions

The staff reviewed LRA Section 2.4.9 to determine whether any structural components of the

radwaste floor drain surge tank that should be within the scope of license renewal were not

identified by the applicant. In addition, the staff performed an independent assessment to

determine whether any components that should be subject to an AMR were not identified by the

applicant. On the basis of its review, the staff concludes that the applicant has adequately

identified the structural components of the radwaste floor drain surge tank that are within the

scope of license renewal, as required by 10 CFR 54(a), and that the applicant has adequately

identified the structural components of the radwaste floor drain surge tank that are subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.4.10 Miscellaneous Foundations

2.4.10.1 Summary of Technical Information in the Application

The applicant described the miscellaneous foundations in LRA Section 2.4.10 and provided a

list of components subject to an AMR in LRA Table 2.4-10.

The contaminated condensate storage tank foundations provide physical support for the nonsafety-related contaminated condensate storage tanks.

The diesel generator fuel oil storage tank foundations provide structural support for the safetyrelated diesel generator fuel oil storage tanks.

The condensate storage facilities provide a storage volume for clean and potentially

contaminated water of suitable quality for use in the reactor and other systems throughout the

plant. The Dresden condensate storage facilities ensure that an adequate amount of water is

available from each contaminated condensate storage tank for use by HPCI pumps. The Quad

Cities condensate storage facilities ensure that an adequate amount of water is available from

each contaminated condensate storage tank for use by HPCI, RCIC, and safe shutdown

pumps. The contaminated condensate storage tank foundations are Class II reinforced

concrete foundations and include anchor bolts.

Each diesel generator fuel oil storage tank, except for the Quad Cities Unit 1 fiberglass tank, is

supported on three reinforced concrete foundation pads and anchored with anchor bolts (four

per pad). The Quad Cities Unit 1 fiberglass tank is anchored to two reinforced concrete

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foundations and is restrained in place by stainless steel straps and turnbuckle assemblies.

The applicant identified the following UFSAR references for additional descriptive information

about the miscellaneous foundations:

* Dresden Station UFSAR Section(s): 9.2.6, 9.5.4

* Quad Cities Station UFSAR Section(s): 9.2.6, 9.5.4

The applicant defined the following intended functions for the miscellaneous foundations:

Contaminated Condensate Storage Tank Foundations

* * Regulated event component support-provides support for components relied upon to

demonstrate compliance with fire protection, ATWS, and SBO regulated events.

Diesel Generator Fuel Oil Storage Tank Foundations

* Safety-related component support-provides support for safety-related, seismically qualified

fuel oil storage tanks provided for emergency diesel generators.

In LRA Table 2.4-10, the applicant listed the following component groups requiring AMR for the

miscellaneous foundations:

Component Component Intended Function LRA Aging Management Ref No.

Caulking/Sealants (Dresden) Shelter, Protection, Shielding 3.5.2.4

Foundations . Structural Support 3.5.1.20, 3.5.1.21, 3.5.1.25, 3.5.1.26

Foundations Non-S/R Structural Support 3.5.1.20, 3.5.1.26

Steel Embedments (Quad Cities) Structural Support 3.5.1.20

The applicant's AMR results for miscellaneous foundations are provided in LRA Section 3.5.

2.4.10.2 Staff Evaluation

The staff reviewed LRA Section 2.4.10, Dresden Station UFSAR Sections 9.2.6 and 9.5.4, and

Quad Cities Station UFSAR Sections 9.2.6 and 9.5.4 to determine whether the miscellaneous

foundations structural components within the scope of license renewal and subject to an AMR

have been identified in accordance with 10 CFR 54.4 and 54.21(a)(1).

In the performance of the review, the staff selected system functions described in the UFSAR

that are required by 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

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LRA Table 2.4-10 presents the list of structural components applicable to the miscellaneous

foundations. The staff did not identify any omissions and all component groups reference LRA

Section 3.5 for the AMR results.

However, the applicant's description of the miscellaneous foundations does not explain the

component 'Caulking/Sealants (Dresden)." It was not clear to the staff what the application

would be for foundations. The applicant was requested in RAI 2.4-6 to submit a detailed

description of this component and its intended function.

In its response to RAI 2.4-6, the applicant stated the following:

The Component Group, 'CaulkinglSealants (Dresden Only)," is a rubber sealant (type-A) used to

seal the Contaminated Condensate Storage Tank between the foundation and tank bottom. The

sealant prevents moisture from entering the area between the concrete foundation and the tank

bottom, preventing exposure of embedded anchor bolts to moisture.

The additional information provided by the applicant in its RAI response sufficiently answers the

question posed by the staff. The staff concludes that the applicant has appropriately addressed

this component in its scoping and screening review. RAI 2.4-6 is, therefore, resolved.

2.4.10.3 Conclusions

The staff reviewed LRA Section 2.4.10 to determine whether any structural components of the

miscellaneous foundations that should be within the scope of license renewal were not

identified by the applicant. In addition, the staff performed an independent assessment to

determine whether any components that should be subject to an AMR were not identified by the

applicant. On the basis of its review, the staff concludes that the applicant has adequately

identified the structural components of the miscellaneous foundations that are within the scope

of license renewal, as required by 10 CFR 54(a), and that the applicant has adequately

identified the structural components of the miscellaneous foundations that are subject to an

AMR, as required by 10 CFR 54.21 (a)(1).

2.4.11 Crib House

2.4.11.1 Summary of Technical Information in the Application

The applicant described the crib house in LRA Section 2.4.11 and provided a list of components

subject to an AMR in LRA Table 2.4-11. The crib house serves as the entry point for river water

into plant systems. It protects and supports the pumps and pipes which deliver river water to

the plant. The crib house is a reinforced concrete structure with a concrete block and steel

superstructure. It contains the circulating water, service water and diesel-driven fire pumps.

At Dresden, the crib house includes the diesel generator cooling water pumps and the suction

piping for the containment cooling service water system pumps. The diesel generator cooling

water pumps and the containment cooling service water system are safety-related. The crib

house also contains stop logs that can be used to isolate the compartment and raise its water

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level where the containment cooling service watersystem pump and the diesel fire pump take

their suction. The crib house is classified as Class II and was investigated to assure that the

integrity of the Class I items is not compromised.

At Quad Cities, the crib house includes the suction lines for the RHR service water system.

The RHR service water system is safety-related. The crib house is classified as Class II and

was investigated to assure that it will not fail and isolate the plant from the river water source.

For license renewal evaluation purposes, the Quad Cities discharge flume weir wall that forms

one of the boundaries of the ultimate heat sink is included as part of the crib house.

The applicant identified the following UFSAR references for additional descriptive information

about the crib house:

* Dresden Station UFSAR Section(s): 1.2.2.2, 3.3.2.3.2, 3.8.5, 9.2.5, and 9.5.5

* Quad Cities Station UFSAR Section(s): 3.3, 3.8.6, and 9.2.5

The applicant defined the following intended functions for the crib house:

* Physical support and protection-provides physical support and protection for safety-related

components and components relied upon to demonstrate compliance with the fire protection

regulated event.

* Heat sink-provides heat sink during SBO or design-basis events.

* Water source-provides source of cooling water for plant shutdown.

In LRA Table 2.4-11, the applicant listed the following component groups requiring AMR for the

crib house:

Component Component Intended Function LRA Aging Management Ref No.

Concrete and Grout Structural Support 3.5.1.29

Concrete and Grout Non-S/R Structural Support 3.5.1.29

Concrete Canal Weirs (Quad Cities) Heat Sink 3.5.1.22

Concrete Curbs Direct Flow 3.5.1.22

Concrete Slabs Structural Support 3.5.1.22,3.5.1.26

Concrete Slabs Shutdown Cooling Water 3.5.1.22

Concrete Slabs Heat Sink 3.5.1.22,3.5.1.26

Concrete Stairs Structural Support 3.5.1.22

Concrete Stairs Non-SIR Structural Support 3.5.1.22

Concrete Walls Structural Support 3.5.1.22

Concrete Walls Non-S/R Structural Support 3.5.1.22

Concrete Walls Shutdown Cooling Water 3.5.1.22

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Component Component Intended Function LRA Aging Management Ref No.

Concrete Walls Heat Sink 3.5.1.22

Fire Doors (Dresden) Fire Barrier 3.3.1.18

Foundations Structural Support 3.5.1.22, 3.5.1.26

Foundations Non-S/R Structural Support 3.5.1.22

Masonry Walls Structural Support 3.5.1.24

Masonry Walls Shelter, Protection, Shielding 3.5.1.24

Metal Siding (Dresden) Shelter, Protection, Shielding 3.5.1.22

Misc. Steel (Dresden) Non-S/R Structural Support 3.5.1.22

Misc. Steel (Dresden) Direct Flow 3.5.1.22

Precast Concrete Panels Structural Support 3.5.1.22

Precast Concrete Panels Shelter, Protection, Shielding 3.5.1.22

Roofing Shelter, Protection, Shielding 3.5.2.11

Steel Embedments Structural Support 3.5.1.20, 3.5.1.22

Steel Embedments (Dresden) Non-S/R Structural Support 3.5.1.22

Steel Panels and Cabinets Structural Support 3.5.1.20, 3.5.1.22

Steel Panels and Cabinets (Quad Non-S/R Structural Support 3.5.1.20

Cities)

Steel Plates (Dresden) Direct Flow 3.5.1.22

Steel Sump Screens (Quad Cities) Non-S/R Structural Support 3.5.1.22

Structural Steel Non-S/R Structural Support 3.5.1.22

Walls, Ceilings, Floors Fire Barier 3.3.1.28

The applicant's AMR results for the crib house are provided in LRA Sections 3.3 and 3.5.

2.4.11.2 Staff Evaluation

The staff reviewed LRA Section 2.4.11, Dresden Station UFSAR Sections 1.2.2.2, 3.3.2.3.2,

3.8.5, 9.2.5, and 9.5.5, and Quad Cities Station UFSAR Sections 3.3, 3.8.6, and 9.2.5 to

determine whether the crib house structural components within the scope of license renewal

and subject to an AMR have been identified in accordance with 10 CFR 54.4 and 54.21 (a)(1).

In the performance of the review, the staff selected system functions described in the UFSAR

that are required by 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

UFSAR Section 9.2.5 describes the ultimate heat sink for each of the stations. A summary of

these descriptions is contained in LRA Section 2.3.3.22, "Ultimate Heat Sink." The staff

reviewed this information in depth in order to ensure that all structures and structural

components, including earthen embankments, that are necessary to guarantee the ultimate

heat sink have been identified to be within the scope of license renewal and subject to an AMR.

To complete its review of LRA Section 2.4.11, the staff required a number of clarifications

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I

i
concerning the ultimate heat sink at both stations.

Quad Cities: LRA Section 2.4.11 Crib House states that at Quad Cities, the crib house includes

the suction lines for the RHR service water system. It also states that for license renewal

purposes, the Quad Cities discharge flume weir wall that forms one of the boundaries of the

ultimate heat sink is included as part of the crib house. To complete the review the staff

requested the following information:

(a) Clarify why the suction lines for the Quad Cities diesel generator cooling water pumps are

not included in the discussion since they are described in LRA Section 2.3.3.22 as taking

suction from the crib house.

(b) Explain why the following components related to the Quad Cities crib house are not included

in the AMR, or identify the component group in LRA Table 2.4-11 that includes them (for

reference, some of the items are identified in Figure 2.4-2 of the Quad Cities UFSAR):

* intake flume/canal (define all boundaries that form the basin)

* log Boom

* crib house wire mesh screens, if applicable

* crib house stop logs, if applicable

* crib house dewatering valves and trash rake refuse pit, if applicable

* discharge structure, including rolling gates

* 16-ft diameter discharge piping

* 96-in ice melting line, including gate

* 14-in circulating water pipe

* discharge flume/canal (define all boundaries that form the basin)

* weir gate in the discharge canal

Dresden: LRA Section 2.4.11 Crib House states that at Dresden, the crib house includes the

diesel generator cooling pumps and the suction piping for the containment cooling service water

system pumps. It also states that the crib house contains stop logs that can be used to isolate

the compartment and raise its water level where the containment cooling service water system

pump and the diesel fire pump take their suction. To complete the review the staff requested

the following information in RAI 2.4-7:

(a) Confirm that for Dresden the cooling lake and associated "hot" and "cold" canals, described

in Dresden Station UFSAR Section 2.4, are not part of the ultimate heat sink and do not

serve an intended function for license renewal. If they do, submit the AMR, including the

credited AMP(s).

: (b) Explain why the following components related to the Dresden crib house are not included in

the AMR, or identify the component group in LRA Table 2.4-11 that includes them (for

reference, some of the items are identified in Figure 2.4-1 of the Dresden UFSAR):

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* intake flume/canal (define all boundaries that form the basin)

* floating boom protecting intake canal

* crib house wire mesh screens

* crib house stop logs

* crib house dewatering valves and trash rake refuse pit

* discharge outfall structure, including rolling gates

* 14.0-ft diameter circulating water pipe from power plant

* 8.0-ft diameter ice melt recirculating pipe, including ice melt gate (or deicing valve)

* circulating water pipe, similar to 14-in circulating water pipe shown on Figure 2.4-2 of

the Quad Cities UFSAR, if applicable

* discharge flume/canal (define all boundaries that form the basin)

* flow-regulating station

In its response to RAI 2.4-7, the applicant stated the following:

Quad Cities

(a) The suction lines in the Quad Cities Crib House are associated with RHR service water

system. The Diesel Generator Cooling Water Pumps take suction off of the RHR service

water line (see boundary diagrams LR-ODC-M-37, location E-3 and E-8 and LR-QDC-M-79,

location F-4.) These branch connections are physically located in the Turbine Building, in the

RHR service water pump vaults. The difference between LRA Sections 2.4.11 and 2.3.3.22 is

that LRA Section 2.4.11 discusses the equipment contained in the structure and LRA Section

2.3.3.22 discusses the functions served by maintaining the UHS.

(b) The following provides the additional requested information for each of the Quad Cities

components listed above:

* Intake flume/canal (define all boundaries that form the basin)-The intake flume

boundaries include the topographic basin from the high point (at approximately 565'

elevation) on the river bottom between the crib house and the main river channel on the

west side and extending to the crib house on the east side. This basin is rock and

earthen bottom. LRA Table 2.4-11, Component Group Concrete Walls, addresses the

crib house walls.

* Log Boom-The log boom is a floating structure that functions as a barrier to floating debris during normal operations. However, it does not perform any function to retain

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water in the event of a loss of lock and dam 14 (the design basis event bringing the UHS

in scope). Therefore, the log boom does not fall within the scope of License Renewal and

does not require aging management.

* Crib House wire mesh screens (if applicable)-Ouad Cites has Wire Mesh Screens

filtering the RHR Service Water intake. These wire mesh screens do not perform a

function in maintaining the UHS and therefore are not in the scope of License Renewal

and do not require aging management.

* Crib House stop logs (if applicable)-The stop logs are installed to perform maintenance

in crib house bays (intake and discharge bays). At Quad Cities, they do not perform any

function relative to maintaining the UHS. As such, they are not in the scope of License

Renewal and do not require aging management.

* Crib house dewatering valves and trash rake refuse pit, (if applicable)-The dewatering

valves are used to drain circulating water piping and bays. Station procedures require the

unit to be in cold shut down prior to draining these areas; therefore, the UHS would not be

required. Additionally, these valves are not required to perform pressure boundary

functions for the UHS. As such, the dewatering valves are not in the scope of License

Renewal and do not require aging management. Quad Cities does not have a Trash

Rake Refuse Pit.

* Discharge structure, including rolling gates-At Quad Cities, the discharge structure

shown on UFSAR Figure 2.4-2 is attached to and managed as part of the crib house.

The crib house walls are addressed in LRA Table 2.4-11 under Component

Group-Concrete Walls. The rolling gates shown on this same figure are installed for

maintenance of the circulating water system only. They are open during normal

operations and are not required to support any UHS function. Therefore, they are not

within the scope of License Renewal and do not require aging management.

* 1 6-ft diameter discharge piping-This component falls within the scope of license renewal

and is evaluated in LRA Table 2.3.3-22 under Component Group-Piping and Fittings.

* 96" Ice Melting Line, including gate-The Ice Melting Line falls within the scope of

License Renewal and is evaluated in LRA Table 2.3.3-22 under Component

Group-Piping and Fittings. The gate is the Ice Melt Valve which also falls within the

scope of License Renewal and is evaluated in LRA Table 2.3.3-22 under Component

Group-Valves. Note that LRA Table 2.3.3-22, Component-Group Valves, should have

been revised to delete "(Dresden Only)" as shown below.

* 14" Circulating Water Pipe-The 14' Circulating Water Pipe shown on UFSAR Figure

2.4-2 is the service water return line from the RHR Service Water system and the Diesel

Generator Cooling Water system. This non-safety-related piping, located outside of the

turbine building, is not required to support any intended function and does not fall within

the scope of License Renewal. As such, it does not require aging management.

* Discharge flume/canal (define all boundaries that form the basin)-The discharge flume

falls within the scope of license renewal. Those portions within the scope of License

Renewal begin at the crib house (LRA Table 2.4-11, Component Group-.Concrete Walls)

and extend to the discharge canal weir (LRA Table 2.4-11, Component Group-Concrete

Canal Weirs).

* Weir gate in the discharge canal-The weir gate falls within the scope of License

Renewal and is evaluated in LRA Table 2.4-11 under Component Group -Concrete

Canal Weirs.

Dresden

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(a) Dresden cooling lake and the associated hot and cold canals are not credited with water

supply in the event that the normal heat sink (the river) is unavailable. Therefore, the cooling

lake and the associated hot and cold canals do not require aging management.

(b) The following provides additional requested information for each of the Dresden components

listed above:

* Intake flume/canal (define all boundaries that form the basin)-The intake canal falls

within the scope of license renewal. The intake flume starts at the Kankakee River intake

canal interface with the canal bottom high point at elevation 495'-0 and runs to the cnb

house. LRA Table 2.3.3-22 should have added 'Earthen Structures" to address the

canal, as shown below. LRA Table 2.4-11, Component Groups-Concrete Slabs and

Concrete Walls, addresses the crib house.

* Floating Boom protecting intake canal-The floating boom is a floating structure that

functions as a barrier to floating debris during normal operations. However, it does not

perform any function in retaining water in the event that the normal heat sink (the river) is

unavailable. Therefore, the log boom does not fall within the scope of License Renewal

and does not require aging management.

* Crib House wire mesh screens-In the event that the normal heat sink becomes

unavailable, the Crib House Wire Mesh Screens are removed to allow the installation of

the stop logs. These screens therefore provide no function in maintaining the UHS and

are not in the scope of License Renewal and do not require aging management.

* Crib House stop logs-The stop logs are needed to support the UHS should have been

added to LRA Tables 2.3.3-22 and 3.3-2 as shown below.

* Crib house dewatering valves and trash rake refuse pit-LRA Table 2.3.3-22, Component

Group Valves, addresses the dewatering valves. The trash rake refuse pit is part of the

crib house structure. LRA Table 2.4-11, Component Groups Concrete Slabs and

Concrete Walls, address the crib house.

* Discharge Outfall Structure, including rolling gates-Portions of the Outfall Structure fall

within the scope of the Rule and perform a structural pressure barrier function for the

UHS. The Outfall Structure should have been added to LRA Table 2.3.3-22, under

Component Group-Concrete Slabs and Concrete Walls, as shown below. The rolling

gates are available for performing maintenance on the Discharge Ouffall Structure bays,

are normally open, and are not required to perform any function associated with the UHS.

As such they are not within the scope of License Renewal and do not require aging

management.

* 14.0-ft Diameter Circulating Water Pipe from Power Plant-The circulating water pumps

are secured in the event that the normal heat sink (the river) is unavailable. Therefore

this piping is not relied upon for the UHS and does not require aging management.

* 8.0-ft Diameter Ice Melt Recirculating Pipe, including ice melt gate (or deicing

valve)-LRA Table 2.3.3-22, Component Group Piping and Fittings

* Circulating water pipe, similar to 14' circulating water pipe shown on Figure 2.4-2 of the

QC UFSAR (if applicable)-This piping is not applicable to Dresden. At Quad Cities the

Circulating Water discharges at the crib house, at Dresden it discharges at the Discharge

Structure.

* Discharge flume/canal (define all boundaries that form the basin)-The discharge canal

falls within the scope of License Renewal. The discharge flume starts at the Discharge

Outfall Structure and runs to the discharge canal interface with the Illinois River at

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Elevation 498'-O". LRA Table 2.3.3-22 should have added 'Earthen Structures" to

address the canal. 'Concrete Walls" and 'Concrete Slabs" should have also been added

to LRA Table 2.3.3-22 to address the Discharge Ouffall Structure, as shown below.

Flow-regulating station-Failure of the flow-regulating station would not affect plant safety or the

ability to accomplish safe shutdown in either configuration (open or closed cycle). Therefore, the

flow-regulating station was considered out of scope and does not require aging management.

Note: Systems do not usually contain structures. Structures usually line up with structures

between Chapter 2 and Chapter 3, but there are some exceptions. In this unusual circumstance

where the ultimate heat sink system does contain structural components, the aging management

reference provided in the system portion of Chapter 2 is to the structural portion of Chapter 3 of the

LRA, when applicable.

Table 2.3.3-22 Component Groups Requiring Aging

Heat Sink

Management Review-Ultimate

Component Component Intended Aging Management Ref No.

Function

Concrete Slabs (Dresden Structural Pressure 3.5.1.22

only) Barrier

Concrete Walls (Dresden Structural Pressure 3.5.1.22

only) Barrier

Earthen Structures Structural Pressure 3.5.1.22

(Dresden only) Barrier

Stop Logs (Dresden only) Structural Pressure 3.3.2.304

Barrier

Valves Pressure Boundary 3.3.2.278, 3.3.2.300

The information provided by the applicant in its RAI response and additional clarification

provided in a submittal, dated December 5, 2003, sufficiently answers the questions posed by

the staff. RAI 2.4-7 is, therefore, resolved.

2.4.11.3 Conclusions

The staff reviewed LRA Section 2.4.11 to determine whether any structural components of the

crib house that should be within the scope of license renewal were not identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. On the

basis of its review, the staff concludes that the applicant has adequately identified the structural

components of the crib house that are within the scope of license renewal, as required by

10 CFR 54(a), and that the applicant has adequately identified the structural components of the

crib house that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.4.12 Unit 1 Crib House (Dresden)

2.4.12.1 Summary of Technical Information in the Application

The applicant described the Dresden Unit 1 crib house in LRA Section 2.4.12 and provided a

list of components subject to an AMR in LRA Table 2.4-12.

The Unit 1 crib house at Dresden supports a diesel-driven fire pump, which is required to

support the Unit 2 and 3 fire protection system.

The diesel-driven fire pump assembly is located on a reinforced concrete floor slab and takes

its suction from the center bay of the Unit 1 crib house. The diesel engine is supported by a

reinforced concrete pedestal and anchored by cast-in-place anchor bolts. The fire pump

support consists of a steel leveling/bearing plate, on grout, with cast-in-place anchor bolts. The

anchor bolts and the steel leveling bearing plate are evaluated in the component support

commodity group.

The applicant identified the following UFSAR references for additional descriptive information

about the Dresden Unit 1 crib house:

* Dresden Station UFSAR Section(s): 9.2.2

* Quad Cities Station UFSAR Section(s): Not Applicable

The applicant defined the following intended function for the Dresden Unit 1 crib house:

* Credited in regulated events-provides physical support for components relied upon to

demonstrate compliance with the fire protection regulated events.

In LRA Table 2.4-12, the applicant listed the following component groups requiring AMR for the

Dresden Unit 1 crib house:

Component Component Intended Function LRA Aging Management Ref No.

Concrete and Grout (Dresden) Non-S/R Structural Support 3.5.1.29

Concrete Slabs (Dresden) Structural Support 3.5.1.22

Concrete Slabs (Dresden) Non-S/R Structural Support 3.5.1.22

Walls, Ceilings, Floors (Dresden) Fire Barrier __3.3.1.28__

The applicant's AMR results for the Unit 1 crib house are provided in LRA Sections 3.3 and 3.5.

2.4.12.2 Staff Evaluation

The staff reviewed LRA Section 2.4.12 and Dresden Station UFSAR Section 9.2.2 to determine

whether the Dresden Unit 1 crib house structural components within the scope of license

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' -;c . .

renewal and subject to an AMR have been identified in accordance with 10 CFR 54.4 and

54.21 (a)(1).

In the performance of the review, the staff selected system functions described in the UFSAR

that are required by 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

Based on the information provided in LRA Section 2.4.12, it was not clear to the staff that "fire

barrier" is the only intended function for the walls and ceilings of the Dresden Unit 1 crib house.

The applicant was requested in RAI 2.4-8 to submit the following information:

(a) How would collapse of the building walls and ceiling effect the availability of the dieseldriven fire pump?

(b) Are the walls and ceiling inspected as part of Maintenance Rule structures monitoring, and

is this program credited to manage aging of the walls and ceiling for license renewal?

In its response to RAI 2.4-8, the applicant stated the following:

Exelon has reviewed LRA Section 2.4.12 and provides the following clarifications:

(a) While the Unit 1 Crib House walls and ceiling have been evaluated as fire barriers, they were

not evaluated for the secondary effect they could have on the diesel-driven fire pump if they

were to collapse. Such an evaluation would be performed if the structure contained safetyrelated components. However, the Unit 1 Crib House is not a safety-related structure and

there are no safety-related components contained within the building. Since the walls and

ceiling do not perform a safety-related function and there are no safety-related components

that can be affected by the collapse of the walls or ceiling, the criteria stated in 10 CFR

54.4(a)(2) are not applicable to this situation. For these reasons, structural support is not an

intended function of the walls and ceiling. This position is supported by NUREG-1 800,

Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants.

Table 2.1-2 of NUREG-1 800 states:

An applicant need not consider hypothetical failures or second, third, or

fourth level support systems. For example, if a non-safety-related diesel

generator is only relied upon to remain functional to demonstrate compliance

with the NRC's SBO regulations, an applicant may not need to consider (1)

an altemate/backup cooling water system, (2) the diesel generator

non-seismically qualified building walls, or (3) an overhead segment of

non-seismically qualified piping (in a Seismic Il/I configuration).

The Unit 1 Crib House is not 'explicitly credited" in the Dresden current licensing basis

documents for Fire Protection. In addition, the Unit 1 diesel-driven fire pump provides a

backup supply of river water to the fire protection system. It is not the primary system credited

for maintaining fire protection system pressure.

(b) The Unit 1 Crib House structure is included within the scope of the Maintenance Rule

Structural Monitoring program. While the walls and ceiling are inspected per the Structural

Monitoring Program criteria, this activity is not credited for License Renewal for the reasons

stated in (a) above.

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The additional information provided by the applicant in its RAI response sufficiently answers the

two questions posed by the staff. The staff concludes that the applicant has appropriately

addressed the Dresden Unit 1 crib house in its scoping and screening review. Therefore RAI

2.4-8 is resolved.

2.4.12.3 Conclusions

The staff reviewed LRA Section 2.4.12 to determine whether any structural components of the

Dresden Unit 1 crib house that should be within the scope of license renewal were not identified

by the applicant. In addition, the staff performed an independent assessment to determine

whether any components that should be subject to an AMR were not identified by the applicant.

On the basis of its review, the staff concludes that the applicant has adequately identified the

structural components of the Dresden Unit 1 crib house that are within the scope of license

renewal, as required by 10 CFR 54(a), and that the applicant has adequately identified the

structural components of the Dresden Unit 1 crib house that are subject to an AMR, as required

by 10 CFR 54.21 (a)(1).

2.4.13 Station Chimney

2.4.13.1 Summary of Technical Information in the Application

The applicant described the station chimney in LRA Section 2.4.13 and provided a list of

components subject to an AMR in LRA Table 2.4-13. The station chimney provides an elevated

discharge point for treated gaseous radioactive effluents. The chimney is a 310-ft tall tapered

structure that contains and/or directs the release of fission products. The reinforced concrete

chimney is founded on bedrock. The lower section of the chimney is divided into five cells

consisting of reinforced concrete walls that provide a holdup volume for the gland exhausters.

The applicant identified the following UFSAR references for additional descriptive information

about the station chimney:

* Dresden Station UFSAR Section(s): 11.3

* Quad Cities Station UFSAR Section(s): 11.3

The applicant defined the following intended functions for the station chimney:

* Elevated release-provides for the discharge of treated gaseous waste to meet the

requirements of 10 CFR Part 100.

* Pressure control path-provides a secondary pressure control path for primary containment.

In LRA Table 2.4-13, the applicant listed the following component groups requiring AMR for the

station chimney:

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Component Component Intended Function LRA Aging Management Ref No.

Caulking/Sealants Gaseous Release Path 3.5.2.4

Concrete Slabs Structural Support 3.5.1.20

Concrete Walls Structural Support 3.5.1.20

Concrete Walls Gaseous Release Path 3.5.1.20

Foundations Structural Support 3.5.1.20, 3.5.1.21, 3.5.1.25, 3.5.1.26

Masonry Walls (Quad Cities) Structural Pressure Barrier 3.5.2.9

Masonry Walls (Quad Cities) Gaseous Release Path 3.5.2.9

Misc. Steel (Includes Platforms, Non-S/R Structural Support 3.5.1.20

Ladders, Railings) .

Steel Doors (Dresden) Gaseous Release Path 3.5.1.20

Steel Embedments Structural Support 3.5.1.20

Steel Plates Gaseous Release Path 3.5.1.20

Structural Steel Non-S/R Structural Support 3.5.1.20

The applicant's AMR results for the station chimney are provided in LRA Section 3.5.

2.4.13.2 Staff Evaluation

The staff reviewed LRA Section 2.4.13, Dresden Station UFSAR Section 11.3, and Quad Cities

Station UFSAR Section 11.3 to determine whether the station chimney structural components

within the scope of license renewal and subject to an AMR have been identified in accordance

with 10 CFR 54.4 and 54.21 (a)(1).

In the performance of the review, the staff selected system functions described in the UFSAR

that are required by 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

LRA Table 2.4-13 presents a comprehensive list of structural components for the station

chimney. The staff did not identify any omissions made by the applicant.

2.4.13.3 Conclusions

The staff reviewed LRA Section 2.4.13 to determine whether any structural components of the

station chimney that should be within the scope of license renewal were not identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. On the

basis of its review, the staff concludes that the applicant has adequately identified the structural

components of the station chimney that are within the scope of license renewal, as required by

10 CFR 54(a), and that the applicant has adequately identified the structural components of the

station chimney that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.4.14 Cranes and Hoists

2.4.14.1 Summary of Technical Information in the Application

The applicant described the cranes and hoists in LRA Section 2.4.14 and provided a list of

components subject to an AMR in LRA Table 2.4-14. Cranes and hoists provide systems for

lifting, transporting, and handling of loads. Cranes and hoists include those cranes and hoists

whose failure could affect safety-related components, except for the refueling bridge platform,

which is covered with refueling equipment. Cranes and hoists include the reactor building

crane, the turbine building cranes, smaller capacity cranes and hoists, and jib cranes that are

located in various parts of the reactor and turbine buildings. Cranes and hoists and jib cranes

are classified as Safety Class II components.

The reactor building crane services the operating floor, which is shared by both units. It is a

bridge-type crane equipped with a 125-ton main hoist and a 9-ton auxiliary hoist and can reach

major component storage areas on the operating floor. The reactor building crane is used for

lifting and transporting the spent fuel cask between the spent fuel pools and the cask

decontamination work area, and handling other equipment and reactor components accessible

from the refueling floor. The crane hoist system consists of a dual load path through the hoist

gear train, the reeving system, and the hoist load block along with restraints at critical points to

provide load retention and minimization of uncontrolled motions of the load in the event of

failure of any single hoist component. Redundancy has also been designed into the hoist,

trolley brakes, the spent fuel cask lifting devices, and crane control components.

The two turbine building overhead cranes are equipped with a 175-ton hoist, with a 25-ton

auxiliary hoist (for the south crane at Quad Cities and the west crane at Dresden), and a 125-

ton hoist with a 1 0-ton auxiliary hoist (for the north crane at Quad Cities and the east crane at

Dresden).

The applicant identified the following UFSAR references for additional descriptive information

about the cranes and hoists:

* Dresden Station UFSAR Section(s): 9.1.4

* Quad Cities Station UFSAR Section(s): 9.1.4

The applicant defined the following intended function for the cranes and hoists:

* Lifting and transporting loads-provide a safe means for handling safety-related

components and loads above or near safety-related components.

In LRA Table 2.4-14, the applicant listed the following component groups requiring AMR for the

cranes and hoists:

Component I Component Intended Function | LRA Aging Management Ref No.

Cranes | Structural Support 3.3.1.3

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Component Component Intended Function LRA Aging Management Ref No.

Cranes Non-S/R Structural Support - 3.3.1.14

Rails Non-S/R Structural Support 3.3.i.14

The applicant's AMR results for cranes and hoists are provided in LRA Section 3.3.

2.4.14.2 Staff Evaluation

The staff reviewed LRA Section 2.4.14, Dresden Station UFSAR Section 9.1.4, and Quad Cities

Station UFSAR Section 9.1.4 to determine whether the cranes and hoists structural

components within the scope of license renewal and subject to an AMR have been identified in

accordance with 10 CFR 54.4 and 54.21 (a)(1).

In the performance of the review, the staff selected system functions described in the UFSAR

that are required by 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

Based on information provided in LRA Section 2.4.14, the staff cannot identify which ULRA

Aging Management Ref Nob is applicable to each of the crane/rail systems included in the

scope of LRA 2.4.14. Also, it is unclear to the staff why cranes and hoists have been split into

two groups, covered under different sections of LRA Section 2.0, and why all references to

aging management results point to LRA Section 3.3, Auxiliary Systems.

The applicant was requested in RAI 2.4-9 to clarify the treatment of cranes and hoists in the

scoping and screening, and in the AMR. In addition, the applicant was 'requested to submit the

following information:

(a) a list of all cranes/hoists/rails and associated components in the scope of license renewal

(b) a list of all cranes/hoists/rails and associated components excluded from the license

renewal scope, and the technical bases for their exclusion

(c) a list of all cranes/hoists/rails and associated components requiring an AMR (i.e., passive,

long-lived)

(d) a list of all cranes/hoists/rails and associated components requiring aging management

and/or TLAA, and the specific AMP(s) and TLAAs credited to manage aging

In its response to RAI 2.4-9, the applicant stated the following:

With the exception of cranes and hoists associated with the refueling system, most cranes are integral

parts of structures for which they provide service. For this reason, Exelon separated overhead lifting

systems into two separate groups. Those cranes and hoists associated with the refueling system are

evaluated in LRA Section 2.3.3.1, Refueling Equipment. All other cranes and hoists were evaluated

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in LRA Section 2.4.14, Cranes and Hoists. Only overhead lifting systems associated with refuel

handling are evaluated in NUREG-1801 (Section VII.B.1-a). Components from this section of the

NUREG are evaluated foraging management underAuxiliary Systems (seeTable 3 in NUREG-1801

Volume 1). In order to maintain consistency with NUREG-1 801, Exelon decided to evaluate the aging

for all overhead lifting systems (refueling and non-refueling) in LRA Section 3.3, Aging Management

of Auxiliary System.

(a) Crane subsystems are installed throughout various buildings at Dresden and Quad Cities. A list

of crane subsystems included within the scope of License Renewal is provided below for each

site. Each crane subsystem includes rails, structural girders required for support of the crane

loads, and the crane mechanism. The crane mechanism includes drive tires/wheels, bolts, nuts,

rivets, load blocks, suspension housing, hand chain wheels, chain attachments, clevis, yokes,

suspension bolts, shafts, gears, bearings, pins, rollers, locks and clamping devices, hook

retaining nuts, hook retaining collars/pins, retaining member welds, load sprockets, drums,

sheaves, mechanical brake mechanisms, and hooks.

In addition to crane subsystems, a number of monorail tracks have been installed over various

locations throughout each site to facilitate maintenance. Portable hoists are installed on these

monorails when maintenance is required or equipment requires movement. Those instances

below for which the description does not include a crane or hoist only refer to monorails.

Dresden Reactor Building-In Scope

Unit 2 Reactor Building (613/E Elevation) Hatch Jib Crane

Unit 3 Reactor Building (613/E Elevation) Hatch Jib Crane

Reactor Building (Elevation 613/E) New Fuel Storage Vault Jib Crane

Reactor Service Platform Jib Crane

Unit 2 Reactor Building (545/E Elevation) Hatch Jib Crane

Reactor Building Overhead Crane

Dresden Turbine Building-In Scope

Unit 3 Diesel Generator Room Monorails (2)

Diesel Generator Room Monorail Crane

Unit 2 Turbine Building Overhead Crane

Unit 2 Diesel Generator Room Monorails (2)

Unit 3 Turbine Building Overhead Crane

Dresden Primary Containment-In Scope

Unit 2 Drywell Equipment Hatch Monorails

Unit 2 Drywell CRD Pit Jib Monorails

Unit 2 Drywell Ground Floor Continuous Monorails

Unit 2 Drywell 2nd Floor Jib Monorails

Unit 3 Drywell Equipment Hatch Monorails

Unit 3 Drywell CRD Pit Jib Monorails

Unit 3 Drywell Ground Floor Continuous Monorails

Unit 3 Drywell 2nd Floor Jibs Monorails

Dresden Miscellaneous Buildings-In Scope

2/3 Diesel Generator Room Monorails (3)

Unit 2 HPCI Room Trolley Chain Hoist

Unit 3 HPCI Room Trolley Chain Hoist

2/3 Cribhouse Service Water Pump Electric Hoist (a single monorail that is used to move and

position the stop logs for set up of the ultimate heat sink)

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Circwater pump monorails and trolleys (4) (these non-safety-related monorails pass overthe

safety-related Unit 2 and Unit 3 diesel generator cooling water pumps)

Quad Cities Reactor Building-In Scope

Unit 1 CRD Repair Floor Jib

Unit 2 CRD Repair Floor Jib

New Fuel Inspection Stand Jib

Unit 1 and 2 Reactor Service Platform Jib

Unit 1 and 2 Reactor Building Overhead Crane

Unit 1 Reactor Building (Elevation 666/E) Jib crane (does not exist on Unit 2)

Quad Cities Turbine Building-In Scope

Unit 1 Turbine Building Overhead Crane

Unit 2 Turbine Building Overhead Crane

Unit 1 Emergency Diesel Generator Room Monorails

Unit 2 Emergency Diesel Generator Room Monorails

Unit 1 HPCI Monorail Hoist

Unit 2 HPCI Monorail Hoist

RHR Service Water Pump Monorails (8)

Quad Cities Primary Containment-In Scope

Unit 1 Drywell First Level Monorail

Unit 2 Drywell First Level Monorail

Unit 1 Drywell 2nd Floor Jibs for SRV work

Unit 2 Drywell 2nd Floor Jibs for SRV work

Quad Cities Miscellaneous Buildings-In Scope

Unit Y2 (Common) Emergency Diesel Generator Room Monorails

(b) The following list contains all cranes, hoists,'and rails at each site that have been excluded from

the scope of License Renewal. The list only applies to cranes, hoists and rails that are located

within structures that have been included within the scope of License Renewal. Cranes, hoists,

and monorails physically located in structures that are not within the scope of License Renewal

are not listed below. Out-of-scope structures do not include safety-related equipment. As such,

any crane, hoist or monorail located within the structure could not affect safety-related equipment.

For this reason they were excluded from the scope of License Renewal along with the associated

structure. The cranes, hoists, or monorails listed below are not safety-related, are not required

for any safety-related system to perform any intended function, and are not capable of moving

any load over or spatially interact with safety-related equipment. For these reasons, they were

excluded from the scope of License Renewal.

Dresden Reactor Building-Out of Scope

Unit 2 Reactor Building (517;E Elevation) Material Interlock Underhung Jib Crane

Unit 3 Reactor Building (517E Elevation) Material Interlock Underhung Jib Crane

Unit 2 Reactor Building (589WE Elevation-RWCU Filter Demon. blocks) Monorails (1)

Unit 3 Reactor Building (589AE Elevation-RWCU Filter Demon. blocks) Monorails (1)

Unit 2 Reactor Building (545AE Elevation - north of RBCCW HX) Monorails (1)

Unit 3 Reactor Building (570 Elevation - north of main hatch) Monorails (1)

Unit 3 Reactor Building (517iE Elevation - East & West) Monorails (2)

Dresden Turbine Building-Out of Scope

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Control Rod Drive Overhaul Shop Crane Underhung

Control Rod Drive Overhaul Shop Jib Crane

Unit 2 Turbine Building Trackway (Elevation 538/E) Elevator Air Hoist Crane

Monorail

Unit 3 Turbine Building Trackway (Elevation 538/E) Elevator Air Hoist Crane

Monorail

Control Rod Drive Flush Tank Jib Crane

Unit 3 Safety Valve Test Boiler Jib Crane

Unit 3 Safety Valve Test Boiler Crane Monorail

Unit 2 Turbine Building Trackway Rollup Door Hoist Mechanism

Unit 3 Turbine Building Trackway Rollup Door Hoist Mechanism

All condensate / booster pump monorails (16)

All control rod drive hydraulic pump monorails (4)

Reactor Recirculation Motor Generator Set Monorails (4)

All stator cooling water heat exchanger monorails (2)

Reactor feedwater pump monorails (2)

Instrument air compressor monorails (3)

Feedwater regulating valve station monorails (5)

Turbine Building floor / equipment drain sump pump monorails & jib

Turbine Building freight elevator monorail (549as elevation)

Main Condenser pullpit monorail (1)

Low pressure heater monorails (12)

Low pressure heater bay area monorails (4)

South Turbine Building 2/3 MG Sets Rollomatic Filters Underhung Crane

Dresden Miscellaneous Buildings-Out of Scope

2/3 Cribhouse Refuse Basket Underhung Crane

Station Blackout Building monorails (4)

Service water pump monorails and trolleys (5)

Service water strainer monorail and trolley (1)

2/3 Cribhouse East/West Monorail Electric Hoist/Trolley

Quad Cities Reactor Building-Out of Scope

Unit 1 Reactor Building (Elevation 666&E) Monorail Hoist

Unit 2 Reactor Building (Elevation 666/E) Monorail Hoist

CRD Repair Area Monorail Hoist

CRD Repair Room Monorail

Quad Cities Turbine Building-Out of Scope

Unit 1 Condensate Pit Jib

Unit 2 Condensate Pit Jib

Unit 1 Condensate Demineralizer Monorail

Unit 2 Condensate Demineralizer Monorail

Unit 1 Turbine Building Trackway Crane

Unit 2 Turbine Building Trackway Crane

Radwaste Truck Bay Crane

Max Recycle Crane

Radwaste Basement Jib

Radwaste Shield Door Hoists (#94-#96)

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aCt Warehouse Overhead Cranes (East & West)

Unit 1 CRD pump Monorail

Unit 2 CRD pump Monorail

Reactor Recirc MG Set Monorails (4)

Instrument Air Compressor Monorails (2)

Unit 1 Battery Room Area Monorail

Unit 2 Battery Room Area Monorail

Unit 2 Reactor Feed Pump Vent Fan area Monorail (does not exist on Unit 1)

Generator Lifting Beam (on Turbine Deck)

10 Ton Lifting Beam with Hoist (on Turbine Deck)

Trolley Monorail (on Turbine Deck)

Unit 1 Off Gas Filter Room Area Monorail

Unit 2 Off Gas Filter Room Area Monorail

Unit 1 TBCCW Heat Exchanger Area Trolley with Underhung Hoist

Unit 1 Outside the West end of the Heater Bay Ground Floor Monorail (2)

Unit 2 TBCCW Heat Exchanger Area Monorail Trolley with Underhung Hoist

Unit 1 (Elevation 595/E) Outside the West end of the Heater Bay Ground Floor

Monorail (2)

Unit 2 (Elevation 595/E) Outside the West end of the Heater Bay Ground Floor

Monorail (2)

Unit 1 (Elevation 61 1IE) Outside the West end of the Heater Bay Second Floor

Monorail (7)

Unit 2 (Elevation 61 1E) Outside the West end of the Heater Bay Second Floor

Monorail (7)

Unit 1 Reactor Feed Pump Exhaust Fan Area Monorail (does not exist on Unit 2)

Unit 1 (Elevation 668WE) Floor Elevation Monorail

Unit 2 (Elevation 648WE) Floor Elevation Monorail

Quad Cities Miscellaneous Buildings-Out of Scope

Unit 1 Station Blackout Diesel Room Monorail

Unit 2 Station Blackout Diesel Room Monorail

Crib House Monorail for circulating water pumps

Fish Basket Jib

Trash Rake Crane

(c) All cranes, hoists, and monorails within the scope of License Renewal require aging management

review are listed in the response to (a) above. -While the type of components comprising crane

subsystems can vary, the following cranes component types require aging management:

a. Load carrying flanges

b. Support structures

c. Bolts, nuts, or rivets

d. Load blocks

e. Suspension housings

f. Hand chain wheels

9. Chain attachments

h. Clevis

I. Yokes

j. *Suspension Bolts

k. Shafts

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1. Gears

m. Bearings

n. Pins

o. Rollers

p. Lock and Clamping Devices

q. Hook Retaining Nuts

r. Hook Retaining Collars/Pins

s. Retaining Member Welds

t. Load Sprockets

u. Drums

v. Sheaves

w. Hydraulic Subsystems

x. Cable

y. Cable Clamps

z. Brakes

aa. Bridge/Beam Structures

(d) All cranes, hoists, and monorails within the scope of License Renewal (listed in the response to

(a) above) require aging management review. Aging for these cranes, hoists, and monorails will

be managed under Aging Management Program B.1.15, Overhead Heavy Load and Light Load

Handling Systems. The reactor building overhead cranes at Dresden and Quad Cities were

designed to meet or exceed the design fatigue loading requirements of the Crane Manufacturers

Association of America (CMAA) Specification 70. Class Al. The evaluation of expected cycles

over the life of each plant is the basis of a safety determination and is therefore a TLAA. Section

4.7.1, Reactor Building Crane Load Cycles, provides the disposition for this TLAA.

The additional information provided by the applicant in its RAI response is comprehensive and

sufficiently answers all four questions posed by the staff. The staff concludes that the applicant

has appropriately addressed cranes and hoists in its scoping and screening review. Therefore

RAI 2.4-9 is resolved.

2.4.14.3 Conclusions

The staff reviewed LRA Section 2.4.14 to determine whether any structural components of the

cranes and hoists that should be within the scope of license renewal were not identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. On the

basis of its review, the staff concludes that the applicant has adequately identified the structural

components of the cranes and hoists that are within the scope of license renewal, as required

by 10 CFR 54(a), and that the applicant has adequately identified the structural components of

the cranes and hoists that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.15 Component Supports Commodity Group

2.4.15.1 Summary of Technical Information in the Application

The applicant described the component supports commodity group in LRA Section 2.4.15 and

provided a list of components subject to an AMR in LRA Table 2.4-15.

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The component support commodity group consists of support members (includes support

members, welds, bolted connections, and support anchorage to building structures), high

strength bolting for Class I supports, and miscellaneous supports (includes constant and

variable load springs, guides, stops, sliding surfaces, design clearances, vibration isolators, and

clevis pins).

The applicant stated that grout (which includes reinforced concrete, grout, and masonry) is

evaluated as a component group within structures.

The component supports commodity group includes the following:

* supports for ASME Class I, 2, and 3 piping and components

* supports for ASME Class MC components, including suppression chamber seismic

restraints, suppression chamber support saddles and columns, and vent system supports

* supports for cable trays, conduit, HVAC ducts, tube track, instrument tubing and non-ASME

piping and components

* anchorage of racks, panels, cabinets, and enclosures for electrical equipment and

instrumentation

* supports for emergency diesel generator, HVAC system components, and miscellaneous

mechanical equipment

* supports for platforms, pipe whip restraints, jet impingement shields, masonry walls, and

miscellaneous structures

In LRA Table 2.4-15, the applicant listed the following component groups requiring AMR for the

component supports commodity group:

Component Component Intended Function LRA Aging Management Ref No.

Anchorage to Buildings, Including Structural Support 3.5.1.29, 3.5.1.30

Bolted/Welded Connections

Anchorage to Buildings, Including Non-S/R Structural Support 3.5.1.29

Bolted/Welded Connections

Bolting Structural Support 3.5.1.32

Clevis Pins: Suppression Chamber Structural Support 3.5.2.5

Columns, Vent

Instrument Racks, Frames, Panels, Structural Support 3.5.1.29

etc.

Instrument Racks, Frames, Panels, Non-S/R Structural Support 3.5.1.29

etc.

Raceways Structural Support 3.5.1.29

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Component Component Intended Function LRA Aging Management Ref No.

Sliding Surfaces Structural Support 3.5.1.31

Support Members (includes Spring Structural Support 3.2.2.79, 3.2.2.80, 3.2.2.81, 3.5.1.29,

Hangers) 3.5.1.31, 3.5.2.14

Support Members Non-S/R Structural Support 3.5.1.29

Vibration Isolation Elements (Quad Structural Support 3.5.1.29

Cities) .

The applicant's AMR results for component supports are provided in LRA Sections 3.2 and 3.5.

2.4.15.2 Staff Evaluation

The staff reviewed LRA Section 2.4.15 to determine whether the component supports

commodity group structural components within the scope of license renewal and subject to an

AMR have been identified in accordance with 10 CFR 54.4 and 54.21 (a)(1).

In the performance of the review, the staff selected system functions that are required by 10

CFR 54.4 to verify that components having intended functions were not omitted from the scope

of the Rule. The staff also focused on components that were not identified as being subject to

an AMR, to determine if any components were omitted.

Based on information provided in LRA Section 2.4.15, it is not clear to the staff that all

component supports within the scope of license renewal are included in the component

supports commodity group. Also, clarification is needed for several "Components" listed in

Table 2.4-15.

In order to complete the screening review for component supports, the staff requested in RAI

2.4-10 the applicant to submit the following information:

(a) Clarify if the ASME Class 1 supports in this commodity group include the reactor vessel

support skirt/support ring and reactor vessel upper lateral stabilizer support. If not, where

are these supports addressed in the LRA? If not managed by ASME Section Xl,

Subsection IWF, submit the technical basis for crediting an alternate AMP.

(b) Clarify if the ASME Class MC supports in this commodity group include the drywell lower

ring support and the drywell upper lateral support. If not managed by ASME Section Xl,

Subsection IWF, submit the AMR for the drywell supports, including the technical basis for

this exception.

(c) Since LRA Section 2.4.15 is not referenced anywhere in LRA Sections 2.3 or 2.4, verify that

all supports associated with "Components" listed in LRA Sections 2.3 and 2.4.1 through

2.4.14 are included in the component supports commodity group. If not, identify the

supports not included and submit the AMR, including credited AMPs.

(d) Verify that the uAnchorage to Buildings Including Bolted/Welded Connections" component in

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LRA Table 2.4-15 includes anchors directly into concrete.

In its response to RAI 2.4-10, the applicant stated the following:

(a) The ASME Class 1 supports discussed in Section 2.4-15 of the LRA do not include the reactor

vessel support skirt. The reactor vessel support skirt was evaluated in LRA Section 2.3.1.1,

Reactor Vessel. The reactor vessel support skirt was included in LRA Table 2.3.1-1 under the

Component Group "Support Skirts and Attachment Welds." This is in alignment with NUREG1801, which assigns 'Support Skirt and Attachment Welds' to Section IV.A1, "Reactor Vessel

(Boiling Water Reactor).' The aging management of the support skirts and attachment welds has

been analyzed as a TLAA and is discussed in LRA Section 4.3.1, Reactor Vessel Fatigue

Analysis. Specifically, the reactor vessel support skirt will be managed for fatigue under aging

management program, B.1.34, Metal Fatigue of the Reactor Coolant Pressure Boundary.

The reactor vessel support ring girderand upper lateral stabilizer supports were analyzed in LRA

Section 2.4.15, 'Component Supports Commodity Group" as part of the 'Support Members

(Includes Spring Hangers)" Component Group. The upper lateral stabilizersupports are managed

by Aging Management Program B.1.27, "ASME Section Xl, Subsection IWF.' The reactor vessel

support ring girder is not an ASME Section Xl, Subsection IWF component. The reactor vessel

support ring girder is managed under Aging Management Program B.1.30, Structures Monitoring

Program.

(b) The drywell lower ring support and the drywell upper lateral support are included in the ASME

Class MC supports discussed in LRA Section 2.4.15, Component Supports Commodity Group.

The drywell lower ring support and the drywell upper lateral support will be managed under Aging

Management Program B.1.27, ASME Section Xl, Subsection IWF.

(c) LRA Section 2.4.15, 'Component Supports Commodity Group," includes all supports associated

with the "Components' listed in LRA Sections 2.3 and 2.4.1 through 2.4.14, with two exceptions:

Table 2.3.1-1 of LRA Section 2.3.1.1, "Reactor Vessel,' includes supports for the reactor vessel

and reactor vessel internals. The aging management of the support skirts and attachment welds

has been analyzed as a TLAA and is discussed in LRA Section 4.3.1, Reactor Vessel Fatigue

Analysis. Specifically, the reactor vessel support skirt will be managed for fatigue under aging

management program, B.1.34, Metal Fatigue of the Reactor Coolant Pressure Boundary.

Table 2.3.1-2 of LRA Section 2.3.1.2, "Intemals,' includes components internal to the reactor

vessel that provide support for other internal components. Aging Management Programs B.1.2,

Water Chemistry, and B.1.9, BWR Vessel Intemals, manage the aging of these internal

components. Jet pump assemblies and orificed fuel support pieces are managed under Aging

Management Program B.1.10, Thermal Aging and Neutron Irradiation Embrittlement of Cast

Austenitic Stainless Steel (CASS). In addition to these Aging Management Programs, several

Component Groups found in LRA Table 2.3.1-2 with a structural support function have'been

analyzed as a TLAA and are discussed in LRA Section 4.2, Neutron Embrittlement of the Reactor

Vessel and Intemals.

For all other component supports included in LRA Section 2.4.15 (other than the two exceptions

discussed), the following Aging Management Programs apply:

B.1.27, "ASME Section Xl, Subsection IWF' will manage ASME Class 1, 2, and 3 component

supports.

B.1.27, "ASME Section Xl, Subsection IWF` will manage ASME Class MC component supports

during the period of extended operation, as stated in (b) above.

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B.1.2, 'Water Chemistry" and AMP B.1.23, One-Time Inspection" will manage component

supports exposed to a torus water environment.

B. 1.30, Structures Monitoring Program" will manage component supports other than in the above

categories.

(d) The Component Group, Anchorage to Buildings Including Bolted/Welded Connections, found in

LRA Table 2.4-15 includes anchors directly into concrete. The concrete surrounding the anchors

is addressed with the corresponding structures as identified in LRA Section 2.4.

The additional information provided by the applicant in its RAI response sufficiently clarifies the

scoping and screening for component supports, and clearly identifies the credited AMPs for

each subset of component supports. The staff concludes that the applicant has appropriately

addressed these components in its scoping and screening review. The staff evaluation of the

AMR and AMPs for component supports is in Section 3.5 of this SER. Therefore RAI 2.4-10 is

resolved.

2.4.15.3 Conclusions

The staff reviewed LRA Section 2.4.15 to determine whether any structural components of the

component supports commodity group that should be within the scope of license renewal were

not identified by the applicant. In addition, the staff performed an independent assessment to

determine whether any components that should be subject to an AMR were not identified by the

applicant. On the basis of its review, the staff concludes that the applicant has adequately

identified the structural components of the component supports commodity group that are

within the scope of license renewal, as required by 10 CFR 54(a), and that the applicant has

adequately identified the structural components of the component supports commodity group

that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.16 Insulation Commodity Group

2.4.16. 1 Summary of Technical Information in the Application

The applicant described the insulation commodity group in LRA Section 2.4.16 and provided a

list of components subject to an AMR in LRA Table 2.4-16.

The insulation commodity group consists of the following categories of insulation:

* mirror insulation inside containment

* insulation and jacketing inside containment

* insulation and jacketing outside containment

* asbestos insulation outside containment

* anti-sweat insulation outside containment

* outdoor insulation and jacketing

Plant areas where systems and equipment in the scope of license renewal require temperature

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control include-inside the drywell, the ECCS pump rooms, the outboard MSIV rooms, and on

outdoor heat-traced piping for freeze protection. Plant areas where insulation jacketing is

subjected to periodic wetting is limited to outdoor heat-traced piping.

Insulation materials in use at the stations include both originally installed materials and

replacement materials. These include metallic reflective insulation, asbestos, fiberglass batts,

calcium silicate, quilted fiberglass blankets, preformed fiberglass, and closed cell foam.

Outdoor insulation installed over electric heat tracing consists of either calcium silicate or

preformed fiberglass with aluminum jacketing.

Insulation requiring aging management consists of asbestos and fiberglass batt insulation

located in the drywell, ECCS pump rooms, outboard MSIV rooms, and outdoor insulation and

jacketing installed over heat-traced piping.

In LRA Table 2.4-16, the applicant listed the following component groups requiring AMR for the

insulation commodity group:

Component Component Intended Function LRA Aging Management Ref No.

Insulation Insulating Characteristics 3.2.2.44, 3.2.2.45, 3.2.2.46, 3.2.2.47,

._ _3.3.2.122, 3.4.2.22

Insulation Jacketing Insulation Jacket Integrity 3.2.2.48, 3.3.2.123. 3.4.2.23

The applicant's AMR results for insulation are provided in LRA Sections 3.2, 3.3, and 3.4.

2.4.16.2 Staff Evaluation

The staff reviewed LRA Section 2.4.16 to determine whether the insulation commodity group

components within the scope of license renewal and subject to an AMR have been identified in

accordance with 10 CFR 54.4 and 54.21 (a)(1).

In the performance of the review, the staff selected system functions that are required by 10

CFR 54.4 to verify that components having intended functions were not omitted from the scope

of the Rule. The staff also focused on components that were not identified as being subject to

an AMR to determine if any components were omitted.

Based on information provided in LRA Section 2.4-16, the staff cannot identify the insulation

and insulation jacketing included in the license renewal scope nor the specific subset that is

included in this commodity group. It is also unclear whether insulation and jacketing on the

reactor coolant system have been included.

In LRA Table 2.4-16, the aging management references are to LRA Sections 3.2 (Engineered

Safety Features), 3.3 (Auxiliary Systems), and 3.4 (Steam and Power Conversion Systems).

However, in LRA Section 2.3 (Scoping and Screening Results: Mechanical), insulation is not

discussed and there are no references to LRA Section 2.4.16.

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In order to complete the screening review for insulation and insulation jacketing, the staff

requested the applicant in RAI 2.4-11 to submit the following information:

(a) Specifically identify the mechanical systems or portions of systems that have insulation

and/or insulation jacketing within the license renewal scope, and their location in the plant.

(b) Specifically identify the structures and structural components that have insulation and/or

insulation jacketing within the license renewal scope, and their location in the plant.

(c) Specifically identify any insulation and/or insulation jacketing within the license renewal

scope, but not included in the insulation commodity group; submit the AMR for this

insulation and/or insulation jacketing.

(d) List all insulation and insulation jacketing materials included in the insulation commodity

group and the results of the AMR for each.

(e) For insulation and insulation jacketing materials not requiring aging management, submit

the technical basis for this conclusion, including plant-specific operating experience.

(f) For insulation and insulation jacketing materials requiring aging management, identify the

AMP(s) credited to manage aging.

In its response to RAI 2.4-11, the applicant stated the following:

(a) The methodology used forscoping and screening of mechanical system insulation is described in LRA

Section 2.1.6, Additional Considerations Incorporated into the Methodology, Treatment of Piping and

Equipment Insulation During Scoping and Screening.

Scoping and screening identified the following systems to have insulation and/or insulation jacketing

within the license renewal scope.

System Location System Location

Reactor Inside Feedwater Inside and

vessel Containment system Outside

Containment

Reactor Inside Main Outside

recirculation Containment Condenser Containment

system

Reactor Inside and HVAC - Outside

core Outside radwaste Containment

isolation Containment buidling

cooling

system

(Quad Cities

only)

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System Location System Location

Head spray Inside Condensate Outside

system Containment and Containment

(Dresden condensate

only) booster

system

Reactor Inside Feedwater Outside

vessel head Containment heater drains Containment

vent system and valves

Nuclear Inside Reactor Inside and

boiler Containment building Outside

instrumentat closed cooling Containment

ion system water

(Quad Cities

only)

Shutdown Inside and Service water Outside

cooling Outside system Containment

system Containment

(Dresden

only) 

l

Standby Outside Diesel Outside

liquid Containment generator Containment

control service water

system system

Reactor Inside and HVAC-main Outside

water Outside control room Containment

cleanup Containment

system

Isolation Inside and SBO building Outside

condenser Outside HVAC Containment

(Dresden Containment

only)

Core spray 

- Inside Plant heating Outside

system Containment steam Containment

Low Inside and HVAC-auxili Outside

pressure Outside ary electric Containment

coolant Containment room and

injection computer

system room

(Dresden

only)

Residual Inside and HVAC-high Outside

heat Outside radiation Containment

removal Containment sampling

system system

(Quad Cities

only)

Containmen Outside Emergency Outside

t cooling Containment diesel Containment

service generators

water and auxiliaries

system

(Dresden

only)

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System Location System Location

Residual Outside SBO diesel Outside

heat Containment generator and Containment

removal auxiliaries

service

water

system

(Quad Cities

only)

High- Inside and Drywell Outside

pressure Outside nitrogen Containment

coolant Containment inerting

injection

system

Main steam Inside and Nitrogen Outside

system Outside containment Containment

Containment atmosphere

dilution

system

Extraction Outside

steam Containment

system

(b) Scoping and screening identified the following buildings or structures as having insulation (fire

wrapping/fire proofing) within the scope of license renewal:

* Reactor Buildings (Section 2.4.2)

* Main Control Room and Auxiliary Electric Equipment Room (Section 2.4.3)

* Turbine Buildings (Section 2.4.4)

* Diesel Generator Buildings (Section 2.4.5)

* Station Blackout Buildings (Section 2.4.6)

(c) For mechanical systems, all insulation and insulation jacketing within the license renewal scope are

included in the Insulation Component Group (Section 2.4.16). For buildings and structures, the fire

wrapping or fire proofing are included as line items in the LRA Section 2.4 component tables for the

buildings listed above. The Aging Management Reference in the Section 2.4 component tables points

to the aging management review results.

(d) The requested information for mechanical systems is contained in the LRA at the following points:

Section 3.2, Table 3.2-2, Aging Management References 3.2.2.44, 3.2.2.45, 3.2.2.46, 3.2.2.47

and 3.2.2.48

Section 3.3, Table 3.3-2, Aging Management References 3.3.2.122 and 3.3.2.123

Section 3.4, Table 3.4-2, Aging Management References 3.4.2.22 and 3.4.2.23

The requested information for structures is contained in LRA Section 3.3, Table 3.3-2, Aging

Management References 3.3.2.62 and 3.3.2.63.

(e) The line items listed in response to Item (d) include identification of insulation and/or insulation

jacketing materials that do not exhibit aging effects and that do not require aging management. This

information is included in the columns headed 'Aging Effect/Mechanism" and 'Aging Management

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Programt associated with each line item identified. The "Discussiont column for each line item where

there are no aging effects provides a technical basis for this conclusion.

The aging management review that evaluated insulation and insulation jacketing included a search

of problem identification forms and work orders to identify documented insulation failures at Dresden

or Quad Cities. This search identified a total of fifteen (15) documented insulation failures. Of these

fifteen failures, three failures were attributed to age-related degradation, seven failures were attributed

to causes unrelated to aging (e.g., damage by personnel), and five were attributed to indeterminate

causes.

(f) The requested information for mechanical systems is contained in the LRA at the following points:

* Section 3.2, Table 3.2-2, Aging Management References 3.2.2.44, 3.2.2.45, 3.2.2.46, 3.2.2.47

and 3.2.2.48

* Section 3.3, Table 3.3-2, Aging Management References 3.3.2.122 and 3.3.2.123

* Section 3.4, Table 3.4-2, Aging Management References 3.4.2.22 and 3.4.2.23

The requested information for structures is contained in the LRA at the following points:

* Section 3.3, Table 3.3-2, Aging Management References 3.3.2.62 and 3.3.2.63

The additional information provided by the applicant in its RAI response sufficiently clarifies the

scoping and screening for the insulation commodity group, and clearly identifies the aging

management reference for each subset of insulation and insulation jacketing. The staff

concludes that the applicant has appropriately addressed the insulation commodity group in its

scoping and screening review. The staff evaluation of the AMRs for each subset of insulation

and insulation jacketing is in Section 3.5 of this SER. RAI 2.4-11 is, therefore, resolved.

2.4.16.3 Conclusions

The staff reviewed LRA Section 2.4.16 to determine whether any components of the insulation

commodity group that should be within the scope of license renewal were not identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components that should be subject to an AMR were not identified by the applicant. On the

basis of its review, the staff concludes that the applicant has adequately identified the

components of the insulation commodity group that are within the scope of license renewal, as

required by 10 CFR 54(a), and that the applicant has adequately identified the components of

the insulation commodity group that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.5 Scoping and Screening Results: Electrical and Instrumentation and Controls

This section addresses the scoping and screening results of electrical and instrumentation and

control (I&C) systems at Dresden and Quad Cities for license renewal. Per 10 CFR 54.21

(a)(1) an applicant is required to identify and list structures and components subject to an AMR.

These are passive, long-lived structures and components that are within the scope of license

renewal. To verify that the applicant has properly implemented its methodology, the staff

focuses its review on the implementation results. Such a focus allows the staff to confirm that

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there is no omission of electrical system components that are subject to an AMR. If the review

identifies no omission, the staff has the basis to find that there is reasonable assurance that the

applicant has identified the electrical system components that are subject to an AMR.

The applicant utilized the guidance provided in NEI 95-10, Appendix B, to define passive, longlived electrical commodities. As described in LRA Section 2.1.2, the passive and long-lived

electrical and instrumentation and control component groups were evaluated using plant

"spaces" approach to identify aging effects, and then, "bounding environmental conditions"

were used to evaluate the identified aging effects with respect to component function.

The following electrical commodity groups were determined to require AMR:

* Cables and connections (splices, connectors, fuse blocks, and terminal blocks)

* Bus Duct

* High-voltage transmission conductors and insulators

* Electrical penetration

2.5.1 Insulated Cables and Connections

LRA Section 2.5.1.1, "Cables And Connections," identifies cables and connections as long-lived

and non-EQ component groups that perform an electrical passive function in support of its

system intended function as defined by 10 CFR 54.21 (a)(1)(i).

2.5.1.1 Summary of Technical Information in the Application

The applicant describes the insulated cable and connections in LRA Section 2.5.1.1 and

provides a list of components subject to an AMR in LRA Table 2.5-1.

The applicant stated that all electrical insulated cables and connections were evaluated, using

the "spaces approach, for aging management based on the comparison of material property

capability with environmental conditions. As appropriate, electrical cables and connections

were excluded from aging management if they were identified as feeding an electrical

component that performed no license renewal intended function.

The function of insulated cables and connections is to electrically connect specified sections of

an electrical circuit to deliver voltage, current or signals. Electrical cables and their

connections are reviewed as commodity groups. The types of connections included in this

review are splices, connectors, fuse blocks, and terminal blocks.

2.5.1.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1.1 to determine whether the insulated cable and

connections within the scope of license renewal and are subject to an AMR have been identified

in accordance with 10 CFR 54.4 and 54.21 (a)(1).

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As part of the review, the staff selected system functions described in UFSAR that were set

forth in 10 CFR 54.4 to verify that components having intended functions were not omitted from

the scope of the Rule.. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

The applicant evaluated the cables and connectors as a single component commodity group.

Insulated cables and connections that perform an intended function within the scope of license

renewal, but are not included in the EQ Program, meet the criterion of 10 CFR 54.21 (a)(1)(ii)

and are subject to AMR. The staff also focused on components that were not identified as

being subject to an AMR to determine if any components were omitted.

The applicant stated that "as appropriate, electrical cables and connections were excluded from

aging management if they were identified as feeding an electrical component that performed no

license renewal intended function." The staff requested the applicant to clarify whether

Dresden and Quad Cities AMR for cables have included those cables that do not perform.

license renewal intended function, but share same cable trays/raceways with cables that do

perform license renewal intended function (RAI 2.5-2(a)).

In its response dated November 20, 2003, the applicant stated that cables that perform no

license renewal intended function and share the same cable trays/raceways with cables that do

perform license renewal function are included in the scope of license renewal. Because these

cables share the same trays/raceways, the applicant included all of the cables within the scope

of license renewal. The only cables that were excluded from the scope of license renewal are

the medium voltage cables to the Quad Cities circulating pump motors and the cables within the

Radwaste Building. The circulating pump motor cables are routed in dedicated raceways that

do not contain cables performing license renewal functions. The Radwaste Building does not

contain any electrical components within the scope of license renewal. As such, all of the

cables contained in the trays/raceways found in the Radwaste Building are excluded from the

scope of license renewal and do not require aging management.

The staff agrees that the applicant has correctly identified the cables and connections as

component commodity group that perform their function without moving parts or a change in

configuration or properties (passive and long lived), and, are therefore subject to an AMR.

2.5.1.3 Conclusions

The staff reviewed the LRA to determine whether any structures, systems, or components that

should be within the scope of license renewal were not identified by the applicant. The staff did

not identify any omissions. On the basis of this review, the staff concludes that the applicant

has appropriately identified the insulated cables and connections that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant has appropriately

identified the components of the insulated cable and connections that are subject to an aging

management review, as required by 10 CFR 54.21 (a)(1).

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2.5.2 Bus Duct

LRA Section 2.5.1.2, "Bus Duct," identifies bus ducts as passive long-lived component

commodity groups that connect power supplies and switchgear in order to deliver voltage and

current to support the system's intended function as defined in 10 CFR 54.21 (a)(1)(i).

2.5.2.1 Summary of Technical Information in the Application

The applicant describes the bus ducts in LRA Section 2.5.1.2 and provides a list of components

subject to an AMR in LRA Table 3.6-2.

The bus ducts within the scope of license renewal include those bus ducts used for safetyrelated systems and those associated with the 4160 V power feeds between the reserve

auxiliary transformers (RATs) and switchgear. The bus ducts utilize pre-assembled raceway

(enclosure) design with conductors supported by electrical insulators. The function of bus ducts

is to electrically connect power supplies and load centers to deliver voltage and current. The

function of bus duct insulators is to support and insulate the bus bar conductors.

2.5.2.2 Staff Evaluation

The staff revi6wed LRA Section 2.5.1.2 to determine whether the bus ducts within the scope of

license renewal and that are subject to an AMR have been identified in accordance with

10 CFR 54.4 and 54.21 (a)(1). The bus ducts identified by the applicant as requiring AMR are

used for safety-related systems and those associated with the 4160V power feeds between the

reserve auxiliary transformers and switchgear. The staff reviewed these component categories

against the requirements of 10 CFR 54.4 (a)(1) and 10 CFR 54.4(a)(3) and found these

categories are included in these requirements.

As part of this review, the staff selected system functions described in the UFSAR that were set

forth in 10 CFR 54.4 to verify that components having intended functions were not omitted from

the scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

2.5.2.3 Conclusions

The staff reviewed the LRA to determine whether any structures, systems, or components that

should be within the scope of license renewal were not identified by the applicant. No

omissions were found. In addition, the staff performed an independent assessment to

determine whether any components that should be subject to an AMR were not identified by the

applicant. The staff did not identify any omissions. On the basis of this review, the staff

concludes that the applicant has appropriately identified the bus duct components that are

within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has

appropriately identified the bus ducts components that are subject to an aging management

review, as required by 10 CFR 54.21 (a)(1).

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2.5.3 High Voltage Transmission Conductors and Insulators

LRA Section 2.5.1.3, "High Voltage Transmission Conductors and Insulators," identifies high

voltage transmission conductors and insulators as passive long-lived component commodity

groups that connect switchyard bus and reserve auxiliary transformers in order to supply offsite

power to the plant systems and perform its intended function as defined in 10 CFR 54.21

(a)(1)(i).

2.5.3.1 Summary of Technical Information in the Application

The applicant describes the high voltage transmission conductors and insulators in LRA Section

2.5.1.3. The high voltage transmission conductors and insulators within the scope of license

renewal rule are those associated with the power feeds from the switchyard to RATs. The

function of the high voltage transmission conductors is to supply power to the plant systems

through the RATs. The function of high voltage insulators is to support and insulate the high

voltage transmission conductors.

2.5.3.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1.3 to determine whether the high voltage transmission

conductors and insulators within the scope of license renewal and that are subject to an AMR

have been identified in accordance with 10 CFR 54.4 and 54.21 (a)(1). The high voltage

transmission'conductors and insulators identified by the applicant as requiring AMR are

associated with the power feeds from the switchyard to the reserve auxiliary transformers. The

staff reviewed these component categories against the requirements of 10 CFR 54.4(a)(3) and

found this category is included in this requirement.

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

On the basis of its review, the staff finds that the switchyard bus and high-voltage transmission

conductor connections are passive, long-lived electrical components subject to an AMR and are

not identified by the applicant. The staff asked the applicant to provide justification for

excluding these components from AMR; otherwise, the applicant was to submit an AMR for the

subject components (RAI 2.5-2(b)). In its response dated November 20, 2003, the applicant

stated that switchyard buses and high voltage transmission conductor connections are in the

scope of license renewal and that the associated AMR is provided in Section 3.6 of the LRA.

2.5.3.3 Conclusions

The staff reviewed the LRA to determine whether any structures, systems, or components. that

should be within the scope'of license renewal were not identified by the applicant. The staff did

not identify any omissions. In addition, the staff performed an independent assessment to

determine whether any components that should be subject to an AMR were not identified by the

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applicant. The staff did not identify any omissions. On the basis of this review, the staff

concludes that the applicant has appropriately identified high voltage transmission conductors

and connections, insulators, and switchyard bus that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and that the applicant has appropriately identified high voltage

transmission conductors and connections, insulators, and switchyard bus that are subject to an

aging management review, as required by 10 CFR 54.21 (a)(1).

2.5.4 Electrical/l&C Penetration

Electrical/l&C penetration are used to pass electrical circuits through the containment wall while

maintaining containment integrity. They provide electrical continuity for the circuit, as well as a

pressure boundary for the containment. The pressure boundary function of electrical

penetration is addressed in LRA Section 2.4-1.

2.5.4.1 Summary of Technical Information in the Application

The applicant describes the electrical/l&C penetration in LRA Section 2.5.1.4. The applicant

stated that electrical penetrations perform the functions of primary containment boundary

(pressure integrity) and electrical continuity across the primary containment boundary. All

primary containment electrical penetrations are included in the scope of the rule. The electrical

continuity function of penetrations is managed under environment qualification (EQ) program

which is discussed in Section 4.4, Environmental Qualification of Electrical Equipment(EQ).

The pressure boundary function of every primary containment electrical penetration is

evaluated in LRA Section 2.4.1, Primary Containment, and the aging management program is

referenced in Section 3.5.1.3.

2.5.4.2 Staff Evaluation

The staff reviewed Section 2.5.1.4 of the LRA to determine whether the applicant has identified

the electrical components within the scope of license renewal, in accordance with 10 CFR 54.4,

and those subject to an AMR, in accordance with 10 CFR 54.21 (a)(1).

As part of this review, the staff selected system functions described in the UFSAR that were set

forth in 10 CFR 54.4 to verify that components having intended functions were not omitted from

the scope of the Rule. The staff also focused on components that were not identified as being

subject to an AMR to determine if any components were omitted.

The staff asked the applicant whether there are any electrical penetrations that are not covered

under EQ program (RAI 3.6-2). In its response dated October 3, 2003, the applicant stated that

at Dresden Station, all electrical penetrations are covered under the Environmental Qualification

(EQ) program. However, at Quad Cities Station, all but three electrical related penetrations (1-

X102B, 2-X100A, and 2-X105A) are part of the station EQ program. These three penetrations

serve circuits (such as drywell booster fans and main steam line vibration monitoring

instrumentation) that do not perform any license renewal intended function. As stated in

Section 2.5.1.4 of the LRA, the intended function (electrical continuity) is managed by the EQ

program. The mechanical and structural related intended functions of all electrical

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penetrations, including the three Quad Cities penetrations not included within the station EQ

program, are addressed in Table 2.4-1 under Component Group "Containment Penetrations

(Electrical)" and the associated aging management is discussed in Table 3.5-1, Aging

Management Reference 3.5.1.3 of the LRA.

2.5.4.3 Conclusions

The staff reviewed the LRA to determine whether any structures, systems, or components that

should be within the scope of license renewal were not identified by the applicant. The staff did

not identify any omissions. On the basis of this review, the staff concludes that the applicant

has appropriately identified the components of the electricaVl&C penetrations that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has

appropriately identified the components of the electricaVl&C penetration assemblies system that

are subject to an aging management review, as required by 10 CFR 54.21 (a)(1).

2.5.5 References

1. NEI 95-10, Industry Guidelines for Implementing the Requirements of 10 CFR Part 54-The

License Renewal Rule," Revision 3, Nuclear Energy Institute, March 2001.

2. NUREG-1801, "Generic Aging Lessons Learned (GALL) Report, U.S. Nuclear Regulatory

Commission,' April 2001.

3. NUREG-1 800, Standard Review Plan for Review of License Renewal Applications for

Nuclear Power Plants," April 2001.

4. 10 CFR Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power

Plants."

5. NRC letter to Alan Nelson and David Lochbaum, "Staff Guidance On Scoping of

Equipment Relied on to Meet the Requirements of the Station Blackout (SBO) Rule

(10 CFR 50.63) for License Renewal (10 CFR 54.4(a)(3)," dated April 1, 2002.

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3. AGING MANAGEMENT REVIEW

3.0 Aging Management Review

The applicant has fully utilized the Generic Aging Lessons Learned (GALL) process defined in

the standard review plan-license renewal (SRP-LR) (NUREG-1800, "Standard Review Plan for

the Review of License Renewal Applications for Nuclear Power Plants," issued April 2001) and

the GALL report (NUREG-1801, "Generic Aging Lessons Learned (GALL) Report," issued July

2001, Volumes 1 and 2). The GALL Report provides the staff with a summary of staff-approved

aging management programs (AMPs) for the aging of most structures and components that are

subject to an aging management review (AMR). If an applicant commits to implementing these

staff-approved AMPs, the time, effort, and resources used to review an applicant's license

renewal application (LRA) will be greatly reduced, thereby improving the efficiency and

effectiveness of the license renewal review process.

The GALL report is a compilation of existing programs and activities used by commercial

nuclear power plants to manage the aging of structures, systems, and components (SSCs)

within the scope of license renewal and which are subject to an AMR. The GALL report

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

aging for most of the structures and components used throughout the industry, and serves as a

reference for both applicants and staff reviewers to quickly identify those aging management

programs and activities that the staff has determined will provide adequate aging management

during the period of extended operation.

The GALL report identifies (1) systems, structures, and components, (2) component materials,

(3) the environments to which the components are exposed, (4) the aging effects associated

with the materials and environments, (5) the AMPs that are credited with managing the aging

effects, and (6) recommendations for further applicant evaluations of aging effects and their

management for certain specific components types.

In order to determine whether the GALL process would improve the efficiency of the license

renewal review, the staff conducted a demonstration project to exercise the GALL process and

determine the format and content of a safety evaluation based on the GALL review process.

The SRP-LR was prepared based on both the GALL model and the lessons learned from the

demonstration project.

As part of its review of the LRA, the staff performed an AMR inspection (Inspection Report 50-

237/03-10(DRS), 50-249/03-10(DRS), 50-254/03-14(DRS), 50-265/03-14(DRS)) from

September 29- October 22, 2003, at both Dresden and Quad Cities Stations. The purpose of

the inspection was to examine activities that support the LRA and consisted of a selected

examination of procedures, representative records, and interviews with the applicant regarding

proposed aging management activities. The team also reviewed the proposed implementation

of all AMPs credited in the LRA for managing aging.

The staff also performed an AMP audit on October 7-8, 2003. The audit team reviewed those

AMPs credited in the LRA for managing aging that the applicant claimed were consistent with

GALL. The audit team evaluated each of the 10 attributes of the applicant's AMP, which the

applicant claimed were consistent with the attributes of the associated AMP described in the

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GALL report. The applicant provided those AMPs that were not claimed to be consistent with

the GALL Report, and those attributes that were deviations from the attributes described in the

GALL Report AMPs, to the NRC staff for review. The team concluded that, with the exception

of the Fire Protection Program, One-Time Inspection Program, and the Selective Leaching

Program, the applicant's AMPs were consistent with the GALL Report AMPs with

differences/exceptions as stated in the LRA/requests for additional information (RAls). As

result of this audit, the applicant has implemented enhancements to these AMPs. The AMP

audit issues can be found in the staff's AMP Audit Report, dated April 23, 2004, and are

addressed in this safety SER.

As a result of the staff's review of the LRA, including the additional information and clarifications

submitted subsequently, the staff identified two proposed license conditions. The first license

condition requires the applicant to include the updated final safety analysis report (UFSAR)

Supplement in the next UFSAR update required by Title 10, Section 50.71 (e), of the Code of

Federal Regulations (10 CFR 50.71 (e)) following issuance of the renewed license. The second

license condition requires that the applicant complete the future activities identified in the

UFSAR Supplement before the period of extended operation.

3.0.1 The GALL Format for the LRA

The Dresden/Quad Cities LRA closely follows the standard LRA format. This format has been

used by previous applicants and will continue to be used by future applicants. However, there

are several important changes within the format that reflect the GALL process. First, the tables

in LRA Section 2 that identify the structures and components that are subject to an AMR now

include a third column which links plant-specific structures and components in the Section 2

tables to generic GALL component groups in Section 3 (this is discussed in more detail below).

Second, the tables in LRA Section 3 are different from the Section 3 tables used in previous

LRAs. There are no system-specific tables in Section 3 of the LRA. The individual components

within a system have been rolled up into a series of system group tables. For example, Section

2.3.3 of the Dresden/Quad Cities LRA addresses scoping and screening results for 28 auxiliary

systems. Each system has several components. In previous LRAs, each system had a

separate table that listed the components in the system, but with the Dresden/Quad Cities LRA,

there are no such individual system tables. Instead, all the components in the 28 auxiliary

systems are rolled up into two separate auxiliary system tables. LRA Table 3.3-1 consists of

auxiliary system components that were evaluated in the GALL report, and LRA Table 3.3-2

consists of auxiliary systems components that were not evaluated in the GALL report. Similarly,

the LRA tables for the other system groups (3.1 - reactor systems, 3.2 - engineered safety

feature systems, 3.4 - steam and power conversion systems, 3.5 - structures, and 3.6 -

electrical systems) have 3.X-1 LRA tables for components that were evaluated in the GALL

report and 3.X-2 LRA tables for components that were not evaluated in the GALL report (where

X corresponds to the appropriate subsection in Section 3).

The 3.X-1 tables provide information regarding AMPs that are consistent with the GALL Report.

The first four columns of Table 3.X-1 are derived from Tables 3.1-1 through 3.1-6 of the SRPLR. Included in this table is a discussion column. The discussion column provides a conclusion

indicating if the aging management evaluation results are consistent with GALL, along with any

clarifications or explanations required to support the conclusion, if the conclusion is different

than those of the GALL Report. For a determination to be made that a table line item is

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"Consistent with GALL," several criteria must be met. First, the plant-specific component is

reviewed against the GALL to ensure that the component, materials of construction; and

internal or external service environments are comparable to those described in a particular

GALL item. Second, for those that are comparable, the results of the plant aging management

review/aging effect evaluation are compared to the aging effects/mechanisms in the GALL.

Finally, the programs credited in the GALL for managing those aging effects are compared to

the programs described in the plant evaluation. If, using good engineering judgment, it could

be reasonably concluded that the plant evaluation is in agreement with the GALL evaluation, a

line item was considered consistent with GALL or NUREG-1 801. There are cases where

components, and component materiaVenvironment combinations, and aging effects are

common between a NUREG-1801 line item and the plant evaluation, but the AMP selections

differ.' In those cases the discussion column indicates the plant AMP selection, but no

conclusion is made that the line item is consistent with the GALL.

The 3.X-2 tables provide information regarding AMPs that are different from or not addressed in

the GALL Report. A plant component is considered not addressed by the GALL report if the

component type is not evaluated in the GALL or has a different material of construction or

operating environment than that evaluated in the GALL report.

The 3.X-2 tables are different from the 3.X-1 tables. The 3.X-2 tables include the component

types, materials, environments, aging effects requiring management (AERMs), programs and

activities for managing aging, and a discussion column. Because these structures and

components were not evaluated in GALL, the staff performed a review, similar to those done for

past applications.

3.0.2 The Staff's Review Process for GALL

The staff reviewed the Dresden/Quad Cities LRA for the AMR results and the associated AMPs

in three phases. In Phase 1, the staff reviewed the applicant's AMP descriptions to identify

those AMPs for which the applicant claimed consistency with those reviewed and approved in

the GALL report. In Section 3.0 of the LRA, the applicant stated the following in describing

what it means for AMPs to be considered uConsistent" with the GALL report (NUREG-1801):

Identifiesaging management reviewsthat are consistent with the NUREG-1801. This means thatthe

component group, material and environment are applicable, the aging effect and aging mechanisms

identified require management, the aging management program identified is appropriate, and the

review results of the key elements provided in Appendix B concludes that the program elements are

consistent with those elements provided in Chapters X and Xl of NUREG-1801.

For the AMPs for which the applicant claimed consistency with the AMPs in the GALL report,

the staff conducted an audit to confirm that the applicant's AMPs were consistent with the

AMPs in the GALL report.

Several AMPs were described by the applicant as being consistent with the GALL report, but

with some deviation. These deviations are of three types: (1) exceptions to the GALL report -

those evaluations where several of the individual NUREG-1801 line items may be evaluated as

consistent with NUREG-1 801 while other line items may be evaluated as exception to NUREG1801; (2) further evaluations recommended by the GALL report - provides reference to sections

3-3
providing further evaluation of aging management recommended by NUREG-1801; and (3)

clarifications to the GALL report - provides notes to clarify NUREG-1801 Volume 2 line items

such as those that are not in scope of license renewal or not installed at Dresden or Quad

Cities. For each AMP that had one or more of these deviations, the staff reviewed each

deviation to determine whether the AMP, as modified, would adequately manage the aging

effect(s) for which it is credited. Through a license condition, the staff will require that any

revisions to the AMP and UFSAR Supplement that must be made as a result of the deviation(s)

are completed and implemented before the start of the period of extended operation.

Some AMPs were identified by the applicant as exceptions to the GALL report which means:

those evaluations which are an exception to the NUREG-1 801 aging effects or aging

management program or activity and provides reference in Section 3 and/or Appendix B which

provides further explanation and justification. In these cases, the exception refers to all of the

NUREG-1801 line items. For those AMPs that are either identified as exceptions to the GALL

report or not evaluated in the GALL report, the staff evaluated each AMP against the 10 AMP

elements (Branch Technical Position RLSB-1 in Section A-1 of SRP-LR Appendix A). Through

a license condition, the staff will confirm any new AMPs and associated UFSAR Supplements

will be developed and implemented before the start of the period of extended operation.

The AMRs and associated AMPs in the GALL report fall into two broad categories: those AMRs

and associated AMPs that the GALL report concludes are adequate to manage aging of the

components referenced in the GALL report, and those AMRs and associated AMPs for which

the GALL report concludes that aging management is adequate, but further evaluation must be

done for certain aspects of the aging management process. In Phase 2, the staff compared the

applicant's AMR results and associated AMPs to the AMR results and associated AMPs in the

GALL report, to determine whether the applicant's AMRs and associated AMPs were consistent

with those reviewed and approved in the GALL report. For those AMR results and associated

AMPs for which the applicant claimed to be consistent with the GALL report, the staff conducted

an inspection to confirm that the applicant's AMRs and associated AMPs were consistent with

AMRs and associated AMPs in the GALL report. For AMRs and associated AMPs that were

not consistent with the GALL report, the staff's review determined whether the AMRs and

associated AMPs were adequate to manage the aging effects for which they were credited.

Finally, for those AMRs and associated AMPs for which the GALL report recommended further

evaluation, the staff reviewed the applicant's evaluation to determine whether the applicable

aging effect would be adequately managed during the period of extended operation.

Once it had determined that the applicant's AMRs and associated AMPs were adequate to

manage aging, the staff performed Phase 3 of its review by reviewing plant-specific structures

and components to determine whether the applicant demonstrated that the effects of aging will

be adequately managed so that the intended function(s) will be maintained consistent with the

current licensing basis (CLB) for the period of extended operation, as required by

10 CFR 54.21 (a)(3). Specifically, this review involved a component-by-component review to

determine whether the applicant properly applied the GALL program to the aging management

of components within the scope of license renewal and subject to an AMR (i.e., the staff

evaluated whether the applicant had properly identified the aging effects, and the AMPs

credited for managing the aging effects, for each structure and component within the scope of

license renewal and subject to an AMR). For structures and components evaluated in GALL,

the staff reviewed the adequacy of aging management against the GALL criteria. For

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structures and components not evaluated in GALL, the staff reviewed the adequacy of aging

management against the 10 criteria in Appendix A of the SRP-LR. Some structures and

components were not evaluated in GALL, but the applicant determined that the GALL AMR

results could be applied to these structures and components and provided justification to

support this determination. In these cases, the staff reviewed the adequacy of aging

management against the GALL criteria to determine whether the GALL AMPs were adequate to

manage the aging effects for which they were credited.

3.0.3 Common Aging Management Programs

Table 3.0.3-1 presents the common aging management programs.

Table 3.0.3-1: Common Aging Management Programs

Applicant's AMP (LRA Associated GALL LRA System Groups that Credit Staff Evaluation

section) AMP the AMP for Aging Management (SER Section)

Inservice Inspection (B.1.1) XI.M1, XI.S3 3.1 - RCS 3.0.3.1

3.5- Structures

Water Chemistry (B.1.2) XI.M2, XI.M21 3.1 - RCS 3.0.3.2

3.2 -ESF

3.3 - Auxiliary

3.4 -Steam and Power Conversion

3.5 - Structures

BWR Stress Corrosion XL.M7 3.1 - RCS 3.0.3.3

Cracking AMP (B.1.7) 3.2 - ESF

3.3 - Auxiliary

Flow-Accelerated XI.M17 3.1 - RCS 3.0.3.4

Corrosion (B.1.11) 3.4 - Steam and Power Conversion

Bolting Integrity (B.1.12) XI.M3, XI.M18 3.1 - RCS 3.0.3.5

3.2- ESF

3.3 - Auxiliary

3.4 - Steam and Power Conversion

Open-cycle Cooling Water XI.M20, XI.M21 3.2 - ESF 3.0.3.6

System (B.1.13) 3.3 - Auxiliary

3.4 - Steam and Power Conversion

Closed-cycle Cooling XI.M20, XI.M21 3.2 - ESF 3.0.3.7

Water System (B.1.14) 3.3 - Auxiliary

3.4 - Steam and Power Conversion

Compressed Air Monitoring XI.M24 3.1 - RCS 3.0.3.8

(B.1.16) 3.2- ESF

3.3 - Auxiliary

3.4 - Steam and Power Conversion

Above Ground Carbon XI.M29 3.3 - Auxiliary 3.0.3.9

Steel Tanks (B.1.20) 3.4 - Steam and Power Conversion

One-Time Inspection XI.M32 3.1 - RCS 3.0.3.10

(B.1.23) 3.2- ESF

3.3 - Auxiliary

3.4 - Steam and Power Conversion

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Applicant's AMP (LRA Associated GALL LRA System Groups that Credit Staff Evaluation

section) AMP the AMP for Aging Management (SER Section)

Selective Leaching XI.M33 3.2 - ESF 3.0.3.11

(B.1.24) 3.3 - Auxiliary

3.4 - Steam and Power Conversion

3.5 - Structures

Buried Piping and Tanks XI.M34 3.2 - ESF 3.0.3.12

Inspection (B.1.25) 3.3 - Auxiliary

3.4 - Steam and Power Conversion

Containment ISI (B.1.28) X.S1, XI.S1, XI.S2 3.5 - Structures 3.0.3.13

4.5 - Concrete and Containment

Tendon Pre-Stress TLAA

Structures Monitoring Xl.S6, XI.S7 3.3 - Auxiliary 3.0.3.14

(B. 1.30) 3.5 - Structures

Corrective Action Program Plant Specific All 3.0.4

(B.2.1)

Heat Exchanger Test and Plant Specific 3.1 - RCS 3.0.3.15

Inspection Activities (B.2.6) 3.2 - ESF

3.3 - Auxiliary

3.4 - Steam and Power Conversion

Lube Oil Monitoring Plant Specific 3.1 - RCS 3.0.3.16

Activities (B.2.5) 3.2 - ESF

3.3 - Auxiliary

3.4 - Steam and Power Conversion

Periodic Inspection of Plant Specific 3.1 - RCS 3.0.3.17

Ventilation System 3.2 - ESF

Elastomers (B.2.3) 3.3 - Auxiliary

3.4 - Steam and Power Conversion

Table 3.0.3-2 presents the system-specific aging management programs, the associated GALL

program, the system groups that credit the program for management of component aging, and

the SER section that contains the staff's review of the program.

Table 3.0.3-2: System-Specific Management Programs

Applicant's AMP (LRA Associated GALL AMP LRA System Groups that Staff Evaluation (SER

section) Credit the AMP for Aging Section)

Management

Reactor Head closure XI.M3 3.1 - RCS 3.1.2.3.1

studs AMP (B.1.3)

BWR vessel ID attachment XI.M4 3.1 - RCS 3.1.2.3.2

welds AMP (B.1.4)

Feedwater nozzle AMP XI.M5 3.1 - RCS 3.1.2.3.3

(B.1.5)

CRD retum line nozzle Xl.M6 3.1 - RCS 3.1.2.3.4

AMP (B.1.6)

BWR penetrations AMP XI.M7 3.1 - RCS 3.1.2.3.5

(B.1.8) I _ _

BWR vessel internals AMP XI.M13, XI.M16 3.1 - RCS 3.1.2.3.6

(B.1.9) _ _ .-

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Applicant's AMP (LRA Associated GALL AMP' LRA System Groups that Staff Evaluation (SER

section) Credit the AMP for Aging Section)

- Management

Thermal aging and neutron Xl.M13 3.1 - RCS 3.1.2.3.7

irradiation embrittlement

(B.1.10)

Reactor vessel Xl.M31 3.1 RCS 3.1.2.3.8

surveillance (B.1.22)

Periodic testing of Plant Specific 3.2 - ESF 3.2.2.3.2

drywelltorus nozzles

(B.2.4)

Overhead load handling XI.M23 3.3 - Auxiliary 3.3.2.3.1

system (B.1.15)

Reactor water cleanup XI.M25 3.3 - Auxiliary 3.3.2.3.2

system inspection (B.1.17)

Fire Protection (B.1.18) XI.M26 3.3 -'Auxiliary 3.3.2.3.3

Fire water system (B.1.19) XI.M27 . 3.3 - Auxiliary 3.3.2.3.4

Fuel oil chemistry (B.1.21) Xl.M30 3.3 - Auxiliary 3.3.2.3.5

Boraflex monitoring XI.M22 3.3 - Auxiliary 3.3.2.3.6

(B.1.36) :

Main generator stator Plant Specific 3.4 - Steam and Power 3.4.2.3.1

cooling water chemistry Conversion

(B.2.7)

Containment ISI (B.1.26- XI.S1, Xl.S4 3.5 - Structures 3.5.2.3.1

ASME Code, Section Xl,

Subsection IWE) -_-

ASME Code, Section Xl, Xl.S3 3.5 - Structures 3.5.2.3.2

Subsection IWF (B.1.27)

Masonry wall program XI.S5 3.5 - Structures 3.5.2.3.3

(B.1.29)

Inspection of water-control Xl.S7 3.5 - Structures 3.5.2.3.4

structures (B.1.31)

Protective coating XI.S8 3.5 - Structures 3.5.2.3.5

monitoring and

maintenance (B.1.32) ;-

Electrical Cables and Xl.E1 3.6 - Electrical 3.6.2.3.1

Connections not Subject to

EQ (B.1.33) _

Electrical Cables used in Xl.E2 3.6 - Electrical 3.6.2.3.2

Instrumentation Circuits

not Subject to EQ (B.1.37)

Inaccessible Medium Xl.E3 3.6 - Electrical 3.6.2.3.3

voltage Cables not Subject

to EQ (B.1.37) -

Bus Ducts Plant Specific 3.6 - Electrical 3.6.2.4.1

High Voltage Switchyard Plant Specific 3.6 - Electrical 3.6.2.4.2

Bus

High Voltage Transmission Plant Specific 3.6 - Electrical 3.6.2.4.3

Conductors

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Applicant's AMP (LRA Associated GALL AMP LRA System Groups that Staff Evaluation (SER

section) Credit the AMP for Aging Section)

Management

High Voltage Insulators Plant Specific 3.6 - Electrical 3.6.2.4.4

Non-EQ Electrical Plant Specific 3.6 - Electrical 3.6.2.4.5

Penetration Assemblies

Environmental X.El 3.6 - Electrical 4.4

Qualification (8.1.35) I I

3.0.3.1 ASME Section Xi Inservice Inspection, Subsections IWB, IWC, and IWD (B. 1.1)

3.0.3.1.1 Summary of Technical Information in the Application

The applicant's inservice inspection program is discussed in LRA Section B.1.1."ASME Section

XI Inservice Inspection, Subsections IWB, IWC, and IWD." The applicant states that with

enhancements the program is consistent with the ten elements of aging management program

XI.M1. "ASME Section Xl Inservice Inspection, Subsections IWB, IWC, and IWD," identified in

the GALL, with the exception that the GALL specifies that the aging management of the

isolation condenser be performed under Subsection IWB (for Class 1 components) of the

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

Xl. However, the isolation condenser of Dresden is classified as ASME Code Class 2 on the

tube side and Class 3 on the shell side. Therefore, the applicant stated in the LRA that

Subsections IWC and IWD are applicable for aging management of the isolation condenser in

lieu of Subsection IWB, since Class 1 requirements do not apply.

This AMP is credited with managing aging in the reactor coolant system (RCS) piping, reactor

internals, and components in the RCS except the reactor vessel and structures. The GALL

specifies that the program to comply with the 1995 Edition through the 1996 Addenda of the

ASME Code, Section Xl. The current Code of record for Dresden and Quad Cities is the 1989

Edition of ASME Section Xl. The LRA contains a commitment by the applicant to enhance the

program to be consistent with the requirements of the 1995 Edition through the 1996 Addenda

of the ASME Code, Section Xl. This enhancement is scheduled for implementation prior to the

period of extended operation. This is Commitment #1 in Appendix A of this SER.

The LRA notes that both Dresden and Quad Cities have successfully identified indications of

age-related degradation prior to any loss of intended function of components, and have taken

appropriate corrective actions through evaluation, repair, or replacement of components in

accordance with the ASME Code, Section Xl and station implementing procedures.

The applicant concludes that the ASME Section Xl Inservice Inspection, Subsections IWB,

IWC, and IWD aging management program provides reasonable assurance that aging effects

are adequately managed so that the intended functions of components within the scope of

license renewal that are covered by this program are maintained during the period of extended

operation.

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3.0.3.1.2 Staff Evaluation

In LRA Section B.1.1, "ASME Section Xl Inservice Inspection, Subsections IWB, IWC, and

IWD," the applicant described its AMP to manage aging in the reactor coolant pressure

retaining piping and components within the scope of license renewal, except for the reactor

pressure vessel. The LRA stated that this AMP is consistent with the GALL AMP Xl.M1, "ASME

Section Xl, Subsections IWB, IWC, and IWD," with an exception regarding the application of

Subsection IWB for the Dresden isolation condenser, which is not a Class 1 component and

therefore, Subsection IWB does not apply. For this AMP, the GALL recommends further

evaluation. The staff confirmed the applicant's claim of consistency during the AMR inspection.

Furthermore, the staff reviewed the deviation and enhancement and justification of the deviation

to determine whether the AMP, with the deviation, remains adequate to manage the aging

effects for which it is credited. The staff also reviewed the UFSAR supplement to determine

whether it provides an adequate description of the revised program. Finally, the staff

determined whether the applicant properly applied the GALL program to its facilities. In a letter

dated, August 7, 2003, the staff requested additional information from the applicant relative to

the inservice inspection (ISI) program. The applicant responded in a letter dated October 3,

2003.

In response to RAI B.1.1 (d) the applicant provided additional clarification related to ASME

Code, Section XI,Subsection IWB and IWC program requirements and the alternative riskinformed inservice inspection (RI-ISI) programs for Class 1 and 2 piping within the scope of

license renewal previously reviewed and approved by the NRC. The applicant stated that LRA

Appendix B, Section B.1.1 should have noted an exception for the implementation of RI-ISI and

its alternative inspections for Class 1 and 2 piping within the scope of license renewal, which

will be implemented at both Dresden and Quad Cities. In addition the applicant confirmed that

the plant specific RI-ISI evaluations have not identified any particular risk significant

components subject to aging management or particular aging effects not addressed in the

GALL. Since the Dresden and Quad Cities RI-ISI programs have been approved as an

acceptable alternative to the ASME Code, Section Xl, Subsection IWB and IWC program

requirements and the alternative risk-informed inservice inspection (RI-ISI) programs for Class

1 and 2 piping and since the RI-ISI evaluations did not identify any particular risk significant

components subject to aging management or particular aging effects not addressed in the

GALL, the staff finds the use of RI-ISI to be acceptable.

3.0.3.1.3 Conclusions

On the basis of its review and audit of the applicant's program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

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3.0.3.2 Water Chemistry Program (B. 1.2)

3.0.3.2.1 Summary of Technical Information in the Application

The applicant's water chemistry program is discussed in LRA Section B.1.2 uWater Chemistry".

The applicant states that with exceptions and enhancements the program is consistent with the

ten elements of aging management program XI.M2."Water Chemistry," specified in the GALL.

The applicant identified the following exceptions to the GALL:

* The Dresden and Quad Cities water chemistry programs are based on EPRI-TR-1 03515-

Rev. 2, while the GALL references Revision 1.

* The GALL indicates that hydrogen peroxide is monitored to mitigate degradation of

structural materials. Dresden and Quad Cities programs do not monitor for hydrogen

peroxide.

* The GALL indicates that the condensate storage tank, demineralized water storage tank,

and torus (pressure suppression pool) water are sampled for dissolved oxygen. The

Dresden and Quad Cities programs do not sample for dissolved oxygen.

* The GALL indicates that water quality (pH and conductivity) is maintained in accordance

with established guidance. Dresden and Quad Cities programs do not monitor pH in the

condensate storage tank, demineralized water storage tank, or torus (pressure suppression

pool) water.

* Aging of SBLC system components not in the reactor coolant pressure boundary section of

SBLC system relies on monitoring of SBLC makeup water chemistry. The makeup water is

monitored in lieu of the storage tank. The effectiveness of the water chemistry program will

be verified by a one-time VT-3 inspection of a Dresden SBLC pump discharge valve casing

and a Quad Cities SBLC pump casing as discussed in the One-Time Inspection (B.1.23)

aging management program.

The applicant indicated that the Dresden and Quad Cities Water Chemistry programs will be

enhanced by revising procedures to provide for increased sampling to verify corrective actions

taken to address abnormal chemistry conditions. It will revise the Quad Cities procedure for

turbine building sample panel collection will be revised to assure maintenance of the chemistry

integrity of samples. These enhancements are scheduled for implementation prior to the period

of extended operation. This is Commitment #2 in Appendix A of this SER.

The applicant stated that appropriate guidance for maintaining the contaminants below specific

limits is provided and that periodic self-assessments of the water chemistry activities have been

and continue to be performed to identify areas that need improvement to maintain the quality

performance of the activity.

According to the applicant, the water chemistry program has identified instances where

parameters were outside the established specifications. The applicant initiated increased

sampling and actions to bring the parameters back into specification.

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This AMP is credited with managing the RCS, engineered safety features (ESF), auxiliary, and

steam and power conversion systems and structures.

The applicant concluded that with the exceptions and enhancements, the Water Chemistry

aging management program provides reasonable assurance that aging effects are adequately

managed so that the intended functions of components within the scope of license renewal that

are covered by this program are maintained during the period of extended operation.

3.0.3.2.2 Staff Evaluation

In LRA Section B.1.2, "Water Chemistry," the applicant described its AMP to manage aging of

components exposed to reactor water, condensate and feedwater, control rod drive (CRD)

water, demineralized water storage tank water, condensate tank water, torus water (pressure

suppression pool), and spent fuel pool water. The LRA stated that this AMP is consistent with

GALL AMP Xl.M2, "Water Chemistry," with exceptions and enhancements. For this AMP,

GALL recommends further assessment in the form of a plant specific evaluation. The staff

confirmed the applicant's claim of consistency during the AMR inspection. Furthermore, the

staff reviewed the exceptions and their justifications to determine whether the AMP, with the

exceptions, remains adequate to manage the aging effects for which it is credited. The staff

also reviewed the UFSAR supplement to determine whether it provides an adequate description

of the revised program. The staff also reviewed the applicant's evaluation to determine whether

it addressed the additional issues recommended in the GALL report and confirmed that the

AMP would adequately address these issues. Finally, the staff determined whether the

applicant properly applied the GALL program to its facility.

In a letter dated, August 7, 2003, the staff requested additional information from the applicant

relative to the water chemistry program. The applicant responded to these RAls in a letter

dated October 3, 2003.

The GALL water chemistry program references revision 1 of the EPRI BWR Water Chemistry

Guidelines, TR-1 03515, while the applicant currently employs revision 2 of the EPRI BWR

Water Chemistry Guidelines. The exceptions identified in the applicant's LRA all relate to the

applicant's use of Revision 2 of EPRI TR-1 03515, 'BWR Water Chemistry Guidelines". In

addition to the exceptions identified in the applicant's LRA, the staff requested that the applicant

outline the key differences between revision 1 and revision 2 and justify why revision 2 is

acceptable for use at Dresden and Quad Cities in RAI B.1.2a. The applicant indicated that

Revision 2 of the EPRI BWR Water Chemistry Guideline recommends that chlorides and

sulfates need not be measured on a daily basis provided conductivity is trended to ensure

action level I limits are not exceeded. The applicant has not implemented this change and

continues to monitor chlorides and sulfates in accordance with the guidance of Revision 1. The

applicant indicated that Revision 2 of the EPRI BWR Water Chemistry Guideline recommends

that plants using hydrogen water chemistry (HWC) with noble metals chemical addition (NMCA)

no longer need to measure electrochemical potential (ECP) on a continuous basis. The

applicant uses HWC with NMCA; however, the applicant continues to use ECP monitoring. The

applicant indicated that Revision 2 of the EPRI BWR Water Chemistry Guideline allows plants

utilizing HWC with NMCA to employ higher action levels for chlorides and sulfates based on the

increased protection provided by the HWC with NMCA. The applicant indicated these

increased chloride and sulfate limits have been incorporated into chemistry procedures. The

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applicant further stated that corrective action is required to reduce chloride and sulfate level if

parameters exceed plant goal values which are established at values significantly below the

EPRI Guideline chloride and sulfate action levels. The applicant indicated that Revision 2 of

the EPRI BWR Water Chemistry Guideline recommends the reactor water iron levels be

monitored as a new diagnostic parameter and that the action level for feedwater copper be

decreased. The applicant has incorporated these conservative actions into the plant chemistry

procedures. The applicant indicated that Revision 2 of the EPRI BWR Water Chemistry

Guidelines recommends that the action level for minimum feedwater dissolved oxygen be

increased. This change is considered conservative relative to reducing the FAC wear rates and

the applicant has incorporated this change into the plant chemistry procedures. The staff finds

that the applicant's use of revision 2 of the EPRI BWR Water Chemistry Guidelines acceptable

because the applicant has conservatively implemented the requirements of revision 2 by

continuing to monitor chlorides and sulfates on a daily basis, continuing to monitor ECP in

conjunction with the use of HWC with NMCA, implementing monitoring of new parameters

(feedwater iron concentration) and conservatively adjusting the limits of other parameters

(feedwater copper and dissolved oxygen) as recommended in revision 2 of the EPRI BWR

Water Chemistry Guidelines. Further, the staff has previously reviewed implementation of

Revision 2 of the EPRI BWR Water Chemistry Guidelines as documented in NUREG-1769,

"Safety Evaluation Report Related to the License Renewal of Peach Bottom Atomic Power

Station, Units 2 and 3". Therefore, the staff finds the use of revision 2 to be acceptable.

The applicant took exception to the GALL BWR water chemistry program and indicated that

dissolved oxygen and pH are not monitored in the condensate storage tank, demineralized

water storage tank, and the torus water. In RAls B.1 .2c and e, the staff requested the applicant

to identify if alternative methods are applied to characterize the aggressiveness of the water

chemistry in lieu of pH and oxygen measurements, and, if so, to describe the methods and its

implementation. The applicant responded that the following alternative methods are applied:

monitoring of conductivity, chlorides, and sulfates are in accordance with limits set by EPRI TR103515, Rev.2 and plant procedures employ goal values set below the EPRI guideline action

limits. Furthermore, the applicant indicated that if parameters exceed the goal values, the

parameters are-verified, and if necessary corrective action is implemented to return the

parameters to the desired ranges. These actions include increased sampling frequency to

verify the effectiveness of corrective action. The staff finds the response to be acceptable

because the alternate methods are recommended in the EPRI guidelines, plant goal values are

conservatively set, and corrective actions, including increased sampling, are taken when the

goal values are exceeded.

The applicant indicated that aging management for the SBLC system relies on monitoring the

SBLC make-up water in lieu of the storage tank water because the sodium pentaborate solution

would likely mask most chemistry parameters monitored. Since the applicant does not monitor

the storage tank solution, the staff requested in RAI B.1.2d, that the applicant provide

assurance that the receipt inspection process will preclude introduction of unexpected impurities

with the sodium pentaborate to avoid aggressive conditions in the tank. The applicant stated

that Borax and Boric Acid (which are combined to make the sodium pentaborate) are

purchased and verified by receipt inspection to meet General Electric Material Specification

D50YP1, Revision 3.

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The staff noted that due to a potential difference in the concentration of sodium pentaborate in

the system (the tank and suction piping are typically at a much higher concentration from the

remainder of the system), that the proposed chemistry inspections may not provide information

on the condition of the tank and pump suction piping. The staff requested in RAI B 1.2 -1 that

the applicant provide supplemental information regarding how aging degradation of the SBLC

tank and suction piping will be managed, since sampling chemistry downstream of the tank and

receipt inspection of the chemicals used in the tank will not provide adequate assurance that

degradation is not occurring in this section of the system. The staff identified this issue as

Confirmatory Item B.1.2-1.

The applicant responded in letters dated December 22, 2003 and March 25, 2004, that it will

perform an ultrasonic examination of portions of the SBLC tank. This is part of Commitment

#23 of Appendix A of this SER. The ultrasonic examinations will be used to identify potential

loss of material and stress corrosion cracking. The applicant will perform one ultrasonic

inspection in each quadrant, near the bottom of the tank. The applicant considers this location

to be the most susceptible location for degradation. The ultrasonic testing (UT) examinations

will include a portion of the tank shell and vertical seam weld and, if accessible, a portion of a

circumferential weld in accordance with the applicant's nondestructive examination (NDE)

procedures. If necessary, the exam results will be addressed by the applicant's corrective

action program.

The staff finds that the applicant will adequately manage aging in the SBLC system through the

combined use of inspection of pump casing, ultrasonic inspection of the SBLC tank and control

of additional chemicals according to the applicant's receipt inspection program. Therefore,

Confirmatory Item B.1.2-1 is closed.

The staff requested in RAI B.1.2g that the applicant indicate how the One-Time Inspection

Program will be applied to the most vulnerable areas, the basis for selection of these areas,

how these areas are applicable to other system locations covered by the Water Chemistry

AMP, and to confirm the effectiveness of the AMP to manage aging effects in areas of low flow

and other areas subject to degradation if the management of water chemistry is inadequate. A

similar request was made in RAI B.1.23-1. The applicant's response indicated that components

are selected based on materials of construction and system conditions, such as stagnant or low

flow areas, that would be most susceptible to general, crevice and pitting corrosion and noted

that if test or inspection results do not satisfy inspection criteria, an evaluation will be performed

and a condition report initiated to document the concern in accordance with plant administrative

procedures. The staff requested the applicant clarify their response regarding chemistry onetime inspections for detecting general and pitting corrosion. The applicant responded in a letter

dated December 12, 2003 and indicated that the Chemistry One-Time Inspections will inspect

for general, pitting and crevice corrosion of carbon steel and stainless steel components. The

staff concluded that the applicant's use of one time inspection will adequately verify the

effectiveness of the water chemistry program to manage aging because the applicant will

perform inspections in stagnant and low flow areas to detect general crevice and pitting

corrosion as outlined in the GALL.

The staff requested in RAI B.1.2h, the applicant provide further information with regard to how

the water chemistry program will manage the effects of aging of the aluminum tanks containing

condensate and demineralized water. The applicant responded that crevice and pitting

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corrosion are the aging mechanisms of concern for the aluminum tanks and described the

guidance that will be followed in maintaining a low impurity environment (EPRI TR-1 03515,

Rev. 2) to minimize crevice and pitting corrosion. Further, the applicant stated in a letter dated

December 12, 2003, that the aluminum tanks will have periodic internal visual inspections and

UT inspection will be performed on the tank bottoms as part of the above ground tank AMP

described in Section 3.0.3.9. The response is acceptable to the staff because the aging

mechanisms identified are those of concern with these components, the applicant will follow the

EPRI BWR Chemistry guidelines and internal inspections will be performed.

In RAI B.1 .2i, the staff requested the applicant to provide additional information relative to its

operating experience by discussing the abnormal chemistry conditions mentioned in the LRA,

and the actions taken. The applicant responded with several examples where water chemistry

parameters were observed to be outside established specifications, and discussed the

conditions and the resulting corrective actions, including increased sampling to verify the

effectiveness of corrective actions. The applicant indicated that its review of operating

experience at both Dresden and Quad Cities did not note any degradation attributable to

abnormal chemistry conditions. The staff finds the applicant's response acceptable because

the applicant's review of operating experience indicates that degradation has not been

traceable to instances of abnormal chemistry.

3.0.3.2.3 Conclusions

On the basis of its review and audit of the applicants program, the staff finds that those portions

of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. In addition, the staff has reviewed the exceptions to the

GALL program and finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

during the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and finds that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.0.3.3 BWR Stress Corrosion Cracking (B. 1.7)

3.0.3.3.1 Summary of Technical Information in the Application

The applicant's stress corrosion cracking aging management program is discussed in LRA

Section B.1.7 "BWR Stress Corrosion Cracking". The purpose of this program is to mitigate

intergranular stress corrosion cracking (IGSCC) in stainless steel reactor coolant pressure

boundary components and in stainless steel piping four inches and greater nominal pipe size.

Preventive measures include monitoring and controlling of water impurities by water chemistry

program activities and providing replacement stainless steel components in the solution

annealed condition with a maximum carbon content of 0.035 wt.% and a minimum ferrite level

of 7.5 wt. %. The applicant conducts inspection and flaw evaluation activities in accordance

with the inservice inspection program plans for the stations.

This AMP is credited with managing aging in RCS, ESF, and auxiliary systems.

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The applicant stated that the program will be enhanced prior to the period of extended

operation to be consistent with the requirements of the 1995 Edition through the 1996 Addenda

of the ASME Code Section Xl Code. With the enhancement, the applicant states that the

program is consistent with the 10 elements of aging management program XI.M7."BWR Stress

Corrosion Cracking" specified in the GALL report. An exception is that GALL specifies the 1993

revision of EPRI TR-1 03515, "BWR Water Chemistry Guidelines." The applicant is applying

the 2000 revision of the EPRI guidelines.

According to the applicant, the BWR stress corrosion cracking aging management program

activities have detected flaw indications in reactor coolant pressure boundary piping prior to loss

of intended functions of the component. Examples are indications on the reactor vessel safe

ends, and recirculation piping. The applicant's engineering staff evaluated these indications

and, where necessary, performed repairs in accordance with ASME Code Section Xi and

station procedural requirements. The LRA indicates that periodic self-assessments of program

activities have been performed and will continue to be performed to identify areas that need

improvement. The applicant states that when problems have been identified, corrective actions

have been taken to prevent recurrence.

The applicant concluded that the BWR Stress Corrosion Cracking aging management program

including the exception and enhancement provides reasonable assurance that IGSCC aging

effects will be adequately managed so that the intended functions of the stainless steel

components in the reactor coolant pressure boundary are maintained during the period of

extended operation.

3.0.3.3.2 Staff Evaluation

In LRA Section B.1.7, UBWR Stress Corrosion Cracking," the applicant described its AMP and

stated that this AMP is consistent with the GALL AMP XI.M7, "BWR Stress Corrosion

Cracking," with exceptions regarding the use of an updated edition of EPRI-TR-103515 "BWR

Water Chemistry". The staff evaluation of exceptions to the water chemistry program is

contained in Section 3.0.3.2 of this SER. The staff confirmed the applicant's claim of

consistency with GALL. Furthermore, the staff reviewed the exception and justifications to

determine whether the AMP, with the exception, remains adequate to manage the aging effects

for which it is credited. The staff also reviewed the UFSAR supplement to determine whether it

provides an adequate description of the revised program. In addition, for D/QCNPS,-the staff

determined whether the applicant properly applied the GALL program.

In a letter dated August 7, 2003, the staff requested the applicant to expand on the operating

experience in the BWR Stress Corrosion Cracking Program description by providing plant

specific experiences with managing IGSCC using this program. The staff also asked the

applicant to provide information regarding whether hydrogen water chemistry and noble metal

chemical addition (NMCA) are implemented at the Dresden and Quad Cities plants and how

implementation has affected monitoring of water chemistry parameters.

The applicant responded in a letter dated October 3, 2003, providing a representative account

of past experience in managing IGSCC at Dresden and Quad Cities. The applicant has

identified IGSCC throughout plant history at D/QCNPS and has performed engineering

evaluations and repairs or has replaced components with IGSCC resistant material. Mitigative

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actions such as induction heat stress improvement (IHSI) of susceptible welds and HWC with

NMCA have been implemented to assist in managing IGSCC. The applicant related cases

where the program inspection schedule has been conservatively adjusted based on plant

operating experience to support management of IGSCC detection.

For instance, the applicant indicated that at Quad Cities it follows the inspection frequencies

identified in Boiling Water Reactor Vessel and Internals Project (BWRVIP)-75, "Technical Basis

for Revisions to Generic Letter 88-01 Inspection Schedules (NUREG-0313)," issued October

1999, for Category C through E welds (there are no Category B welds) for normal water

chemistry, although HWC with NMCA has been implemented and BWRVIP 75 would support

reduced inspection frequencies with HWC with NMCA implemented. At Dresden, the applicant

indicated that inspection frequencies are based on BWRVIP-75 guidelines for either normal

water chemistry or HWC with NMCA. The applicant stated that inspection frequencies are only

reduced (per BWRVIP-75) in Unit 2 where improved water chemistry has been demonstrated to

be effective. The applicant indicated that improved water chemistry has been used in Unit 2

since 1983, but was not implemented in Unit 3 until 1996. The staff finds the applicant's

response acceptable because the applicant's program follows the guidelines of BWRVIP-75

and has incorporated plant operating experience to manage IGSCC.

3.0.3.3.3 Conclusions

On the basis of its review and audit of the applicant's program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

3.0.3.4 Flow-Accelerated Corrosion (B. 1.11)

3.0.3.4.1 Summary of Technical Information in the Application

The applicant's flow-accelerated corrosion (FAC) aging management program is discussed in

LRA Section B.1.11, "Flow-Accelerated Corrosion," and is based on EPRI guidelines found in

NSAC-202L-R2, "Recommendations for an Effective Flow Accelerated Corrosion Program."

The program predicts, detects, and monitors for loss of material by wall thinning in piping,

fittings, and valve bodies due to FAC.

This AMP is credited with managing aging in piping, fittings, and valve bodies in the RCS and

Steam and Power Conversion systems.

The applicant states that analytical evaluations and periodic examinations of locations that are

most susceptible to wall thinning due to FAC are used to predict the amount of wall thinning in

pipes and fittings. Program activities include analyses to determine critical locations, baseline

inspections to determine the extent of thinning at these critical locations, and follow-up

inspections to confirm the predictions. Repairs and replacements are performed as necessary.

3-16
The applicant states that operating experience has shown that the program can determine

susceptible locations for FAC, predict component degradation, and detect wall thinning in piping

and valves due to FAC.

The applicant states that with an enhancement, the FAC AMP is consistent with the ten

elements of aging management program Xl.M17, "Flow-Accelerated Corrosion," specified in

NUREG-1 801 . The enhancement required to make the applicant's program consistent with the

GALL is to expand the program scope to include main steam piping within the scope of license

renewal. The applicant stated that this enhancement is scheduled for implementation prior to

the period of extended operation.

3.0.3.4.2 Staff Evaluation

In LRA Section B.1.11, "Flow-Accelerated Corrosion," the applicant described its AMP to

manage flow-accelerated corrosion in piping, fittings, and valves within the scope of license

renewal. The LRA stated that this AMP is consistent with GALL AMP XL.M17, "FlowAccelerated Corrosion" with no deviations. The program will require one enhancement, which

the applicant has committed to make prior to the period of extended operation, to make it

consistent with GALL. This is Commitment #11 in Appendix A of this SER. The staff confirmed

the applicant's claim of consistency with GALL during the AMR inspection. In addition, the staff

determined whether the applicant properly applied the GALL program to its facilities. The staff

also reviewed the UFSAR supplement to determine whether it provides an adequate description

of the program.

In a letter dated, August 7, 2003, the staff requested in RAI B.1.11, that the applicant provide

operating experience demonstrating the effectiveness of the program such as corrective actions

taken, identifying changes to the program to ensure that flow accelerated corrosion has been

successfully managed and provide evidence that the current aging management program has

been effective to successfully mitigate and detect wall thinning during the time period

addressed by the LRA.

In a letter dated October 3, 2003, the applicant responded with a detailed account of operating

experience related to the Flow Accelerated Corrosion (FAC) programs at both Dresden and

Quad Cities. The applicant noted that the FAC programs at Dresden and Quad Cities have

identified wall thinning prior to the loss of intended function of the piping. Program changes

made to improve effectiveness were also identified. The EPRI approved FAC software

(CHECWORKS) is maintained by the applicant to improve the modeling and prediction of wall

thinning. In addition, when degradation is detected, additional inspections are performed to

ensure that the area of thinning has been bounded. The program has resulted in the timely

replacement of degraded piping, in most cases with piping made of FAC resistant materials,

and the programs have been maintained and upgraded on the basis of plant operating

experience. The response addresses the issues posed in the RAI and demonstrated to the staff

satisfaction that the FAC programs have been effective in managing aging effects from wall

thinning.

The staff finds the Flow-Accelerated Corrosion Program to be acceptable because the program

is consistent with the GALL report and because the program has used plant specific experience

to ensure that the program is adequately managing aging effects.

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3.0.3.4.3 Conclusions

On the basis of its review and audit of the applicant's program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.0.3.5 Bolting Integrity (B. 1.12)

3.0.3.5.1 Summary of Technical Information in the Application

The applicant's bolting integrity program is discussed in LRA Section 6.1.12, "Bolting Integrity

Program." The applicant states that the program is consistent with GALL program XI.M1 8,

"Bolting Integrity," with the following exceptions:

* The GALL report indicates that EPRI TR-104213, "Bolted Joint Maintenance and

Applications Guide," is used as a basis for evaluation of the structural integrity of nonsafety-related (NSR) bolting. The Dresden and Quad Cities programs address the guidance

contained in EPRI TR-1 04213 but do not specifically cite its use.

* The GALL report indicates that the program covers all bolting within the scope of license

renewal including structural bolting. The Dresden and Quad Cities bolting integrity programs

do not address structural bolting. The Structures Monitoring Program (B.1.30) covers aging

management of structural bolting.

* The GALL report indicates that the program covers all bolting within the scope of license

renewal including bolting for Class 1 nuclear steam supply system (NSSS) component

supports. The Dresden and Quad Cities bolting integrity programs do not address Class 1

NSSS component support bolts which are covered under the ASME Section Xl, Subsection

IWF aging management program (B.1.27).

* The GALL report indicates that the program generally includes periodic inspection for loss

of preload. The Dresden and Quad Cities programs do not include inspections for loss of

preload because loss of preload in a mechanical joint is a design driven effect and not an

aging effect.

The applicant also identified two enhancements which will be required to make the AMP

consistent with GALL. The program will be revised to be in accordance with the 1995 Edition

through the 1996 Addenda and approved relief requests of ASME Section Xl for inservice

inspection of Class 1,2, and 3 components. Also, the program will provide for formal

inspections of bolted joints in diesel generator components and performing periodic inspection

of components with bolted joint is in high humidity/moisture areas (pump vaults). These

enhancements will be implemented prior to the period of extended operation.

3-18
The applicant stated that Dresden and Quad Cities have experienced isolated cases of bolting

degradation attributed to aging effects due to loss of material and cracking. System engineer

walkdowns have also identified incidental surface rust on exterior component surfaces. In all

cases, the existing inspection and testing methodologies have discovered deficiencies and -

corrective actions were implemented prior to loss of 'system or component intended functions.

This AMP is credited for managing degradation of bolting in the RCS, ESF, Auxiliary, and

Steam and Power Conversion Systems.

3.0.3.5.2 Staff Evaluation

In LRA Section B.1.12, "Bolting Integrity Program," the applicant described its AMP to manage

effects of aging in bolting. The LRA states that this AMP is consistent with GALL AMP XI.M18,

"Bolting Integrity," with the exceptions in regard to (1) the reference to EPRI TR-104213; (2) this

AMP does not cover structural bolting; (3) this AMP does not include aging management of

ASME Section Xl Class 1, 2, and 3, and Class MC support members, including mechanical

connections; and (4) inspection for loss of preload is not included in this AMP. The staff

reviewed the applicant's claim of consistency with GALL, including the exceptions and

justifications, during the AMR inspection. In addition, the staff determined whether the

applicant properly applied the GALL program to its facility. The staff also reviewed the UFSAR

supplement to determine whether it provides an adequate description of the program. In a

letter dated August 7, 2003, the staff requested additional information from the applicant on the

bolting integrity program. The applicant responded to staff's RAI in letter dated October 3,

2003.

With regard to non-safety-related bolting, the applicant clarified its compliance with the GALL

referenced industry consensus recommendations in EPRI TR-104213 in their response to RAI

B.1.12(c). The applicant confirmed that the non-safety-related bolting integrity program

addressed in LRA Section B.1.12 meets the intent of the aging management attributes

delineated in EPRI TR-104213 including material procurement, use of approved lubricants and

sealants, proper torquing, and leakage evaluations. - However, the bolting program

implementing procedures do not specifically reference EPRI TR-1 04213. The applicant

committed to enhance the implementing procedures for this aging management program to

reference maintenance evaluations and repairs of non-safety-related bolted connections

following the EPRI bolting guidelines per EPRI NP-5769, "Degradation and Failure of Bolting in

Nuclear Power Plants," and TR-1 13859 "Proceeding of the 1st International Conference on

Sealing Technology and Plant Leakage Reduction (ICSTPLR-99)" for the evaluation and repairs

of the flange and bolts. This is part of Commitment #12 in Appendix A of this SER. The staff

finds that the applicant's bolting integrity aging management program for non-safety-relatedbolting consistent with the recommendations in the GALL and will meet or exceed the standards

delineated in EPRI TR-104213.

For safety-related bolting, the GALL relies on the NRC recommendations and guidelines on

comprehensive bolting integrity program delineated in NUREG-1 339 'Resolution of Generic

Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants," and industry's

technical basis for the program and guidelines in regard to material selection and testing,

bolting preload control, inservice inspection'(ISl), plant operation and maintenance, and

evaluation of structural integrity of bolted joints outlined in EPRI NP-5769, with the exceptions

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noted in NUREG-1 339. The LRA states that the bolting integrity program at Dresden and Quad

Cities incorporates industry recommendations addressed in EPRI NP-5769, yet makes no

reference to the NRC recommendations delineated in NUREG-1339 and NRC exceptions to

EPRI NP-5769. In their response to RAI B.1.12(d) the applicant confirmed that Dresden and

Quad Cities programs meets the intent of EPRI NP-5769, and the exceptions noted in

NUREG-1339, for material selection, testing, inservice inspection (ISI), and plant surveillance

and maintenance practices. The corporate and station implementing procedures specifically

cite EPRI NP-5769, however NUREG-1339 was not specifically referenced. The applicant

committed to enhance the implementing procedures for this aging management program to

reference NUREG-1339. This is part of Commitment #12 in Appendix A of this SER.

The scope of the Bolting Integrity program in the GALL primarily applies to the ASME code

piping and components including high strength bolting used in NSSS component supports

where the actual yield strength is greater than 150 ksi (GALL item number IlI.B.1.1.2-a). Other

structural bolting used in supports, including expansion and anchor bolts are managed under

ASME Code, Section Xl, Subsection IWF (B.1.27) or the Structures Monitoring program

(B. 1.30) in accordance with GALL.

The LRA states that the Dresden and Quad Cities bolting integrity programs do not include

bolting for Class 1 NSSS component support bolts. However, the applicant identified two uses

of high strength bolting in supports for Class 1 piping and components - refer to Staff's

discussion in Section 3.5.2.4.5.2 of this SER. The staff finds that the applicant's information

related to American Society for Testing and Materials (ASTM) Al 93, Grade B7 bolting material

is sufficient to establish that the upper limit on yield strength is less than 150 ksi; consequently,

the additional inspections of XI.M.1 8 Bolting Integrity are not warranted for A193, Grade B7.

However, in part (c) of its response, the applicant has assumed that the bolt material used in "a

friction type connection at the reactor skirt base" is ASTM A193, Grade B7 or equivalent. The

applicant was requested to confirm that assumption or commit to inspection in accordance with

NUREG-1801, Program XI.M.18 Bolting Integrity. In a letter dated December 5, 2003, the

applicant stated that it would commit to inspection in accordance with NUREG-1 801, Program

XI.M.18 Bolting Integrity since it could not confirm that the yield strength of the bolts would be

less than 150 ksi. This is part of Commitment #12 in Appendix A of this SER. The staff finds

the applicant's response acceptable and considers RAI 3.5-13 resolved.

In response to RAI B.1.12(e) the applicant stated that the monitoring of the loss of preload for

closure bolting in the reactor vessel, recirculation pumps, reactor recirculation valves, vessel

head vent valves, and the reactor coolant piping will be monitored under the Bolting Integrity

Program. Further, in response to staff's RAI 3.3-9, the applicant also included management of

age-related degradation due to general corrosion on the external surfaces of non-bolting

components such as piping, valves, and mufflers within the Bolting Integrity Program and will

rely on component inspections under preventive maintenance, and routine walk down

inspections. Presence of external surface corrosion will require engineering evaluation. The

applicant asserted that these activities will detect early leakage and material degradation of

closure bolting.

The staff has previously accepted the use of periodic inservice inspections of closure bolting as

an acceptable aging management program for loss of mechanical closure integrity since failure

of the mechanical joint, as evidenced by leakage, can be attributed to, loss of material, cracking

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of bolting materials, and loss of preload. The staff determined that periodic ASME Section XI

inservice inspections and plant preventative maintenance programs can be effectively relied

upon to identify loss of closure integrity for bolted assemblies. Therefore, the applicant's

management of loss of mechanical closure integrity is adequate for managing the aging effects

of loss of material, cracking, and loss of preload.

3.0.3.5.3 Conclusions

On the basis of its review and audit of the applicants program, the staff finds that those portions

of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. In addition, the staff has reviewed the exceptions to the

GALL program and finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

during the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also

reviewed the UFSAR supplement for this AMP and finds that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

3.0.3.6 Open-Cycle Cooling Water System (B. 1.13)

3.0.3.6.1 Summary of Technical Information in the Application

The applicant's open-cycle cooling water system program is discussed in LRA Section B.1.13,

"Open-Cycle Cooling Water Program." The applicant states that, with enhancements, the

program is consistent with GALL program XL.M20, "Open-Cycle Cooling Water Program" with

exceptions. The following enhancements and exceptions are identified in the LRA.

Enhancements

The program will provide for inspection of cooling water pump internal lining, additional heat

exchangers and sub-components, inspection of external surfaces of various submerged pumps

and piping.

The program will provide for new periodic component inspections in the pump vaults that have a

high humidity/moisture environment.

Exceptions to NUREG-1801

NUREG-1801 indicates that program testing and inspections are performed annually and during

refueling outages. The Dresden/Quad Cities open-cycle cooling water system aging management

program activities provide for adjustment of inspection intervals due to specific inspection results

as stated in the response to GL 89-13.

In LRA Section B.1.13 and UFSAR supplement A.1.13, the applicant describes the Open-Cycle

Cooling Water System program as an existing aging management program that manages loss

of material, cracking, buildup of deposits and flow blockage aging effects in cooling water

systems that are tested and inspected in accordance with the guidelines of Generic Letter (GL)

89-13, "Service Water System Problems Affecting Safety-Related Equipment," issued August 8,

1988. More specifically, the Open-Cycle Cooling Water System program is credited with

managing the following aging effects during the period of extended operation:

l loss of material due to general, pitting, crevice corrosion, galvanic, erosion, wear, selective

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leaching and microbiologically influenced corrosion (MIC)

* cracking due to stress corrosion cracking and mechanical fatigue

* buildup of depositlfouling/flow blockage due to biofouling and silting.

This AMP is credited with managing the ESF, Auxiliary, and Steam and Power Conversion

systems.

The applicant states that the operating experience of the Dresden/Quad Cities Nuclear Stations

has shown that its open-cycle cooling water system aging management activities have detected

aging degradation and implemented appropriate corrective actions to maintain system and

component intended function. The applicant also states that the program consists of system

test procedures, inservice testing, periodic component inspections, piping nondestructive

examinations, station maintenance inspections, component preventive maintenance testing,

inservice inspections, and inspections for the Class 3 portions of raw water system. The LRA

credits system and component tests, visual inspections, NDE, flushing and chemical treatment

to ensure that aging effects are managed such that system and component functions are

maintained. The applicant also identifies that inservice inspections of the Class 3 portions of

the raw water systems are also conducted to provide periodic leakage detection of the

aboveground and buried piping, but external surfaces of buried components are managed by

AMP B.1.25.

In Section B.1.13 of the LRA, the applicant concluded that the open-cycle cooling water

program provides reasonable assurance that the aging effects are adequately managed so that

the intended functions of open-cycle cooling water components within scope of license renewal

are maintained during the period of the extended operation.

3.0.3.6.2 Staff Evaluation

In LRA Section B.1.13, "Open-Cycle Cooling Water System," the applicant described its AMP to

manage aging on raw cooling water system piping and components. The LRA stated that with

enhancements this AMP is consistent with GALL AMPs XI.M20, "Open-Cycle Cooling Water

System" with an exception. The staff confirmed the applicant's claim of consistency during the

AMR inspection. The staff reviewed the UFSAR supplement to determine whether it provides

an adequate description of the revised program. The staff also reviewed the exceptionr and its

justification to determine whether the AMP, with the exception, remains adequate to manage

the aging effects for which it is credited. Finally, the staff determined whether the applicant

properly applied the GALL program to its facility.

In the description of the AMP B.1.13, the applicant includes an exception to NUREG-1801

concerning the adjustment of inspection intervals due to specific inspection results as stated in

the response to GL 89-13. By letter dated August 4, 2003, the staff requested, in RAI B.1.13

(a), the applicant to clarify if these adjustments are in accordance with the information provided

in GL 89-13 concerning a routine inspection and maintenance program and section D,

"frequency of testing and maintenance," in GL 89-13, Supplement 1.

In its response dated October 3, 2003, the applicant stated that the adjustments to the

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inspection intervals for the Dresden and Quad Cities open-cycle cooling water system aging

management program activities are in accordance with the information provided in GL 89-13

concerning routine inspection and maintenance programs and section D, "frequency of testing

and maintenance", in GL 89-13, Supplement 1. The applicant clarified that one representative

heat exchanger for each heat exchanger type with similar operating conditions would be

tested/inspected as required by Supplement 1 of GL 89-13 to establish the appropriate test

frequency for that type of heat exchanger.

On the basis of its review, the staff finds the applicant's response to RAI B.1.13 (a) adequate

and acceptable because the applicant has demonstrated that the test frequency would be

tested/inspected as required by Supplement 1 of GL 89-13. Therefore, this issue is resolved.

In the description of AMP B.1.13, the applicant lists its first enhancement to NUREG-1801 as

"The program will provide for inspection of cooling water pump internal linings, additional heat

exchangers and sub-components, inspection of external surfaces of various submerged pumps

and piping." By letter dated August 4,2003, the staff requested, in RAI B.1.13 (b), the

applicant to identify the specific additional heat exchangers and sub-components that will be

inspected, the inspection frequency, and the technical basis, including operating experience, for

the inspection frequency.

In its response dated October 3, 2003, the applicant stated that additional inspection

requirements were added for the heat exchanger as shown in the table below. The applicant

identified that the frequencies of these inspections are based on reviews of industry, company,

and vendor operating experience. The applicant clarified that station and corporate procedures

and policies contain provisions for adjustment of inspection frequencies based on periodic

reviews of operating experience, inspection results, and vendor recommendations.

Heat Exchanger EPN(s) Frequency

Dresden TBCCW Heat Exchanger 2(3)-3802-A(B) 6-year

(tube side only)

Dresden RBCCW Heat Exchanger 2/3-3702. 2(38-3702-A(B) 3-Vear

In addition, the applicant identified that new inspection requirements delineated specific subcomponents to be inspected for the affected heat exchanger. The specific sub-components

include:

* Inlet/outlet end bells, divider plates, joint welds as applicable

* Inlet/outlet tube sheets, divider plates, joint welds as applicable

* Inlet side tubes

* Outlet side tubes

* Inlet/outlet piping

* Anodes

* Supports (particularly tube/support joint and support/shell joint areas)

* Shell/fins as applicable

* Inlet/outlet nozzles, primary and secondary process sides as applicable.

On the basis of its review, the staff finds that the applicant's response to RAI B.1.13 (b)

adequate and acceptable because; (1) the applicant used a combination of periodic reviews of

operating experience, inspection results, and vendor recommendations, and (2) the applicant

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clearly identified the components that are to be inspected and tested, and these identified

components are the most susceptible locations for the identified aging effects.

In the description of AMP 1.1.13, the applicant identified an enhancement regarding new

periodic component inspections in the pump vaults that have a high humidity/moisture

environment. By letter dated August 4, 2003, the staff requested, in RAI B.1.13 (c), the

applicant to specify the inspection frequency and its technical basis, including operating

experience.

In its response dated October 3, 2003, the applicant stated that the frequency for the new

periodic component inspections in the pump vaults is once per year and the frequency of these

inspections is based on input provided by cognizant system/program engineers. Less intensive

inspections of the affected areas are conducted on a more frequent basis as part of operator

rounds, maintenance activities, and routine walkdowns; surface degradation, leakage or other

adverse conditions would be noted as part of these inspections.

On the basis of its review, the staff finds the applicant's response to RAI B.1.13 (c) adequate

and acceptable because the combination of the applicant's annual intensive inspection and less

intensive inspections of the affected areas conducted on a more frequent basis as part of

operator rounds, maintenance activities, and routine walkdowns will provide that the aging

effects on the applicable components will be detected and managed.

In the description of the AMP B.1.13, the applicant states: "the open-cycle cooling water system

aging management activities have detected aging degradation and implemented appropriate

corrective actions to maintain system and component intended functions..." This operating

experience suggests that the preventive actions prescribed in this AMP may not be as effective

as expected. By letter dated August 4, 2003, the staff requested, in RAI B.1.13 (d), the

applicant to provide justifications on the effectiveness of the preventive actions based on the

plant operating experience, with consideration of Information Notice 94-03.

In its response dated October 3, 2003, the applicant addressed their program effectiveness

relative to Information Notice 94-03 regarding deficiencies identified by the NRC during service

water system operational performance inspections to assess licensee actions in response to GL

89-13. The applicant stated that testing and procedures governing service water system and

performance at Dresden Station and Quad Cities Station are part of the station GL 89-13

program and that periodic GL 89-13 system performance tests and component visual

inspections provide for timely detection of loss of material and flow blockage. The periodicity of

the testing and inspections is based on previous findings and are adjusted accordingly. NDE

tests consist of eddy current testing (for heat exchanger) and piping UTs and/or RTs to detect

loss of material aging effects. Available flow to the heat exchangers and coolers is used to

determine the extent of blockage (fouling) in the system. The station GL 89-13 program

procedures outline the requirements to ensure that the testing and inspection activities have.

been performed and the results have been documented and sent to the appropriate station

personnel for trending and analysis. The piping and components that are periodically inspected

form a representative sampling for evaluating potential system-wide aging degradation. In

addition, the applicant further stated that IST procedures provide for the periodic monitoring and

trending of system performance per the notification of the appropriate system engineer of test

results and notification of both the system engineer and unit supervisor of any inspection

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deficiencies. The response identified that documentation results are maintained in accordance

with ASME Section Xl, IWP-6000 and ISI documentation facilitates comparison with previous

and subsequent inspection results are also maintained in accordance with ASME Section Xl,

IWA-6000.

On the basis of its review, the staff finds that the applicant's response to RAI B.1.13 (d)

adequate and acceptable because the applicant has provided that the preventive actions

prescribed in the AMP are effective.

In the operating experience section of AMP B.1.13, the applicant stated that "Engineering

evaluations have resulted in various specific component and programmatic enhancements and

correction actions. In addition, program assessments have been reviewed for heat sink

performance." By letter dated August 4, 2003, the staff requested, in RAI B.1.13 (e), the

applicant to describe the appropriate corrective actions made and the operating experience

since these corrective actions were implemented and provide the results on the assessment for

the heat sink performance review in regard to the adequacy of this AMP.

In its response dated October 3, 2003, the applicant described the appropriate corrective

actions made:

* implementing procedure revisions for more frequent pump bay cleaning to reduce silt and

clam buildup

* revising the ISI boundary to include additional piping for periodic inspection

* monitoring minor Zebra Mussel infestations to prevent flow restriction

* implementing new inspections to periodically inspect components found to be susceptible to

blockage (Y-strainers and keep-fill check valves)

* repairing or replacing specific piping and component minimum wall conditions and pinhole

leaks (follow-up root cause evaluations were performed)

* implementing closer monitoring of marginal conditions (flow rates and piping wall thickness)

to confirm continued system and component operability

* implementing additional flushing for lines determined to be susceptible to blockage.

In its response dated October 3, 2003, the applicant further stated that prior to the

implementation of the station GL 89-13 program activities, component blockage was a recurring

problem resulting in valves being unable to function and flow restrictions in the heat exchanger.

More recent periodic system flushing and component inspections and cleaning have detected

minor levels of biofouling and silting, primarily in system drain lines that were removed without

any loss of system function.

In addition, the applicant stated: "Self-assessments of heat sink performance were performed

for Dresden and Quad Cities in January 2001 and February 2001, respectively, to identify site

heat exchanger deficiencies and verify resolution of previously identified heat sink performance

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issues. These self-assessments were reviewed in preparation of the LRA. The selfassessments were noted as identifying the following in support of the adequacy of the opencycle cooling water system AMP:

* adequately identified areas for improved inspection/testing and/or component

replacement/refurbishment to ensure adequate heat exchanger performance

* provided assurance that consideration was given to inclusion of risk significant heat

exchanger, not just safety-related heat exchanger

* adequately identified deficiencies and initiated appropriate corrective actions

* provided on-going review of heat exchanger testing, maintenance, and performance

documentation activities for incorporation of recent industry, regulatory, or vendor guidance.

The applicant concluded that the above information provides evidence that the GL 89-13

program and self-assessments have been effective at managing associated aging effects.

On the basis of its review, the staff finds the applicant's response to RAI B.1.13 (e) adequate

and acceptable because the applicant has provided a verification that the corrective actions

prescribed in the AMP are effective.

In AMP B.1.13, the applicant stated: "The open-cycle cooling water AMP... provides for

managing loss of material aging degradation on the outside surfaces... by condition monitoring

of the accessible external surfaces of components in moist air (indoor) or submerged (raw

water) environments." However, this AMP does not address managing the loss of material on

inaccessible outside surfaces. By letter dated August 4, 2003, the staff requested, in RAI

B.1.13 (f), the applicant to provide an explanation of how the loss of material aging effects on

the outside surfaces in inaccessible locations is managed for the period of extended operation.

The staff asked the applicant to indicate to what extent it used eddy current testing.

In its response dated October 3, 2003, the applicant stated that management of the loss of

material is not provided for all outside surfaces of inaccessible locations. The piping and

components that are periodically inspected form a representative sampling for evaluating

potential system-wide aging degradation. The applicant identified that eddy current testing is

used for heat exchanger tubes, but not necessarily for all piping and components with

inaccessible outside surfaces.

On the basis of its review, the staff finds the applicant's response to RAI B.1.13 (f) adequate

and acceptable because the applicant used the results of piping and components that are

periodically inspected to form a representative sampling for evaluating potential system-wide

aging degradation.

LRA Table 3.3-2 credits the Open-Cycle Cooling Water System (AMP B.1.13) with managing

galvanic corrosion. By letter dated August 4, 2003, the staff requested, in RAI B.1.13 (g), the

applicant to; (1) identify any preventive measures used to minimize the effects of galvanic

corrosion in heat exchangers such as sacrificial anodes or internal coatings and indicate if

inspections verify that they are performing their intended function, and (2) clarify whether the

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inspection and testing described in the AMP Open-Cycle Cooling Water System' (B.1.13) are

targeted or opportunistic with respect to managing loss of material due to galvanic corrosion.

In its response dated October 3, 2003, the applicant stated that no credited preventive

measures used to minimize the effects of galvanic corrosion in affected heat exchangers and

the the aging effects of galvanic corrosion are managed through periodic inspections of inscope components as appropriate.

On the basis of its review, the staff finds the applicant's response to RAI B.1.13 (g) adequate

and acceptable because the applicant has stated that, although there are no credited

preventive measures to minimize galvanic corrosion, galvanic corrosion will be managed by

periodic heat exchanger inspections.

The staff reviewed the UFSAR supplement in LRA Appendix A.1.13 and found that the

description of the Open-Cycle Cooling Water System is consistent with Section B.1.13 of the

LRA.

3.0.3.6.3 Conclusions

On the basis of its review and audit of the applicants program, the staff finds that those portions

of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. In addition, the staff has reviewed the exceptions to the

GALL program and finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

during the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and finds that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.0.3.7 Closed-Cycle Cooling Water System (B. 1.14)

3.0.3.7.1 Summary of Technical Information in the Application

The applicant's closed-cycle cooling water system aging management program is discussed in

LRA Section B.1.14, "Closed-Cycle Cooling Water Program." The applicant states that with

enhancements the program is consistent with GALL program XI.M21, "Closed-Cycle Cooling

Water Program." Enhancements consist of procedure revisions to provide for monitoring of

specific parameters in accordance with EPRI TR-107396 guidance and to provide for

monitoring pH and ammonia in the Dresden diesel generator jacket water. In LRA Section

B.1.14 and UFSAR supplement A.1.14, the applicant describes the Closed-Cycle Cooling

Water System program as an existing aging management program that manages loss of

material, cracking and buildup of deposit through the use of preventive measures to minimize

corrosion by maintaining inhibitors and by performing non-chemistry monitoring consisting of

inspection and NDE based on industry-recognized guidelines of EPRI-TR-107396. More

specifically, the Closed-Cycle Cooling Water System is credited with managing the following

aging effects during the period of extended operation:

* loss of material due to general, pitting, crevice corrosion, erosion, wear and MIC

* cracking due to stress corrosion cracking and mechanical fatigue

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* buildup of deposit/fouling

In the LRA Operating Experience Section, the applicant stated that its closed-cycle cooling

water system aging management activities have detected aging degradation in heat

exchangers prior to loss of system intended functions. The applicant further states that

engineering evaluations have resulted in various specific component and programmatic

corrective actions. The applicant also stated that performance monitoring provides indications

of degradation in closed-cycle cooling water systems, with plant operating conditions providing

indications of degradation in normally operating systems. Station maintenance inspections and

NDE provide condition monitoring of heat exchangers exposed to closed-cycle cooling water

environments.

This AMP is credited with managing the ESF, Auxiliary, and Steam and Power Conversion

systems.

In Section B.1.14 of the LRA, the applicant concludes that the closed-cycle cooling water aging

management program provides reasonable assurance that the aging effects are adequately

managed so that the intended functions of components exposed to closed-cycle cooling water

environments within scope of license renewal are maintained during the period of extended

operation.

3.0.3.7.2 Staff Evaluation

In LRA Section B.1.14, "Closed-Cycle Cooling Water System," the applicant described its AMP

to manage aging on components exposed to closed-cycle cooling water environments. The

LRA states that with enhancements this AMP is consistent with GALL AMP XI.M21, uClosedCycle Cooling Water System." The staff confirmed the applicant's claim of consistency during

the AMR inspection. The staff reviewed the UFSAR supplement to determine whether it

provides an adequate description of the revised program. The staff also reviewed the program

enhancements and its justification to determine whether the AMP, with the enhancements,

remains adequate to manage the aging effects for which it is credited. The program

enhancements will be implemented prior to the period of extended operation. This is

Commitment #14 of Appendix A in this SER. Finally, the staff determined whether the applicant

properly applied the GALL program to its facility.

During its review, the staff determined that it needed additional information to complete its

evaluation. In LRA AMP Bl.14, the applicant stated that closed-cycle cooling water system

activities have detected aging degradation, and engineering evaluations have resulted in

various specific component and programmatic corrective actions. This operating experience

suggests that the preventive actions prescribed in this AMP may not be as effective as

expected. Furthermore, in the operating experience section, the AMP states, "engineering

evaluations have resulted in various specific component and programmatic corrective actions."

By letter dated August 4, 2003, the staff requested, in RAI B.1.14 (a), the applicant to describe

the appropriate corrective actions made, and the operating experience since these corrective

actions were implemented.

In its response dated October 3, 2003 to RAI B.1.14 (a), the applicant stated that the preventive

activities relied on by the closed-cycle cooling water system activities program include

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measures to maintain water purity and the addition of corrosion Inhibitors to minimize corrosion.

The activities will not by themselves eliminate corrosion altogether. The preventive activities of

the program are only a part of a comprehensive program, which also includes periodic heat

exchanger functional testing and monitoring of system parameters (i.e., flows, temperatures,

pressures). The applicant further stated that the program activities, in total,'will provide an

effective means for management of the aging effects of the in-scope closed-cycle cooling water

heat exchangers. The applicant provided specific examples of the program corrective actions

made as a result of aging degradation and stated that no operating experience involving

recurrence of heat exchanger degradations similar to those identified has been identified since

implementation of the associated corrective actions.

On the basis of its review, the staff finds that the applicant's response to RAI B13.14(a)

acceptable because(1) the applicant has shown that the preventive activities of the program are

only a part of a comprehensive program, which also includes periodic heat exchanger functional

testing and monitoring of system parameters (i.e., flows, temperatures, pressures), and that the

program activities, in total, will provide an effective means for management of the aging effects

of the in-scope closed-cycle cooling water heat exchangers, and (2) the applicant has further

specified several explicit examples of the program corrective actions made.

LRA Table 3.3-2 credits the Closed-Cycle Cooling Water System Program (B.1.14) for

managing galvanic corrosion for certain components. By letter dated August 4, 2003, the staff

requested, in RAI B.1.14 (b), the applicant to identify any preventive measures used to

minimize the effects of galvanic corrosion in heat exchangers such as sacrificial anodes or

internal coatings and to indicate if inspections verify that preventive measures are performing

their intended function.

In its response dated October 3, 2003 to RAI B.1.14 (b), the applicant stated that some of the

heat exchangers monitored in the closed cooling water aging management program contain

sacrificial anodes, however, the applicant clarified that this preventive measure has not been

credited to minimize the effects of galvanic corrosion in affected heat exchangers.

On the basis of its review, the staff finds the applicant's response to part (b) of RAI Bi1.14

acceptable because the applicant has clarified that, although some of the heat exchangers

monitored in the closed cooling water aging management program contain sacrificial anodes,

this preventive measure has not been credited to minimize the effects of galvanic corrosion in

affected heat exchangers. Therefore, chemistry control, inspections, and performance

monitoring are used to mitigate and detect galvanic corrosion.

The applicant's UFSAR supplement for the Closed-Cycle Cooling Water System is documented

in Section A.1 .14 of Appendix A to the LRA and provides an overview of the program as

described in Section B.1.14 of Appendix B to the LRA. The staff finds that the information

provided in the UFSAR supplement is consistent with that in the AMP.

3.0.3.7.3 Conclusions

On the basis of its review and audit of the applicant's program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, the

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applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

3.0.3.8 Compressed Air Monitoring (B.1.16)

3.0.3.8.1 Summary of Technical Information in the Application

The applicant's compressed air monitoring aging management program is discussed in LRA

Section B.1.16 "Compressed Air Monitoring". The applicant states that with enhancements, the

program is consistent with the ten elements of aging management program XI.M24,

"Compressed Air Monitoring" specified in the GALL report, with exceptions. The following

enhancements and exceptions are identified in the LRA:

Enhancements

* The program will provide for new periodic inspections for those portions of instrument air

distribution piping at Dresden and Quad Cities that are within the scope of the rule.

* The program will provide for periodic blowdowns of instrument air receiver tanks located upstream of

the instrument air dryers at Dresden.

Exceptions to NUREG-1801

* NUREG-1801 indicates that the program is based on responses to GL 88-14 and INPO

SOER 88-01, 'Instrument Air System Failures," as well as EPRI NP-7079-1990, EPRI TR108147, Compressor and Instrument Air System Maintenance Guide," ASME OM-S/G-1998,

and ANSIAISA-S7.0.01-1996. The Dresden and Quad Cities programs are based on the

guidance provided in the GL 88-14 and ANSI/ISA-S7.3-1975 documents, which are part of

the current licensing basis. Enhancements include inspection of instrument air distribution

piping based on EPRI TR-108147.

* NUREG-1 801 indicates that inservice inspection 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. Inservice

inspections at Dresden and Quad Cities do not verify air quality because air quality testing

is performed in accordance with specific procedures based on ANSI/ISA-S7.3-1975.

Maintenance practices, emergency procedures, and training are plant performance issues

that are not directly related to aging management of the instrument air. Aging management consists of air quality tests and pressure decay tests of MSIV and safety/relief valve

pneumatic system including accumulators, piping, and check valves, and periodic inspections to verify the integrity of the systems.

The compressed air monitoring aging management program activities manage loss of material

due to general, crevice, and pitting corrosion for portions of the instrument air system within the

scope of license renewal. Program activities consist of air quality testing, pressure decay

testing, and visual inspections at various system locations.

In supplemental response to RAI B.1.16-1 dated June 22, 2004, the applicant provided the

following additional operating experience:

Dresden has experienced corrosion, corrosion product buildup, and dirt buildup in instrument air system

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receiver tanks and dryers leading to a receiver tank connection failure in 1994. The program enhancement

of crediting periodic blowdowns of instrument air receiver tanks addresses this condition. No similar failure

has occurred at Dresden since the receiver tank blowdowns were implemented. Dresden and Quad Cities

have not experienced a failure of a pneumatically operated components within the scope of license renewal

due to aging effects in the instrument air system since implementation of actions in response to GL 88-14.

The LRA states that Dresden and Quad Cities have experienced equipment failures including

MSIVs, dampers, and process valves due to instrument air leaks. These failures were to

individual components and did not propagate to other components within the system. Dresden

and Quad Cities have not experienced a common mode failure caused by the instrument air

system. The Dresden'and Quad Cities enhancements of performing predefined tasks that

require periodic inspections of instrument air distribution piping address this condition.

This AMP is credited with managing the RCS, ESF, Auxiliary, and Steam and Power

Conversion systems.

The applicant concludes that with the exceptions and enhancements, the Compressed Air

Monitoring aging management program provides reasonable assurance that loss of material

aging effects are adequately managed so that the intended functions of the in'strument air

components within the scope of license renewal are maintained during the period of extended

operation.

3.0.3.8.2 Staff Evaluation

In LRA Section B.1.16, "Compressed Air Monitoring," the applicant described its AMP to

manage loss of material due to general, crevice, and pitting corrosion for portions of the

instrument air system within the scope of license renewal. The LRA stated that this AMP is

consistent with GALL AMP XI.M24, "Compressed Air Monitoring," with exceptions and

enhancements as noted above. The staff confirmed the applicant's claim of consistency during

the AMR inspection. Furthermore, the staff reviewed the exceptions and their justifications to

determine whether the AMP, with the exceptions, remains adequate to manage the aging

effects for which it is credited. The staff also reviewed the UFSAR supplement to determine

whether it provides an adequate description of the revised program. The staff also reviewed

the applicant's evaluation to determine whether it addressed the additional issues

recommended in the GALL report and confirm that the AMP would adequately address these

issues. Finally, the staff determined whether the applicant properly applied the GALL program

to its facility.

The staff noted that maintenance practices, emergency procedures,-and training are not aging

management issues and the applicant's exception to this is acceptable.

The staff noted that the applicant's Compressed Air Monitoring program as described in the

LRA, is not based on all of the references (IN 81-38, IN 87-28, IN 87-28S1, INPO SOER 88-01,

EPRI-1 08147, ASME OM-S/G-1 998, Part 17, American National Standards Institute

(ANSI)/lnstrument Society of America (ISA)-S7.0.01-1996, and EPRI 7079 identified in the

GALL report AMP XL.M24. In RAI B.1.16a dated August 4, 2003, the staff requested the

applicant explain why these references were not included in the development of the applicant's

program. In the response dated October 3, 2003 and supplemental response dated December

12, 2003, the applicant stated the following:

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The Dresden and Quad Cities programs are based on GL 88-14 and ANSI/ISA-S7.3-1975 and are

enhanced with inspection based on EPRI TR-108147. NUREG-1801 XI.M24 (Compressed Air Monitoring)

states that GL 88-14 is augmented by References IN 81-38, IN 87-28, IN 87-28S1 and INPO SOER 88-01.

The sentence in the exception section of LRA Appendix B, Section B.1.16, that currently reads:

The Dresden and Quad Cities programs are based on the guidance provided inthe GL88-14

and ANSI/ISA-S7.3-1975 documents, which are part of the current licensing basis.

should have read:

The Dresden and Quad Cities programs are based on the guidance provided in ANSI/ISAS7.3-1975andGL 88-14which is augmented byprevious NRC Information Notices IN 81-38,

IN 87-28, IN 87-28 SI, and by the Institute of Nuclear Power Operations Significant

Operating Experience Report (INPO SOER) 88-01.

In response to GL 88-14, Exelon committed to implementing an instrument air quality-monitoring program

using ANSI/ISA-S7.3-1975. ANIS/ISA-S7.0.01-1996 is a newer revision to ANSI/ISA-S7.3-1975 that is less

conservative then ANSI/1SA-S7.3-1975. Exelon has a licensing commitment contained in the response to

GL88-14 that uses ANSI/ISA-S7.3-1975. The following is a comparison of ANIS/ISA-S7.0.01-1996 to

ANSI/ISA-S7.3-1975:

Parameter ANSVISA-S7.0.01 -1996 ANSIISA-S7.3-1975

Dewpoint 180

1F below the minimum 180F below the minimum temperature

temperature of any part of the air of any part of the air system. The

system. The dewpoint shall not dewpoint shall not exceed 350F at line

exceed 390F at line pressure. pressure.

Particle Size 40 microns maximum. 3 microns maximum. (Test

procedures allow up to 4 particles/ft3

to exceed the 3 micron size limit)

Hydrocarbons (lubricant As close to zero as possible, not As close to zero (0) w/w or v/v as

content) to exceed 1 ppm w/w or v/v. possible, not to exceed 1 ppm w/w or

v/v under normal operating conditions.

EPRI TR-108147 is a new revision to EPRI NP-7079. Exelon has enhanced the Dresden and Quad Cities

programs to include inspection of instrument air distribution piping based on ERPI TR-1 08147.

The scope of components included in the compressed air monitoring aging management activities includes

distribution piping, valves, and accumulators for air operated safety-related valves, and the containment

isolation valves of the instrument air system. The instrument air system compressors, receivers, filters, and

dryers are not within the scope of license renewal. Exelon takes exception to ASME OM-S/G-1998, Part 17

as specified in NUREG-1801 XI.M24. ASME OM-S/G-1 998, Part 17 provides guidance concerning the

performance testing of instrument air systems in light-water reactor power plants. Because the instrument

air system compressors, receivers, filters, and dryers are not within the scope of license renewal, the

instrument air systems do not require performance testing for aging management. Exelon aging

management program B.1.16 (Compressed Air Monitoring) provides adequate aging management for the

select number of instrument air system components that have been included within the scope of license

renewal.

The staff finds that the applicant's program adequately addresses the reference documents

contained in the GALL program and is acceptable based on the additional information provided.

In RAI BA.1.16b, the staff noted that it is not readily apparent how the Compressed Air

Monitoring program will adequately manage the aging effect of loss of material due to

corrosion, corrosion product build-up, or dirt build-up for brass or bronze valve components in

the control rod drive hydraulic system. The applicant's response dated October 3, 2003 stated

that occurrences of corrosion have not been noted in brass or bronze valve components in the

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control rod drive hydraulic system. Furthermore, RAI B.1.16-1 supplemental response dated

June 22, 2004 stated that Dresden has experienced corrosion, corrosion product buildup, and

dirt buildup only in the instrument air system receiver tanks and dryers leading to a receiver

tank connection failure in 1994. The program enhancement of crediting periodic blowdowns of

instrument air receiver tanks addresses this condition. No similar failure has occurred at

Dresden since the receiver tank blowdowns were implemented.

3.0.3.8.3 Conclusions

On the basis of its review and audit of the applicants program, the staff finds that those portions

of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. In addition, the staff has reviewed the exceptions to the

GALL program and finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

during the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also

reviewed the UFSAR supplement for this AMP and finds that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.0.3.9 Above Ground Carbon Steel Tanks (B. 1.20)

3.0.3.9.1 Summary of Technical Information in the Application

The applicant's above ground carbon steel tanks aging management program is discussed in

LRA Section B.1.20, "Above Ground Carbon Steel Tanks"and provides for management of loss

of material aging effects for outdoor carbon steel nitrogen storage tanks. The applicant states

that the program is consistent with GALL program XL.M29 with the enhancement that the

program provides for initiating documentation of inspection results of periodic system engineer

walkdowns of the nitrogen storage tanks. The LRA contains a commitment that this

enhancement will be implemented at both Dresden and Quad Cities prior to the period of

extended operation. This is part of Commitment #20 in Appendix of A of this SER.

The program provides for the application of paint as a corrosion preventive measure and for

periodic visual inspections to monitor degradation of the paint and any resulting metal

degradation. The LRA notes that the Dresden and Quad Cities outdoor carbon steel storage

tanks have not experienced leakage or degradation due to loss of material. The applicant states

that the nitrogen storage tanks are above ground and are not directly supported by earthen or

concrete foundations. Therefore, inspection of the sealant or caulking at the tank/foundation

interface and inspection of inaccessible tank locations does not apply.

This AMP is credited with managing aging in auxiliary and steam and power conversion

systems.

3.0.3.9.2 Staff Evaluation

In LRA Section B.1.20, "Above Ground Carbon Steel Tanks," the applicant described its AMP to

manage corrosion of above ground carbon steel tanks by protecting the external surfaces with

paint or coatings in according with standard industry practice. The LRA stated this AMP is

consistent with the GALL AMP XL.M29 with the exception that aging of aluminum tanks are

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managed by this AMP as well as carbon steel tanks. The staff confirmed the applicant's claim

of consistency during the AMR inspection. Furthermore, the staff reviewed the deviation and its

justification to determine whether the AMP, with the deviation, remains adequate to manage the

aging effects for which it is credited, and reviewed the UFSAR supplement to determine

whether it provides an adequate description of the revised program. In addition, the staff

determined whether the applicant properly applied the GALL program to its facilities.

The applicant has aluminum above ground storage tanks used as condensate water storage

tanks and demineralized water storage tanks at both the Dresden and Quad Cities sites. The

applicant's LRA specified that the applicable aging management program for the above ground

aluminum water storage tanks would be the Buried Carbon Steel Pipe and Tank Program in

Section B.1.25 of the LRA (GALL Program Xl. M29). In a letter dated August 7, 2003, the staff

requested additional information in RAI B.1.25 regarding the applicability of the Buried Carbon

Steel Pipe and Tank Program B.1.25 (GALL Program Xl. M29) for managing aging of above

ground Aluminum Storage Tanks. The staff also requested that the applicant describe the

inspection criteria, potential corrective actions if acceptance criteria are not met and why a one

time UT inspection of a single tank bottom at one site will be representative of all tanks.

In a letter dated October 3, 2003, the applicant responded to the staff's request for additional

information. The applicant indicated that the proposed Buried Piping and Tank AMP, and

associated aging mechanisms are not relevant to an above ground aluminum tank. The

applicant indicated that the Buried Carbon Steel Pipe and Tank Program B.1.25 (GALL

Program Xl. M29) was inadvertently identified instead of the correct AMP, which is the Above

Ground Carbon Steel Tanks AMP, LRA section B.1.20. The applicant also indicated the LRA

should have included the following changes:

LRA Section B.1.20, Aboveground Carbon Steel Tanks, should have referenced the UT inspection requirement for the associated above ground aluminum tanks. Since the AMP for aboveground carbon steel tanks does not include aluminum as a material type, an exception statement to this effect

should have been included in this section.

LRA Section B.1.25, Buried Piping and Tanks Inspection, should have removed reference to the UT

inspection requirement for the associated above ground aluminum tanks.

Item 3.4.2.42 of LRA Table 3.4-2 should have referenced the aboveground carbon steel tanks AMP.

LRA Section A.1.20 (for Dresden and Quad Cities) should have referenced the UT inspection

requirement for the associated above ground aluminum tanks.

LRA Section A.1.25 (for Dresden and Quad Cities) should have removed the reference to the UT

inspection requirement for the associated above ground aluminum tanks.

In the applicant's response to RAI B.1.25, it also indicated that the tank selected for inspection

would be a Quad Cities tank and would be based on operating experience input from the site.

The applicant indicated that a Quad Cities tank would be selected because the tank bottoms

were older than the Dresden tank bottoms which had been replaced in the 1992/1993 time

frame because of corrosion. The applicant indicated that because the tanks are made of the

same material, constructed in a like manner, and have similar internal and external

environments and because the Quad Cities tank bottoms are older they will more likely show

any aging effects and thus are representative of all the aluminum above ground tanks.

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The staff requested that the applicant provide additional clarifying information related to its RAI

response regarding tank selection. The staff requested that the applicant provide sufficient

information relative to the elements of an aging management program to evaluate the program

exception of aluminum tanks and to provide operating experience relative to the corrosion

mechanism which led to the Dresden tank bottom replacement and what inspections have been

performed at Dresden since tank bottom replacement for assessment of further corrosion. The

applicant in a letter dated November 20, 2003 provided additional clarifying information. The

applicant reiterated that aluminum was considered to be an exception to the Above Ground

Carbon Steel Tank AMP, B.1.20 and provided pertinent information for managing the aging of

the Aluminum Tanks in the form of the elements of an aging management program. The

applicant indicated that there are no protective coatings used in or on the aluminum tanks and a

sealant is used at the interface between the tank and its concrete foundation. The applicant

indicated that the sealant is periodically monitored as part of the Structures Monitoring Program

and that periodic internal/external inspections of the tanks will be in place prior to the period of

extended operation. The applicant indicated aging effects will be detected by the periodic

visual internal/extemal inspection, a UT inspection of one of the Quad Cities tank bottoms and

through the periodic inspection of the foundation sealants. The applicant indicated the periodic

visual examinations will be performed at a five year periodicity rather than every other outage,

that detection of corrosion or degradation of the sealant would require further evaluation and

that the UT inspection results would be compared against tank design criteria. This is part of

Commitment #20 of Appendix A of this SER. The applicant also reiterated that the Dresden

tank bottoms had been replaced due to corrosion and indicated that no inspections of the tank

bottoms at Dresden had occurred since replacement. The applicant further stated that a

requirement for periodic visual inspection of the tank bottoms was in development which would

inspect for corrosion and pitting and if evidence of corrosion or pitting was observed NDE

methods capable of determining wall thickness would be employed.

In a letter dated December 12, 2003, the applicant responded to the staff's request for further

clarification regarding the operating experience associated with corrosion of the Dresden tank

bottoms. The applicant indicated that the corrosion initiated from the aluminum/soil interface

and stated that no inspections of the Dresden tank bottoms had occurred since replacement.

Because the periodic internal visual inspection cannot inspect this surface, the Dresden

operating experience indicates corrosion has led to tank bottom replacement and no

inspections of the Dresden tank bottoms have occurred since replacement the applicant will

incorporate a periodic inspection of one Dresden tank bottom using an NDE method capable of

detecting corrosion and pitting at the aluminum/soil interface into the program. The applicant

indicated the periodicity of the tank bottom inspection was yet to be determined, but would not

exceed a 10 year period. This is part of Commitment #20 of Appendix A of this SER.

The staff finds the applicant's response acceptable because the program is consistent with

GALL, will provide for periodic internal visual inspection of the aluminum tanks, will provide for a

one-time inspection of a Quad Cities aluminum tank bottom using UT and will provide for a

periodic inspection of a Dresden aluminum tank bottom using UT. The staff finds the one-time

inspection of a Quad Cities tank bottom acceptable because operating history has not indicated

that degradation of the Quad Cities aluminum tank bottoms is occurring, and these tank

bottoms have greater accumulated service time .than the tank bottoms replaced at Dresden.

Therefore, one time inspection will focus on the lead component and identify if aging is

occurring. The staff finds the maximum periodicity of 10 years for the UT of the Dresden

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aluminum tank bottoms acceptable because the tanks had been in service over 20 years prior

to the degradation which lead to replacement of the tank bottoms. Therefore, the future

inspections should be appropriate and adequate to manage the aging prior to loss of intended

function.

The applicant indicated that Section A.1.20 of the LRA Appendix A (for each site) will be revised

to reflect the inspections and information provided in the response.

3.0.3.9.3 Conclusions

On the basis of its review and audit of the applicant's program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

3.0.3.10 One Time Inspection (B. 1.23)

3.0.3.10.1 Summary of Technical Information in the Application

The applicant's one-time inspection aging management program (AMP) is discussed in LRA

Section 6.1.23, "One-Time Inspection." The applicant states that the program is consistent with

the ten elements of AMP XI-M32, 'One-Time Inspection," specified in the GALL report. The

One-Time Inspection program provides one-time inspections that manage aging effects of

identified components within the scope of license renewal. The purpose of the program is to

determine if a specified aging effect is occurring. If the aging effect is occurring, the program

provides for an evaluation the effect will have on the ability of affected components to perform

their intended functions for the period of extended operation. The program also provides

appropriate corrective actions if aging effects are found.

Based on the above, the applicant concludes that implementation of the One -Time Inspection

program provides reasonable assurance that the aging effects are adequately managed so that

the intended functions of components within the scope of license renewal that are covered by

this program are maintained during the period of extended operation.

3.0.3.10.2 Technical Evaluation

The applicant's One-Time Inspection program is described in LRA Section B.1.23. The LRA

states that the One-Time Inspection program is consistent with the ten elements of AMP

XI-M32, "One-Time Inspection," specified in the GALL report. No exceptions or enhancements

to the GALL report AMP XL.M32 were identified by the applicant. The staff confirmed the

applicant's claim of consistency during the AMR inspection. The staff determined whether the

applicant properly applied the GALL program to its facilities. The staff also reviewed the

UFSAR supplements for Dresden and Quad Cities to determine whether they provide an

adequate description of the program.

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The GALL report recommends use of the One-Time Inspection program to verify the

effectiveness an aging management program and to confirm the absence of an aging effect.

The 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 a

confirmation that either the aging'effect is not occurring, or the aging effect is occurring very

slowly as not to affect the component or structure intended function. The staff reviewed the

tables in Sections 2 and 3 of the LRA to confirm that the structures and components that credit

the One-Time Inspection program are commensurate with the GALL report. The staff identified

material and environment combinations for components where the One-Time Inspection

program is used in conjunction with an aging management program to confirm the absence of

aging effects or when the aging effect is not expected to occur. The staff considers the

applicant's One-Time Inspection program appropriate to manage these types of aging effects.

However, the staff also identified that one-time inspections are credited for material and

environment combinations where aging could be expected to occur. Where an aging effect is

expected to occur, the GALL report recommends either; (a) an appropriate aging management

program is used to manage the aging effect and a one-time inspection augments the aging

management program to confirm the effectiveness of the program, or (b) the use of periodic

inspections in lieu one-time inspections. By RAls B.1.23-1, B.1.23-2, B.1.23, and B.1.23-2.1

through B.1.23-2.6, the applicant was requested to justify use of the One-Time Inspection

program to manage aging effects for various carbon steel, alloy steel, stainless steel, cast iron,

and neoprene components in environments such as moist air, steam, water (condensate), and

containment atmosphere. By letters dated October 3, 2003, January 26, 2004, and March 25,

2004, the applicant responded to the staff's RAIs as follows:

1) By RAls B.1.23-1, B.1.23-2(a), B.1.23-2.3 and B.1.23-2.4, the staff questioned use of the

One-Time Inspection program to manage loss of material and cracking for carbon steel,

stainless steel, cast iron, brass or bronze, and iron components in lube oil and fuel oil

environments. This was identified as Confirmatory Item B.1.23-1. By letters dated October 3,

2003, January 26, 2004 and April 9,2004, the applicant stated that aging management

program, B.2.5, "Lubricating Oil Monitoring Activities," will be expanded to manage loss of

material and cracking for oil coolers and other components in lube oil, turbine electro-hydraulic

control (EHC) fluid, and generator hydrogen seal oil environments for the emergency diesel

generator system, station blackout diesel generator system, high pressure coolant injection

system, electro-hydraulic control system, reactor core isolation cooling system (Quad Cities),

and generator hydrogen seal oil system (Quad Cities). Aging management program, B.1.23,

"Fuel Oil Chemistry," will be expanded to manage loss of material for components in a fuel oil

environment for the station blackout diesel generator system. The One-Time Inspection

program will not be credited to manage the aging effects for these components since periodic

inspections will be implemented. The staff considers the Lubricating Oil Monitoring Activities

and Fuel Oil Chemistry aging management programs appropriate to manage these aging

effects; therefore,'staff finds this acceptable.'

2) Table 3.3.2 of the LRA identifies components in the Plant Heating System which credit the

One-Time Inspection program to manage aging effects for components in a saturated steam or

condensate environment. By RAls B.1.23-1 and B.1.23-2(a) & (b), staff requested the applicant

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to justify use of one-time inspections to manage the aging effects for these components. By

letters dated January 26, 2004 and March 25, 2004, the applicant stated that Plant Heating

System components in a saturated steam or condensate environment would be managed by

aging management program, B.2.8, "Periodic Inspection of Plant Heating System." The

program includes periodic inspections to manage cracking, loss of material, or leakage of

selected brass/bronze, carbon steel, cast iron, and stainless steel components. The staff

considers the Periodic Inspection of the Plant Heating System program appropriate to manage

these aging effects; therefore, staff finds this acceptable.

3) For the main steam system flexible hoses in a containment nitrogen environment, Reference -

Number 3.4.2.18 of the LRA does not identify any aging effects for these neoprene hoses. By

RAls 3.4.1-3 and B.1.23-2.1, the staff requested the applicant to justify with respect to

temperature, radiation levels, and time, why neoprene hoses do not require aging management.

In responses dated October 3, 2003 and January 26, 2004, further review by the applicant

indicated that hoses in Reference Number 3.4.2.18 and 3.4.2.19 of the LRA are not comprised

of an elastomer material as earlier reported but are made of stainless steel with an overall

stainless steel outer braided jacket. Based on the hose material being stainless steel, the

applicant will use the One-Time Inspection program to verify that the hoses are constructed of

metal rather than an elastomer material. Any hoses found to be constructed of an elastomer

during the one-time inspection will be replaced with metal flexible hoses. The One-Time

Inspection program will perform inspections of the installed metal hoses for mechanical

damage. This applies to Quad Cities only. The applicant has noted that stainless steel hoses

are installed at Dresden. The staff considers use of the One-Time Inspection program

acceptable to verify that stainless steel hoses are installed and to inspect the stainless steel

hoses for damage.

4) For non-safety-related (NSR) vents or drains, piping, and valves in various systems, the LRA

identifies loss of material due to corrosion for carbon steel, stainless steel, brass, or bronze in

an environment of air, moisture, humidity, and leaking fluid. By RAI 3.3-2, the staff requested

the applicant to describe the types of corrosion expected and to provide criteria for selecting

one-time sample locations for these types of corrosion. The applicant stated in its letter dated

October 3, 2003 that general, crevice, and pitting corrosion are expected in these components.

The applicant compiled a list of the in-scope NSR vents and drains for the various systems

throughout the plants. The One-Time Inspection program will inspect a selected number of

NSR vent and drains for the affected systems. The sample population will be representative of

all material and environment combinations but may not include components for every system.

The criteria used for selection of susceptible inspection locations are as follows: 1)

Corrosiveness of fluid passing through the vent, drain, or piping when in service. Those

components servicing more corrosive fluids are given preference. 2) Duration of service when

performing venting and draining operations. Those components with higher durations of

service are given preference. 3) Frequency of performance of venting and draining operations

through the selected components. Those components with higher performance frequencies are

given preference. 4) Period that component has been in service. Those components that have

been in service longest are given preference. By RAls B.1.23-2(b) and B.1.23-2.2, staff

requested further justification that a one-time inspection is adequate to manage the aging

effects for these vent, drains, and valves. By letters dated October 3, 2003 and January 26,

2004, the applicant stated that the NSR vents, drains, valves, and piping are normally outboard

of closed safety relief valves or closed isolation valves and are not likely to contain moisture.

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Any appreciable leakage or condensation inside these vents and drains would be identified in

the course of periodic operations or through the daily monitoring of unidentified inputs to

radwaste by the operating department. Malfunctioning isolation valves or other degraded

conditions are promptly repaired, replaced, or corrected. For the reasons stated above, the

applicant considers the rate of material loss due to corrosion to be slow; therefore, one-time

inspections will confirm the assumption that loss of material due to corrosion is occurring at a

sufficiently slow rate for the subject components. In the event that the results of the one-time

inspections fail to provide this confirmation, evaluations will be performed in accordance with

the site corrective action process to identify actions, including possible periodic inspections of

the vents and drains. Based on the applicant's response, staff concurs that the loss of material

due to corrosion for the subject vents, drains, piping, and valves are considered to occur at a

sufficiently slow rate such that a one-time inspection is adequate to manage this aging effect;

therefore, staff finds this acceptable.

5) By RAIs B.1.23-2 and B.1.23-2.6, the staff requested the applicant to provide justification for

using one-time inspections to manage carbon steel, cast iron, alloy steel, elastomer, and -

neoprene components in a moist air environment that 1) varies with normal plant conditions, 2)

is impractical to monitor or control routinely, 'and 3) is similar to the environments associated

with the Aging Management References listed in part b of RAI B.1.23-2. This was identified as

Open Item B.1.23-2. By letter dated March 25, 2004, the applicant concluded by further review

that periodic inspections of components in this population would be appropriate. A new aging

management program, B.2.9, "Periodic Inspection of Components Subject to Moist Air

Environments," was developed for these components. Specifically, the applicant will perform

periodic inspections of a representative sample of stainless steel, carbon steel, cast iron,

aluminum, copper, brass, and bronze components normally exposed to environments of air and

steam; moist air; saturated air; warm moist air; moist containment atmosphere; steam or

demineralized water; and hot diesel engine exhaust gases containing moisture and particulates.

In addition, the program inspects flexible hoses to detect age-related degradation prior to the

loss of function.

The applicant considers a one-time inspection appropriate for managing aging effects for the

standby gas treatment system and HVAC systems components with an internal environment of

"occasional exposure to moist air" and an external environment of "ambient plant air" or "warm

moist air." Components in these systems include doors, closure bolts, equipment frames,

piping, fittings, valves, ducts, and filters fabricated of cast iron, carbon steel,-brass, bronze,

stainless steel, and copper. Based on the materials and environments for these ventilation

system components, the applicant believes that 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. Based on favorable operating history that revealed no widespread

corrosion in the affected system, a limited number of components were selected as

representative of the ventilation systems. The worst-case one-time inspection locations will

include the following: the air intake ductwork of the standby gas treatment system; main control

room HVAC ductwork; emergency diesel generator HVAC air intake ductwork; reactor building

HVAC ductwork downstream of the steam coils and chilled water cooling coils; and main control

room HVAC drip pan and drainpipe. If the one-time inspection detects corrosion resulting in

material loss, results of the examination will be evaluated by engineering to determine the rate

of material loss and the need for additional inspections. Unacceptable results will be

documented in the corrective action program.

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Based on the applicant's response, staff considers the Periodic Inspection of Components

Subject to Moist Air Environments acceptable to manage components in a moist air

environment and the One-Time Inspection program acceptable to manage ventilation systems

components 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.

Therefore Open Item B.1.23-2 and Confirmatory Item B.1.23-1 are closed.

3.0.3.10.3 Conclusion

On the basis of its inspection of the applicant's program, the staff finds that the program is

consistent with the GALL program. The staff also reviewed the UFSAR supplement for this

aging management program and finds that it provides an adequate summary description of the

program, as required by 10 CFR 54.21 (d).

Therefore, on the basis of its review, the staff concludes that the applicant has demonstrated

that the One-Time Inspection program will verify the effectiveness of aging management

programs so that there is reasonable assurance that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.0.3.11 Selective Leaching of Materials (B. 1.24)

3.0.3.11.1 Summary of Technical Information in the Application

The applicant's Selective Leaching of Materials aging management program is discussed in

LRA Section B.1.24 "Selective Leaching of Materials". The Selective Leaching of Materials

aging management program consists of numerous one-time inspections to determine if

selective leaching of materials is occurring. The scope of the program includes susceptible

components within the scope of license renewal that are exposed to chemically treated water,

demineralized water, raw water and ground water, and moist ventilation and gas environments.

Susceptible component materials are gray cast iron, copper alloys with less than 85% copper,

aluminum-bronze, and Muntz metal.

This AMP is credited with managing aging in the ESF, Auxiliary and Steam and Power

Conversion systems and structures.

The LRA indicates that this new program will consist of one-time inspections including visual

inspection or other appropriate examination methods of components of the different susceptible

materials selected from each applicable environment. The purpose of the program is to

determine if loss of material due to selective leaching is occurring. If selective leaching is

occurring, the program provides for evaluation as to the effect it will have on the ability of the

affected components to perform their intended function for the period of extended operation,

and the need to expand the sample of components to be tested.

The applicant indicates that the Selective Leaching of Materials aging management program is

consistent with the ten elements of aging management program XI.M33, "Selective Leaching of

Materials" specified in the GALL, with the exception that the applicant will not perform hardness

measurements on selected components. The GALL Program XI.M33 recommends both visual

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inspection and Brinell hardness measurements be made to assess the potential for selective

leaching.

The applicant indicates that the Dresden and Quad Cities Selective Leaching of Materials

program will be implemented prior to the period of extended operation.

The applicant concludes that the Selective Leaching of Materials aging management program

(including the exception) provides reasonable assurance that selective leaching aging effects

are adequately managed so that the intended functions of the components within the scope of

license renewal are maintained during the period of extended operation.

3.0.3.11.2 Staff Evaluation

In LRA Section B.1.24, 'Selective Leaching of Materials," the applicant described its AMP to

ensure the integrity of components exposed to chemically treated water, demineralized water,

raw water, ground water, and moist ventilation and gas environments. Susceptible component

materials are described as gray cast iron, copper alloys with less than 85 percent copper,

aluminum-bronze and Muntz metal. The LRA stated that this AMP is consistent with GALL AMP

XI.M33, "Selective Leaching of Materials," with the exception that the Dresden and Quad Cities

programs provide for only visual examination and do not include hardness testing. The

applicant indicated that components that exhibit visual indications of selective leaching will

receive further examination or evaluation, which may include non-destructive testing or other

examinations that provide definitive results regarding the presence of selective leaching. The

applicant indicates that the plant specific evaluation may include removal of specific

components for examination under microscope. The applicant also committed to expand the

sample size based on unfavorable inspection results. This is Commitment #24 in Appendix A of

this SER. The staff confirmed the applicant's claim of consistency during the AMR inspection.

Furthermore, the staff reviewed the exception and associated justifications to determine

whether the AMP, with the exception, remains adequate to manage the aging effects for which

it is credited. The staff also reviewed the UFSAR supplement to determine whether it provides

an adequate description of the revised program. Finally, the staff determined whether the

applicant properly applied the GALL program to its facility.

In a letter dated August 7, 2003, the staff requested additional information in RAI B.1.24 relative

to the program exception not to perform hardness testing. The staff asked why visual

inspection could be relied on especially when it was noted that selective leaching often occurs

under deposits and in non-visible areas and what basis would be used for visual inspection.

The staff requested the applicant to identify the criteria for selecting sample locations and how

operating experience will be factored into the applicant's program. The staff also requested

that the applicant supplement the UFSAR description of the program to specifically address

visual inspection.

The applicant responded to the staff request in a letter dated October 3, 2003. In the response,

the applicant provided additional justification for the program exception not to perform hardness

testing. The applicant's justification focused on a lack of accurate baseline hardness values for

susceptible plant components, difficulty in performing in-situ hardness testing and the need to

interpret the results. The applicant indicated that visual inspection would be performed

consistent with the requirements of ASME Code Section Xl VT-1 visual inspection. The

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applicant indicated that inspectors would inspect surfaces for evidence of weak, porous or

spongy layers in localized (plug-type) or general areas and if visual inspection indicated the

potential for selective leaching other NDE methods (i.e., UT) may be used to assess the

component. The applicant also noted that the program performs a number of one-time

inspections on components with susceptible material environment combinations and the

program scope will be expanded to additional components if selective leaching is identified.

The applicant noted that the selective leaching of materials aging management program is new

and that no programmatic operating experience is available at Dresden and Quad Cities.

The staff requested additional clarifying information related to the determination of selective

leaching under deposits and guidance on scope expansion if selective leaching is identified.

The applicant responded in a letter dated November 20, 2003. The applicant indicated that

visual inspection will be performed in accordance with ASME Code Section Xl VT-1

requirements and will be supplemented by work instructions. The applicant provided sample

work instructions that include steps for surface preparation including the removal of dirt grease

or other foreign material that could mask indications of selective leaching. The applicant's work

steps also indicate that if selective leaching is identified, the affected area must be removed to

sound metal and that minimum wall thickness be determined in conjunction with initiation of a

corrective action report documenting identification of selective leaching. Regarding the scope

expansion, the applicant indicated that sampling would start with the most aggressive

environments and, if necessary, expand into less aggressive environments. Additional samples

of the same material in the same environment as well as the less aggressive environments will

be chosen for inspection.

The staff reviewed the applicant's program exception not to perform hardness testing, and the

responses to the RAls and the requests for clarification. The staff concurs with the applicant

that the program will provide that aging will be managed because visual inspection will be

performed using ASME Section Xl VT-1 requirements, if necessary alternate NDE methods

may be used to assess the component's condition, the applicant has taken steps to ensure that

indications of selective leaching will not be masked through the use of surface preparation,

which will provide a somewhat qualitative assessment of surface hardness.

In response to the staff's request for the applicant to supplement the UFSAR description, the

applicant responded in a letter dated October 3, 2003. The applicant indicated that the

following statement should have been included in the UFSAR description:

The selective leaching of materials aging management program includes numerous one-time

inspections of components of the different susceptible materials selected from each of the applicable environments to determine if loss of material due to selective leaching is occurring. These inspections

will consist of visual inspection consistent with ASME Section Xl VT-1 visual inspection requirements. If selective leaching is occurring the program requires evaluation of the effect it will have on the ability of the affected components to perform their intended functions for the period of extended operation, and of the need to expand the test sample. For systems subjected to environments where water is

not treated (i.e., the open-cycle cooling water system) the program also follows the guidance of NRC

Generic Letter 89-13, 'Service Water System Problems Affecting Safety-Related Equipment.

The staff finds the applicant's response to modify the UFSAR description of the program

acceptable because it identifies that program inspections will be performed in accordance with

ASME Section Xl VT-1 visual inspection requirements and scope expansion will occur if

selective leaching is identified.

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3.0.3.11.3 Conclusions

On the basis of its review and audit of the applicants program, the staff finds that those portions

of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. In addition, the staff has reviewed the exceptions to the

GALL program and finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

during the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the UFSAR supplement for this AMP and finds that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

3.0.3.12 Buried Piping and Tanks Inspection (B.1.25)

3.0.3.12.1 Summary of Technical Information in the Application

The applicant's Buried Piping and Tanks Inspection aging management program is discussed

in LRA Section B.1.25, "Buried Piping and Tanks Inspection". The applicant states that with

enhancements, the program is consistent with the ten elements of GALL aging management

program XL.M34, "Buried Piping and Tanks Inspection" specified in The GALL. The applicant

states that the program consists of preventive and condition monitoring measures to manage

loss of material due to corrosion from external environments for buried piping and tanks in the

scope of license renewal.

This AMP is credited with managing loss of material in the ESF, Auxiliary and Steam and Power

Conversion systems.

The applicant's program takes exception to the program as described in the GALL, which

indicates that buried piping and tanks are inspected when they are excavated during

maintenance. The applicant noted that access to buried components does not occur on

specified frequencies, therefore the applicant's program includes the use of piping and

component coatings and wrappings and enhancements that include periodic pressure testing,

buried tank leakage checks, inspections of buried tank internal surfaces, and inspections of the

ground above buried tanks and piping. The program enhancements also include one-time

internal ultrasonic testing (UT) of buried steel tanks, a one-time internal UT of the bottom of an

outdoor aluminum storage tank, and a one-time visual inspection of the external surface of a

buried piping section. This AMP will be implemented at Dresden and Quad Cities prior to the

period of extended operation.

3.0.3.12.2 Staff Evaluation

In LRA Section B.1.25, "Buried Piping and Tanks Inspection", the applicant described its AMP

to perform inspections on buried piping and tanks. This AMP is provided to manage loss of

material due to corrosion from external environments for buried piping and tanks in the scope of

license renewal. The LRA stated that this AMP is consistent with GALL AMP XL.M34, "Buried

Piping and Tanks Inspection", with an exception regarding the visual inspection during

maintenance, which the applicant regarded as not having a defined frequency. Therefore, the

applicant proposed the use of coating and wrapping, periodic pressure testing, buried tank

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leakage checks, inspection of buried tank internal surfaces, and inspections of the ground

above buried tanks and piping. The applicant's program will also include one-time internal UT

of buried steel tanks, and a one-time visual inspection of the external surface of a buried piping

section. This is part of Commitment #25 of Appendix A of this SER. The staff confirmed the

applicant's claim of consistency during the AMR inspection. Furthermore, the staff reviewed the

deviation and its justification to determine whether the AMP with the deviation and

enhancements, remains adequate to manage the aging effects for which it is credited. The staff

also reviewed the UFSAR supplement (A.1.25, "Buried Piping and Tanks Inspection") to

determine whether it provides an adequate description of the program. In addition, the staff

determined whether the applicant properly applied the GALL program to its facilities.

The staff finds the applicant's exception to the GALL program acceptable, because the

applicant will inspect buried piping and tanks which are uncovered during maintenance and the

applicant will supplement this activity by performing one time inspections of selected

components as well as using flow and pressure testing to assess system integrity. The

enhancements proposed by the applicant verify that the aging of buried pipe will be managed.

Based on its review of the LRA, the staff requested further information from the applicant

related to the buried piping and tanks inspection AMP in a letter dated August 7, 2003. The

applicant replied to the staff RAIs in a letter dated October 3, 2003.

In RAI B.1.25a, the applicant was requested to indicate if all buried tanks at both plants will be

subject to a one time UT inspection and if not, how the tanks and internal areas will be selected,

to provide the acceptance criteria for the UT inspections and the actions to be taken if the

acceptance criteria are not met. The applicant responded that only one buried steel tank at

each site will be inspected. This is part of Commitment #25 of Appendix A of this SER. The

applicant also stated that selection and acceptance criteria will be based on applicable ASME

Codes and ASTM Standards as well as engineering judgement. If tank wall thicknesses are

outside the acceptance criteria the applicant indicated they will expand the sample area or

population, evaluate results, and implement necessary repairs. The staff requested that the

applicant clarify why scope expansion might not include expansion to other tanks with the same

corrosion environment. The applicant in a letter dated December 12, 2003 indicated that there

are only 2 buried tanks at each site and that the population of tanks inspected will be increased

if acceptance criteria are not met during the one time inspection. The staff finds this response

to be acceptable, because the applicant will apply engineering judgement to select the

susceptible areas for age related degradation and acceptance criteria are based on tank design

codes. Furthermore, expanding the sample scope to include other tanks with similar

environments will provide assurance that aging is managed in similar components.

The applicant originally included a one time inspection of an above ground aluminum storage

tank bottom in this AMP. The staff requested an explanation of how the features of this AMP

are relevant to an above ground aluminum tank and what correlation exists between

degradation of the buried pipe and tank materials with degradation of the aluminum tank bottom

in RAI B.1.25. The applicant was also requested to explain how the tank will be selected and

why the inspection of one tank at either Dresden or Quad Cities will be representative of the

soil-to-tank bottom interactions for all aluminum tanks at both plant sites. The applicant's

response noted that this AMP was inadvertently identified instead of the correct AMP, which is

the Above Ground Carbon Steel Tanks AMP (AMP B.1.20). The staff agrees that this activity is

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more correctly placed in AMP B.1.20 and the request for additional information is further

discussed in Section 3.0.3.9 of the SER.

The applicant provided operating experience in the LRA indicating that failures had occurred in

buried piping. In order to understand the failures, the staff requested in RAI B.1.25.that the

applicant explain how operating experience illustrates the AMP is effective, what was the root

cause of the related piping degradation, how pressure and flow testing are used to manage

aging and what changes in the program resulted from operating experience. The applicant

responded that the failures occurred in Fire Protection concrete asbestos piping and in

demineralized water carbon steel piping. The applicant indicated that the failures were

attributed to the aging effect 'loss of material', but that a specific aging mechanism was not

identified. The applicant also indicated the concrete asbestos piping was replaced with PVC.

The applicant indicated that a comprehensive approach is used to manage aging in buried

piping which includes inspections during excavation, one time inspections, flow and pressure

testing as well as system walkdowns. The applicant related operating experience with the

buried fire protection piping to illustrate how pressure and flow testing had been used to identify

degradation. The applicant responded that pressure and flow testing were not intended to'

solely manage aging. Further, the applicant stated that based on the operating experience, the

flow testing acceptance criteria were being enhanced to indicate that minor variations in system

pressure could be indicative of pinhole leaks, although system pressure and flow requirements

were still met. The applicant indicated that flow testing is performed on a three year periodicity

which will identify pipe degradation prior to a loss of system function based on their operating

experience.

The staff finds the applicant's response acceptable relative to the program's effectiveness

based on the applicant's operating experience and the use of system and pressure tests

because the applicant will perform one time inspections in conjunction with GALL

recommended inspections during excavation. The staff finds the program appropriate and

adequate to manage the aging of the buried piping prior to the loss of its intended function.

However, the staff requested the applicant to provide additional clarifying information regarding

how operating experience with buried concrete asbestos piping is applicable to managing

buried carbon steel, whether all the concrete asbestos piping had been replaced with PVC, if

concrete asbestos and PVC piping are exceptions to GALL, how aging of these materials'are

addressed and to provide information regarding the demineralized water line failure including

why one time inspection of a similar section of pipe was not warranted.

The applicant responded to the additional questions in a letter dated December 12, 2003. The

applicant indicated that experience with buried concrete asbestos piping was relative to the

program based on the operating experience of how degradation was identified and that this

method would be applicable to all piping material types. The applicant indicated that potential

degradation of some of the replaced fire main piping was initially identified on the basis of

periodic pressure drop testing. The applicant indicated that both concrete asbestos and PVC

piping are currently used. The applicant stated that PVC piping in these environments has no

aging effects and was identified as an exception to the GALL in the LRA. The applicant

indicated that the concrete asbestos piping should have been included in the LRA as an

exception to the GALL. The applicant stated the internal environment of the concrete asbestos

piping is "raw water' and the external environment is 'soil and groundwater." The applicant also

stated that the concrete asbestos pipe is in an excellent environment; buried deep to avoid

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freeze/thaw cycles, heat and stress and that there are no know chemicals that adversely affect

the concrete in the raw water or soil and ground water environments. The potential aging

effects associated with both the internal and external environments are "increase in porosity

and permeability, cracking and loss of material (spalling, scaling)" due to aggressive chemical

attack. In addition, the applicant stated that the internal environment has the potential aging

effect of "build up of deposits" due to biofouling. The applicant stated that the aging is

managed by the use of Fire System flow and pressure drop testing along with the Buried Pipe

Program B.1.25. The applicant indicated that the failure of the demineralized water line was

provided as an example of operating experience related to failure and repair of buried piping.

The applicant stated that the specific failure mechanism was not identified in maintenance

history and that this portion of the demineralized water line was not within the scope of license

renewal, thus, a one time inspection of the line was not warranted.

The staff had additional concerns regarding concrete asbestos piping and buried carbon steel

piping and requested clarifying information. Specifically, with regard to concrete asbestos

piping, the applicant's operating history indicated that failures of the piping have occurred. On

the basis of this experience, the staff requested justification for why a one-time inspection was

not warranted, as well as confirmation that the soil environment for the piping was not

aggressive. With regard to buried carbon steel piping, the applicant indicated that much of the

piping may not be coated. Given that some of the piping may not be coated, the staff

questioned why this was not identified as an exception to the GALL program. The staff

identified this issue as Confirmatory Item B.1.25-1.

The applicant responded to the staff's request for supplemental information in letters dated

December 12, 2003 and March 25, 2004. The applicant indicated that the buried concrete

piping likely failed as a result of ground shifting or heavy loads transported in the vicinity of the

piping. This piping is located in a soil and ground water environment which is not aggressive to

concrete based on pH values between 7 to 9, chlorides 5 to 30 ppm, and sulfates 10 to 30 ppm.

These values are within the NUREG 1801 criteria (chlorides less than 500 ppm, sulfates less

than 1500 ppm and pH greater than 5.5). The applicant indicated that buried carbon steel and

ductile iron piping in the Fire Suppression System are externally coated with coal tar wrapping;

however, there was some question regarding use of coating on other carbon steel buried

piping. The applicant provided supplemental information after a detailed review of plant

documents that indicates that all carbon steel buried piping at Dresden and Quad Cities was

externally coated. The applicant further indicated that the installation specification required an

inspection of the coating integrity prior to burial. The applicant provided operating experience

from a recent plant modification that required excavation of some Fire Suppression System

piping at Quad Cities. A section of 10 inch schedule 40 carbon steel piping was recently

excavated. The applicant indicated that the piping was coated with coal tar wrapping and had

been buried in the early 1970's. The nominal wall thickness of this piping is 0.365 inches. The

measured minimum and maximum wall thicknesses were 0.320 inches and 0.400 inches

respectively. The applicant concluded that there was little effect of aging on this piping after

burial for approximately 30 years. The applicant also surveyed the craft personnel who

performed the work to assess the condition of the external pipe coating. The applicant

provided qualitative information that the coating was generally in good condition" based on the

craft personnel. The staff finds the applicant's response acceptable because the applicant

provided information regarding the cause of the concrete piping degradation, provided

information consistent with NUREG 1801 that indicates the environment is not aggressive to

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concrete, that there is reasonable assurance that the buried piping is coated and provided

additional operating experience that indicates there is limited aging degradation of buried

piping. Therefore, Confirmatory Item B.1.25-1 is closed.

The staff requested in RAI B.1.25 the applicant to explain why a one-time inspection of the

buried ductile iron fire pipe including a mechanical joint was appropriate to manage aging, given

the failures identified in the operating history. The staff also requested the applicant to address

how pipe sections would be selected to represent the most likely location for degradation. The

applicant's LRA and operating history did not indicate that the failures were located in concrete

asbestos piping. The applicant indicated that the one time inspection is used in conjunction

with inspection of piping uncovered during excavation. This is part of Commitment #25 of

Appendix A of this SER. The applicant also stated that engineering judgement, including

factors such as, age, operating experience, susceptible location and accessibility would be used

to select the locations. The applicant's program will include provisions for expanding sample

size if acceptance criteria are not met, establishing root cause and specifying corrective actions.

The staff finds the applicant's response acceptable because one time inspections will be used

in addition to inspections performed when piping is exposed during excavations in accordance

with the GALL report and the related operating history pertained to failures of a different

material type.

In RAI B.1.25, the staff requested the applicant to clarify that inspections of buried pipe would

occur during excavation and that pipe coatings and wraps are considered a program element

instead of an enhancement. The applicant confirmed that inspections would occur during,

excavations and that coatings and pipe wraps are used. The staff finds the applicants

response acceptable because the applicant confirmed these program elements were consistent

with the elements of the GALL program.

3.0.3.12.3 Conclusions

On the basis of its review and audit of the applicant's program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

3.0.3.13 10 CFR Part 50, Appendix J (B. 1.28)

3.0.3.13.1 Summary of Technical Information in the Application

The applicant stated in LRA Section B.1.28 that the 10 CFR Part 50, Appendix J aging

management program is consistent with the ten elements of aging management program

XL.S4, "10 CFR Part 50, Appendix J", specified in NUREG-1801.

The 10 CFR Part 50, Appendix J aging management program is credited for aging

management of pressure boundary degradation due to loss of material in the primary

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containment and various systems penetrating primary containment. The program also manages

changes in material properties of gaskets, O-rings, and packing materials for the primary

containment pressure boundary access points.

The program consists of tests performed in accordance with the regulations and guidance

provided in 10 CFR 50 Appendix J, "Primary Reactor Containment Leakage Testing for WaterCooled Power Reactors," Option B, Regulatory Guide 1.163, "Performance-Based Containment

Leak-Testing Program," NEI 94-01, "Industry Guideline for Implementing Performance-Based

Options of 10 CFR Part 50, Appendix J," ANSI/ANS 56.8, "Containment System Leakage

Testing Requirements," and station procedures. Containment leak rate tests are performed to

assure that leakage through the primary containment and systems and components penetrating

primary containment does not exceed allowable leakage limits specified in the Technical

Specifications. An integrated leak rate test (ILRT) is performed during a period of reactor

shutdown at the frequency specified in 10 CFR Part 50, Appendix J, Option B. Local leak rate

tests (LLRT) are performed on isolation valves and containment access penetrations at

frequencies that comply with the requirements of 10 CFR 50 Appendix J, Option B.

With regard to "operating experience", the applicant indicated that the industry has found that

10 CFR Part 50, Appendix J testing has been effective in maintaining the pressure integrity of

the containment boundaries, including identification of leakage within the various systems'

pressure boundaries. The Dresden and Quad Cities facilities have demonstrated experience in

effectively maintaining the integrity of the containment boundaries as evidenced by the

selection of Option B of 10 CFR Part 50 Appendix J leakage testing requirements. Both stations

have experienced "as found LLRT results in excess of individual containment penetration

administrative limits. Evaluations were performed and corrective actions were taken to restore

the individual penetration leakage rates to within the established administrative leakage limits in

accordance with the Appendix J testing program.

The applicant concludes that the 10 CFR Part 50, Appendix J aging management program

provides reasonable assurance that the loss of material and changes in material properties

aging effects are adequately managed so that the intended functions of primary containment

components within the scope of license renewal are maintained during the period of extended

operation.

3.0.3.13.2 Staff Evaluation

In LRA Section B.1.28, "10 CFR Part 50, Appendix J", the applicant described its AMP to

manage containment leak-tight integrity. The LRA stated that this AMP is consistent with GALL

AMP XI.S4, 410 CFR Part 50, Appendix J". The staff confirmed the applicant's claim of

consistency during the AMR inspection. In addition, the staff determined whether the applicant

properly applied the GALL program to its facility. The staff also reviewed the UFSAR

supplements for both Dresden and Quad Cities to determine whether they provide an adequate

description of the program.

3.0.3.13.3 Conclusions

On the basis of its review and audit of the applicant's program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

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consistent with the GALL program. Since the GALL program is acceptable to the staff, the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

3.0.3.14 Structures Monitoring Program (B. 1.30)

3.0.3.14.1 Summary of Technical Information in the Application

The applicant stated in LRA Section B.1.30 that, with enhancements, the structures monitoring

aging management program is consistent with the ten elements of aging management program

XL.S6, "Structures Monitoring Program," specified in NUREG-1801.

The structures monitoring program is credited for aging management of various structures and

external surfaces of mechanical components within the scope of license renewal. The program,

which was developed for structures monitoring under 10 CFR 50.65, 'Requirements for

Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," is based on the

guidance in Regulatory Guide 1.160 Revision 2, "Monitoring the Effectiveness of Maintenance

at Nuclear Power Plants," and NUMARC 93-01 Revision 2, Industry Guidelines for Monitoring

the Effectiveness of Maintenance at Nuclear Power Plants," and implemented through

procedures. The program is not credited for managing protective coatings.

The program will provide for visual inspections of structures and components not included in the

ASME Section Xl, Subsection IWF (B.1.27) aging management program. For licence renewal,

the following enhancements will be made. Enhancements are scheduled for implementation

prior to the period of extended operation.

* The program will provide for inspections of structural steel components in secondary

containment, flood barriers, electrical panels and racks, junction boxes, instrument racks

and panels, offsite power structural components and their foundations, and the Quad Cities

discharge canal weir as part of the ultimate heat sink. -

* The program will provide for periodic reviews of chemistry data on below-grade water to

confirm that the environment remains non:aggressive for the license renewal term for the

aging mechanisms of corrosion of embedded steel and aggressive chemical attack of

concrete.

* The program will provide for inspection of a sample of non-insulated indoor piping external

surfaces at locations immediately adjacent to periodically inspected piping supports.

* Program procedures will reference specific insulation inspection criteria for existing cold

weather preparation and inspection procedures for outdoor insulation, and establish new

inspections for various indoor area piping and equipment insulation.

* The program will provide for inspection parameter specificity for non-structural joints,

roofing, grout pads, and isolation gaps.

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l

* The program will extend inspection criteria to the structural steel, concrete, masonry walls,

equipment foundations, and component support sections of the program to provide

consistency with NUREG-1 801 component supports.

In its discussion of operating experience, the applicant stated that roof leaks were detected and

corrective actions were taken for the Dresden turbine building and main control room and for

the Quad Cities reactor building and turbine building. Minor degradation of concrete has been

detected such as cracks with water stains, pitting, and leaching for various structures including

the Dresden reactor building and crib house. Similar degradation has been detected in the

Quad Cities reactor building and circulating water intake bays. The degradation was evaluated

and dispositioned in accordance with the corrective action process. Cracks and small gaps

were detected in elastomer seals at both Dresden and Quad Cities. Most of the degraded

conditions were attributed to man-made occurrences. None were determined to be significant.

Damage and degradation of insulation has been observed and repaired.

The applicant concludes that the structures monitoring program for aging management

provides reasonable assurance that the aging effects are adequately managed so that the

intended functions of structures within the scope of license renewal are maintained during the

period of extended operation.

3.0.3.14.2 Staff Evaluation

In LRA Section B.1.30, "Structures Monitoring Program," the applicant described its AMP to

manage aging of structures and structural components within the scope of license renewal that

are not managed by one of the other structural AMPs. The LRA stated that this AMP, with the

enhancements described above in Section 3.0.3.14.1 of this report, is consistent with GALL

AMP XI.S6, "Structures Monitoring Program". The staff confirmed the applicant's claim of

consistency during the AMR inspection. Furthermore, the staff reviewed the enhancements to

determine whether this AMP, with the enhancements, is adequate to manage the aging effects

for which it is credited. In addition the staff determined whether the applicant properly applied

the GALL program to its facility. The staff also reviewed the UFSAR supplements for both

Dresden and Quad Cities to determine whether they provide an adequate description of the

revised program.

In its description of the program and the enhancements, the applicant made several statements

that needed clarification before the staff could complete its evaluation. Therefore, the applicant

was requested by RAI B.1.30 to submit the following additional information:

(a) The LRA states that "The program will provide for visual inspections of structures and

components not included in the ASME Section Xl, Subsection IWF (B.1.27) aging management

program." The staff asked if this statement was intended to encompass component supports

not covered by Subsection IWF. The staff requested the applicant to clearly define the scope

of structures and components encompassed by this statement.

(b) The last item under "Enhancement" states that "The program will extend inspection criteria

to the structural steel, concrete, masonry walls, equipment foundations, and component support

sections of the program to provide consistency with NUREG-1801 component supports." The

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staff is unable to interpret the meaning of this enhancement. The staff requested the applicant

to describe in detail the structures and structural components included in this enhancement; the

associated aging effects in need of aging management; the inspection methods to be used, and

the acceptance criteria to be applied.

In its response to RAI B.1.30 dated October 3, 2003, the applicant stated the following:

Exelon has reviewed LRA Appendix B.1.30 and the following clarification is provided.

The Structural Monitoring Program is intended to encompass component supports that are not

covered by the ASME Section Xi, Subsection IWF. The ASME Section Xl, Subsection IWF program provides for inspection of ASME Class 1, 2, and 3 supports. It will be enhanced to include ASME

Class MC supports. The Structures Monitoring Program consists of defining and performing periodic

structural evaluations which will ensure the timely identification, assessment and repair of degraded structural elements. One of the elements to be evaluated includes component supports. Component

supports include:

* Pipe Whip Restraint Supports

* Jet Impingement Shield Supports * Instrument Tubing Supports

* Tube Track Supports * HVAC Supports * Conduit and Junction Box Supports

* Cable Tray Supports * Instrument Racks, panels and supports * Electrical panels, racks, MCCs, Switchgears, junction boxes and supports

* Piping Component Supports including immediately adjacent piping/tubing.

A fixed number of supports for each type of component are selected for evaluation. The selection

includes representation of supports throughout the plant, considering environmental conditions as well

as configuration. Component selection includes sample sizes for each component classifications

mentioned above. The component support includes all auxiliary steel members (i.e., all steel plates, shapes, bolts, and anchors) between the supported component and the main structural element (i.e.,

the concrete slab/beam or the structural steel floor framing). The program does not include standard

components such as snubbers, struts and spring cans. Grout pads for support base plates are also

in-scope.

The last item under"Enhancement7 in LRA Appendix B.1.30 related to consistency with NUREG 1801

component supports is not an enhancement in the sense that new areas of inspection are being added, but it is rather a clarification to NUREG 1801 terminology to ensure that the proper attributes

are considered for specific types of installed plant components and structures. The following includes

the types of clarifications that were added to in the structural monitoring program implementing procedure for structural steel, concrete, masonry walls, equipment foundations, and component

support sections to ensure consistency with NUREG 1801.

* Added several support sub-categories under Component Supports' for Tube Track

Supports, Instrument Tubing Supports, Jet Impingement Shield Supports, and Pipe Whip Restraint Supports

' Added platform support clarification wording under "Structural Steel Elements" examination

guidelines. * Added aging effect (loss of material due to environmental corrosion-pitting, corrosion, general corrosion) to bolted connection inspection. - * Added aging effect (loss of material due to environmental corrosion-pitting, corrosion, general corrosion) to wall support inspection. * Added aging effect (loss of material due to environmental corrosion-pitting, corrosion, general corrosion) to anchorage and welds inspection. * Added panels, cabinets and enclosures for electrical equipment.

* Added emergency diesel generators, HVAC system components, and other miscellaneous

equipment under "Equipment Foundations.!

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* Added aging mechanism (service induced cracking or other concrete aging degradation) to

Grout Pads/Concrete Pedestals examination.

The above clarifications are not enhancements, but ratherare clarifications to provide consistencywith

NUREG 1801 terminology. All associated aging effects in need of aging management for the

structures and structural components included in the above clarifications are presently being

managed.

The additional information provided by the applicant in its response to RAI B.1.30 sufficiently

answers the questions posed by the staff, with two exceptions. It was not clear whether the

category "Piping Component Supports including immediately adjacent piping/tubing," listed in

the response to item (a) of the RAI is meant to include non-ASME piping supports. It also was

not clear as to why the Structures Monitoring Program does not include "standard components

such as snubbers, struts and spring cans." In order to completely resolve the response to this

RAI, the staff requested that the applicant confirm the following:

(a) the B.1.30 program covers non-ASME piping supports

(b) there are no snubbers, struts, or spring cans on non-ASME piping and components

This issue was identified as Confirmatory Item 3.0.3.14.2-1.

In its response to Confirmatory Item 3.0.3.14.2-1, dated December 5, 2003, the applicant

stated:

Exelon has reviewed the supplemental Information Request and provides the following clarification and

confirmation.

1)The Structure Monitoring Program, B.1.30, includes non-ASME piping supports for aging management. The

selection of component supports includes a representation of supports throughout the plant, considering

environmental conditions as well as configuration.

2)There are standard components such as snubbers, struts, and spring cans on non-ASME piping and

components that are in-scope of the License Renewal, which are required to be managed for aging. The

Structural Monitoring Program, B.1.30, will inspect the non-ASME component supports including the standard

components. The in-scope non-ASME component supports are addressed in LRA Section 2.4.15, Table 2.4-15

under the Component Groups 'Support Members' with a 'Non-S/R Structural Support" component intended

function. Aging Management Reference 3.5.1.29 discusses the aging management of the non-ASME

component supports.

The staff finds the applicant's response to Confirmatory Item 3.0.3.14.2-1 to be acceptable,

because it clarified that the "Structural Monitoring Program," (B.1.30), will inspect non-ASME

piping and component supports, including snubbers, struts, and spring cans. This commitment

is stated in the enhancements as "The program will provide for inspection of a sample of

non-insulated indoor piping external surfaces at locations immediately adjacent to periodically

inspected piping supports and inspection of standard components such as snubbers, struts,

and spring cans," under B.1.30, Structures Monitoring Program, in the applicant's response to

Open Item 3.5.2.3.2 1: (Section 3.5.2.3.2 of ASME Code, Section Xl, Subsection IWF (B.1.27)),

dated June 22, 2004. Therefore Confirmatory Item 3.0.3.14.2-1 is resolved. This is part of

Commitment #30 in Appendix A of this SER.

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3.0.3.14.3 Conclusions

On the basis of its review and audit of the applicant's program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL-program. Since the GALL program is acceptable to the staff, the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement

for this AMP and concludes that it provides an adequate summary description of the program,

as required by 10 CFR 54.21 (d).

3.0.3.15 Heat Exchanger Test and Inspection Activities (B.2.6)

3.0.3.15.1 Summary of Technical Information in the Application

The heat exchanger test and inspection activities are a plant specific program, not addressed in

the GALL report. In Section B.2.6 of the LRA, the applicant addressed the ten program

elements using guidance in Branch Technical Position RLSB-1 in Appendix A of the SRP-LR.

The following information was provided in the LRA:

The LRA describes the heat exchanger test and inspection activities as providing condition

monitoring, inspection, and performance testing. The activities manage loss of material,

cracking, and buildup of deposits in heat exchangers in the scope of license renewal that are

not tested and inspected by the Open-Cycle Cooling Water System (B.1.13) and Closed-Cycle

Cooling Water System (B.1.14) aging management programs. The augmentation activities

identified in the GALL report lines IV.C1.4-a and IV.C1.4-b to manage loss of material and

cracking for the Dresden isolation condensers are included in this aging management program.

The applicant indicates that the inspection activities are new and will be implemented prior to

the period of extended operation.

The applicant utilizes surveillance testing, inspections and in-service nondestructive

examinations (ISI, NDE) to verify that heat exchanger performance is adequate and to detect

aging effects. Results are trended to confirm that aging effects are managed and that system

and component functions are maintained.

Isolation condenser test and inspection augmentation activities detect cracking due to stress

corrosion cracking or cyclic loading, and detect loss of material due to pitting and crevice

corrosion. These augmentation activities are not part of the ISI program, but are used by the

applicant to verify that the ISI program is effective, for ensuring that significant degradation is

not occurring, and the intended function of the isolation condenser. is maintained during the

extended period of operation. These augmentation activities consist of temperature and

radioactivity monitoring of the shell-side (cooling) water, and eddy current testing of tubes.

The inservice inspection, water chemistry management and lubricating oil management

activities applied to the heat exchangers in the scope of this aging management program are

described in other aging management program evaluations.

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3.0.3.15.2 Staff Evaluation

Because the Heat Exchanger Test and Inspection Activities program is not included in the

GALL, The staff review was performed against the 10 elements of the Branch Technical

Position RLSB-1 in Appendix A of the SRP-LR and focused on how the program manages

aging effects through the effective incorporation of the following 10 elements: program scope,

preventive actions, parameters monitored or inspected, detection of aging effects, monitoring

and trending, acceptance criteria, corrective actions, confirmation process, administrative

controls, and operating experience. The applicant indicated that the corrective actions,

confirmation process, and administrative controls are part of the site-controlled Quality

Assurance Program. The staff's evaluation of the Quality Assurance Program is provided

separately in Section 3.0.4 of this SER. The staff also reviewed the UFSAR supplement to

determine whether it provides an adequate description of the program. The staff identified a

need for additional information which was requested in the staff letter to the applicant of August

7, 2003. The applicant responded by letter dated October 3, 2003.

[Program Scope] The LRA identified the following heat exchangers as being subject to these

test and inspection activities:

* Dresden Unit 2 and 3 HPCI lubricating oil coolers

* Dresden Unit 2 and 3 HPCI gland seal condensers

* Dresden main control room air handling unit heat exchanger

* Dresden Unit 2 and 3 isolation condensers

* Quad Cities Unit 1 and 2 HPCI lubricating oil coolers

* Quad Cities Unit 1 and 2 HPCI gland seal condensers

* Quad Cities main control room air handling unit heat exchanger

* Quad Cities Unit 1 and 2 battery/station blackout room HVAC heat exchangers

The staff finds the scope to be appropriate for the AMP.

[Preventive Actions] The LRA stated that these heat exchanger test and inspection activities

do not provide any preventive actions. These activities provide condition monitoring to detect

degradation prior to a loss of function. The staff finds this acceptable and notes that preventive

actions are not required.

[Parameters Monitored/Inspected] The LRA stated that performance tests verify system

operability by verifying proper fluid flows, temperatures, or differential pressures during system

operation under load. Wall loss and surface condition of heat exchanger tubes will be monitored

by eddy current inspection. Radioactivity monitoring of the Dresden isolation condenser is

monitored through periodic sampling. The staff finds that the parameters monitored will identify

loss of material or loss of heat transfer and therefore, are acceptable.

[Detection of Aging Effects] Loss of material, cracking, or build up of deposits would result in

degradation of heat exchanger or system performance. Inspection activities monitor the effects

of corrosion and buildup of deposits. Periodic inspections and NDE tests may consist of visual

inspections, eddy-current testing, and ultrasonic tests or radiography to detect loss of material,

cracking, or buildup of deposits. System performance testing will be used to detect loss of heat

transfer in heat exchangers. The staff requested additional information in RAI B.2.6 a,

3-54
regarding detection of local corrosion mechanisms affecting the battery station blackout room

heat exchangers and the HPCI lube oil coolers and gland seal condensers. The applicant's

response stated that periodic inspections (visual and eddy current) of accessible tube internal

surfaces for the HPCI lubricating oil coolers and gland seal condenser tubes will be used to

identify galvanic, crevice and pitting corrosion and MIC and FAC. One-time visual inspections

will be used to identify the potential for selective leaching in a component with similar material

environment combination as the HPCI lubricating oil coolers and gland seal condenser tube

internal surfaces. The applicant stated that visual inspections of accessible internal surfaces of

the Quad Cities battery/station blackout room heat exchanger will identify loss of material in that

component. The staff finds that the applicant's program will detect aging effects within the

program scope through the use of system performance testing, visual inspection and other

NDE methods such as eddy current testing. Furthermore, the applicant's related operating

experience in response to Generic Letter 89-13, "Service Water System Problems Affecting

Safety-Related Equipment," issued July 18, 1 989illustrates that the program will be capable of

detecting aging.

[Monitoring and Trending] Heat transfer testing results are documented in plant test

procedures, and are trended and reviewed by the appropriate plant personnel. Isolation

condenser temperatures are recorded in surveillance logs and radiation monitoring of the

isolation condensers is conducted by procedure. The applicant has established the frequency

and extent of inspections and testing to ensure detection of aging effects before the loss of

intended function of the heat exchanger or associated system. The applicant relies on system

operability testing to verify heat removal capabilities. Inspections are generally conducted at 10-

year intervals or less, with shorter intervals based on industry guidelines or plant operating

experience. Eddy current testing is to be performed at least once every 10 years, and the

procedure provides for increasing the inspection frequency based on the results.

After initial inspection, subsequent inspection frequencies will be based on the as-found

condition of the equipment. The inspection and 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.

The staff asked the applicant in RAI B.2.6d to provide additional details describing the methods

that will it will use to evaluate inspection results and assess remaining component life

predications for material loss and cracking mechanisms. The applicant's response stated that

cracking and loss of material are documented in plant procedures and evaluations are

performed for inspection results that do not satisfy the acceptance criteria. Condition reports

are initiated to document concerns and the resolution of the condition reports includes

engineering evaluations including an assessment of remaining component life and the need for

additional aging management activities.

The staff finds the applicant's monitoring and trending is acceptable because system

performance testing and NDE results are documented and the frequency of tests and

inspections are established with provisions to reevaluate the frequency to ensure aging is

managed in the future. Further, the staff finds the program acceptable because corrective

action reports will be used to document aging concerns and ensure evaluations are performed

to evaluate degradation and remaining life evaluations.

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[Acceptance Criteria] The LRA states that specific acceptance criteria are provided in the

inspection or test procedures, as required to ensure continued system and component

operability. The applicant stated system functional testing must confirm the system's ability to

meet minimum Technical Specification requirements and EPRI guidance is used to determine

allowable percent wall loss, plugging criteria, and for projections of remaining life. Indications of

degradation are evaluated by the applicant to determine if the material condition will maintain

the system intended function prior to returning the system to operable status. The applicant

performs engineering evaluations if aging is identified and to determine corrective action. The

staff requested that the applicant provide additional details on the evaluation methods and

acceptance criteria/standards in RAI B.2.6c. The applicant's response to this RAI noted that

EPRI documents are used as a basis to determine allowable wall loss, plugging criteria, and

projections of remaining life. The applicant indicated that these documents included the

following:

* EPRI TR-106857, Volume 34, "Preventive Maintenance Program Basis: Main Condensers,"

July 1988

* EPRI CS-5235, "Recommended Practices for Operating and Maintaining Steam Surface

Condensers,' July 1987

* EPRI TR-1 00385, "Balance-of-Plant Heat Exchanger Condition Assessment Guidelines,"

July 1992

* EPRI TR-1 01772, "Electromagnetic NDE Guide for Balance-of-Plant Heat Exchangers,"

Rev. 2, December 1997

* ERPI TR-1 10392, "Eddy Current Testing of Service Water Heat Exchangers for Engineers

Guideline, Final Report," February 1999

Furthermore, the applicant stated that these procedures, governing eddy current testing,

contain criteria for establishing inspection timing, inspection interval reduction or expansion,

and tube random sampling schemes based on criteria such as the following:

* Number of tubes plugged

* Rate of tube wall loss

* Evidence of tube cracking

* Wall degradation factors (e.g., flaw growth rate)

Similar acceptance criteria are provided in procedures governing other NDE methods utilized by

the program. The applicant stated that acceptance criteria for visual inspection may vary

depending on a number of parameters associated with the particular heat exchanger being

inspected. The applicant stated that in general the visual acceptance criteria will include

ensuring the number of plugged/blocked tubes is less than that allowed by a review of the heat

exchanger load calculation or engineering judgement. The applicant stated that the visual

acceptance criteria for evidence of tube fouling would be based on operating experience and

system performance. The applicant stated that visual acceptance criteria will also include

inspection for pitting and general corrosion. The applicant indicated that evaluations will be.

performed for inspections that do not satisfy acceptance criteria and condition monitoring

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reports are initiated to document conditions in accordance with corrective action program. The

applicant indicated that resolution of the corrective action documents would include engineering

evaluations assessing the remaining component life and determine the need for additional

aging management activities.

The staff found that the applicant's acceptance criteria were acceptable because the

acceptance criteria are based on industry guidelines and current practice that account for

frequency of inspection, sample expansion and applicable aging mechanisms as well as

incorporation of operating history and system performance criteria.

[Operating Experience] The LRA stated that this is a new aging management program.

Therefore, no program operating experience exists at this time. However, the LRA indicated

that similar controls implemented for the GL 89-13, "Service Water System Problems Affecting

Safety-Related Equipment," program have been effective in detecting aging effects in heat

exchangers. Instances of loss of material, cracking, and buildup of deposits in heat exchangers

have been detected in Dresden and Quad Cities heat exchangers prior to loss of system

intended functions. In RAI B.2.6b, the staff requested that the applicant provide additional

details regarding these occurrences, including the heat exchanger, type of degradation

mechanism, how it was detected, and corrective action taken, etc. The applicant's response to

this RAI provided a list of the heat exchangers identified by the GL 89-13 program and provided

examples of the types of degradation, methods of detection and associated corrective actions

as follows:

Loss of material for TBCCW tubing identified by eddy current testing as part of periodic inspections. Corrective actions included evaluating inspection results and replacing tubes with minimum wall

thicknesses not meeting acceptance criteria.

Buildup of deposits for ECCS room cooler components identified by cooler flow surveillance or

operator rounds instrumentation inspections. Corrective actions included cleaning and subsequent inspection of surfaces.

Loss of material of ECCS room cooler tubing identified by eddy current testing. Corrective actions

included revising procedures to require periodic eddy current testing and replacing the associated

cooling coil.

The staff finds that the applicant's operating experience related to GL 89-13 confirms that the

applicant's heat exchanger test and inspection program will adequately manage aging because

similar degradation mechanisms have been identified using similar techniques in plant heat

exchangers and the applicant has incorporated this experience into this program.

3.0.3.15.3 Conclusions

On the basis of its review of the applicant's program, the staff finds that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR supplement for this AMP

and finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

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3.0.3.16 Lube Oil Monitoring Activities (B.2.5)

3.0.3.16.1 Summary of Technical Information in the Application

The applicant's Lube Oil Monitoring program is discussed in LRA Section 6.2.5, "Lube Oil

Monitoring Activities.' The applicant states that the program is not consistent with a GALL

report program; therefore, the applicant summarized the program in terms of the 10-element

program as described in Branch Technical Position, Appendix A of the SRP-LR. The LRA

credits this program with managing loss of material and cracking of lubricating oil coolers in the

HPCI, emergency diesel generator, station blackout (SBO) diesel generator, electro-hydraulic

control, reactor core isolation cooling, reactor recirculation motor generator oil and generator

hydrogen seal oil systems at the D/QCNPS. The applicant stated that the program will use

periodic sampling, testing, and trending for maintaining physical and chemical properties in

lubricating oil.

The applicant stated that this program manages the physical and chemistry properties in the

lubricating oil. The complete aging management for the lubricating oil heat exchangers in the

scope of this program also includes activities under the "Closed-Cycle Cooling Water System"

and/or "Heat Exchanger Test and Inspection Activities," AMPs B.1.14 and B.2.6, respectively.

The applicant concluded that the Lube Oil Monitoring program will mitigate, detect, monitor, and

trend the effects of aging to provide reasonable assurance that the intended functions will be

maintained during the period of extended operation.

3.0.3.16.2 Staff Evaluation

In LRA Section 6.2.5, "Lube Oil Monitoring Activities," the applicant described its AMP to

manage loss of material and cracking in lubricating oil coolers within the scope of license

renewal. The staff reviewed this program using the guidance in Branch Technical Position

RLSB-1 in Appendix A of the SRP-LR and focused on how the program manages aging effects

through the effective incorporation of the following 10 elements: program scope, preventive

actions, parameters monitored or inspected, detection of aging effects, monitoring and trending,

acceptance criteria, corrective actions, confirmation process, administrative controls, and

operating experience. The applicant indicated that the corrective actions, confirmation process,

and administrative controls are part of the site-controlled Quality Assurance Program. The

staff's evaluation of the Quality Assurance Program is provided separately in Section 3.0.4 of

this SER. The remaining seven elements are discussed below. The staff also reviewed the

UFSAR supplement to determine whether it provides an adequate description of the program.

In its October 3, 2003, response to RAI B.1.23-2(a), the applicant committed to include the

following additional components in the scope of this program: components in the reactor core

isolation cooling (RCIC) system, additional components in the high pressure coolant injection

(HPCI) system, additional components in the emergency diesel generator and auxiliaries

system, and additional components in the station blackout diesel system. In addition, the

applicant committed to add components exposed to EHC oil (main turbine and auxiliary

systems) and generator hydrogen seal oil (turbine oil system - Quad Cities only) to the scope of

this program. The staff found that adding the above components to the scope of this program

is appropriate, since maintaining oil quality is important for preventing aging effects. However,

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the applicant did not provided updates to the program elements to address the increased scope

of the program.' The applicant was requested to provide'the appropriate revisions to the 10

elements and the UFSAR summary description of this program. The staff identified this issue

as Confirmatory Item B.2.5-1.

In its draft supplemental response dated December 18, 2003, the applicant further committed to

add components exposed to EHC oil (main turbine and auxiliary systems) and generator

hydrogen seal oil (turbine oil system) to the scope of this program. The applicant added these

components to the scope of the program by letter dated January 26, 2004. The staff found that

adding the above components to the scope of this program is appropriate, since maintaining oil

quality is important for preventing aging effects in these components.

In a letter dated June 22, 2004, the applicant committed to include the following additional

component in the scope of this program: components in the reactor recirculation motor

generation oil system. The staff found that adding the above component to the scope of this

program is appropriate, since maintaining oil quality is important for preventing aging effects in

these components.

[Program Scope] The applicant stated that this AMP is applicable to heat exchanger and other

components exposed to a lubricating oil environment in the HPCI, emergency diesel generator

and auxilaries, (SBO) diesel and auxlilaries, reactor core isolation cooling (RCIC), generator

hydrogen seal oil (HSO), main turbine and auxiliaries'(electro-hydraulic control (EHC) oil

subsystem), and reactor recirculation motor generator systems. The staff finds that the scope is

acceptable because it includes those components that rely on the program for aging

management.

[Preventive or Mitigative Actions] The applicant's program monitors and controls the oil

properties and impurity levels. When the parameters exceed predefined limits, actions are

taken to restore the conditions. The staff finds that maintaining the oil parameters mitigates

loss of material and cracking in lubricating oil systems; therefore, the staff finds this acceptable.

[Parameters Monitored or Inspected] The applicant stated that the parameters monitored by'

the program include viscosity, total acid number, total base number, rotary bomb oxidation test,

water demulsability, particle count, fuel and combustion byproducts, sediment, water, antifoaming characteristics, whole particle counting, air release and emission spectrum. The

applicant also stated that the parameters monitored by the program depends on oil type and

type of service. The staff notes that loss of material due to general, crevice, and pitting -

corrosion and cracking are applicable aging effects for lubricating oil cooler components in a

lubricating oil environment at locations containing water or contaminants such as chloride ions.

By RAI B.2.5(a), the staff asked the applicant to clarify whether water, moisture, and chloride

ions are monitored for all type of oil and service. If not, the staff requested the applicant to

provide justification for not including these parameters in monitoring. In its response dated

October 3, 2003, the applicant stated that water/moisture is monitored as part of the Lubricating

Oil Monitoring'Activities program.'No monitoring for chloride ions is provided in this program.

The applicant explained that EPRI 1003056, Non-Class 1 Mechanical Implementation Guideline

and Mechanical Tools, Revision 3, Appendices C and G were reviewed in the development of

the Lubricating Oil Monitoring Activities program. These appendices address oil environments

in general and lubricating oil environments for heat exchangers, respectively. Appendix C

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identifies damaging effects associated with chlorides in fuel oil environments, but no similar

effects are identified for lubricating oil environments. Appendix G does not identify any

applicable aging effects associated with chlorides for lubricating oil environments in heat

exchanger components. The applicant also stated that there is no site operating experience of

failure or degradation in oil environments attributed to the presence of chlorides. Therefore, the

applicant concluded that monitoring for chloride ions is not required for the Lubricating Oil

Monitoring Activities program. Based on the applicant's operating experience, the staff finds

that the applicant's response satisfactorily addresses the staff's concerns and RAI B.2.5(a) is

considered closed. The staff concludes that the applicant is monitoring the appropriate oil

parameters; therefore, the staff finds this acceptable.

[Detection of Aging Effects] The applicant stated that samples of lubricating oil are taken

monthly for EDGS, EHC oil, reactor recirculation motor generator oil, and HSO systems,

quarterly for HPCI, SBO diesel generators, semi-annually for the RCIC pump, and every 24

months for the RCIC turbine. Sampling frequency is increased if plant and equipment operating

conditions indicate a need to do so. The applicant stated that the sampling would reveal aging

degradation because increased impurities and degradation of oil properties indicate

degradation of material in lubricating oil systems. The staff finds this acceptable because

sampling and analyses are performed periodically, and the analysis is capable of detecting

aging degradation.

The staff also notes that the aging effects of the heat exchangers are also managed by the

"Closed-Cycle Cooling Water System" and/or "Heat Exchanger Test and Inspection Activities,"

AMPs B.1.14 and B.2.6, respectively. For other components, the applicant uses the One-Time

Inspection Program (B.1.23) to verify the effectiveness of the Lube Oil Monitoring Activities

AMP. The inspections and performance testing under these programs provides additional

assurance that loss of material and cracking will be detected before the loss of intended

function; therefore, the staff finds this acceptable.

[Monitoring and Trending] The Lube Oil Monitoring program monitors the relevant parameters

via samples taken monthly for EDGs, quarterly for HPCI, SBO diesel generators, EHC oil, and

HSO systems, semi-annually for the RCIC pump, and every 24 months for the RCIC turbine.

The oil analysis results are trended and evaluated using computer software and a database.

The applicant stated that the lubricating oil analysis results are trended and evaluated using

computer software and a database. The staff finds that monitoring through sample analysis is

appropriate and that the frequency is consistent with industry experience; therefore, the staff

finds the monitoring and trending to be acceptable.

[Acceptance Criteria] The applicant stated that normal, alert, and fault levels have been

established for the various chemical and physical properties, wear metals, additives, and

contaminant levels based on information from oil manufacturers, equipment manufacturers, and

industry guidelines, for the specific oil type and application. The applicant also stated that the

program maintains contaminant and parameter limits within the application-specific limits. By

RAI B.2.5(b), the staff asked the applicant to explain the acceptance criteria of water, moisture,

and contaminants. In its response dated October 3, 2003, the applicant provided the acceptable

limits for water/moisture and contaminants at normal, alert, and fault levels for emergency

diesel generator and SIO diesel components with MOBILGARD 450 NC oil and for HPCI

turbine components with MOBIL VAPROTEC LIGHT oil. The applicant stated the acceptable

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limits are based on EPRI 1003056, uNon-Class 1 Mechanical Implementation Guideline and

Mechanical Tools," Revision 3, and that any failures to meet these criteria result in a condition

evaluation, an identification of root causes, and correction of the adverse condition. The staff

finds that the acceptance criteria are consistent with industry guidelines and that the applicant's

activities in case of failure to meet these acceptance criteria are reasonable; therefore, the staff

finds these criteria acceptable.

[Operating Experience] The applicant stated that oil sampling and analysis have detected

particulate or water contamination (or both) in lubricating oil systems. The operating experience

has produced procedure and program changes, which have improved the effectiveness of

lubricating oil testing and inspection activities. In RAI B.2.5(c), the staff asked the applicant to

describe the corrective actions made and the facilities' operating experience since these

corrective actions were implemented. In its response dated October 3, 2003, the applicant

provided four examples of corrective actions made as a result of operating experience involving

lube oil sampling and analysis. In one of the examples, the applicant stated that the October 28,

1999 oil analysis of the Unit 1A (1B) SBO diesel engine crankcases indicated high percentage

volume for sediment of 0.3 percent (upper limit of 0.05 percent volume). All physical

parameters other than sediment were found to be suitable for use. A recommendation was

made to continue sampling/trending oil sample results on a quarterly frequency. The sampling

procedure was revised to include requirements to perform sampling on a quarterly basis, and

trend results. In another example, the applicant stated that a number of Quad Cities oil analysis

results for RHRSW pump bearings showed high metal levels. It was determined that the

high/increased wear level concentrations could have been indications of pump shaft, housing,

rolling element bearing or bearing cage clearance wear. It was determined that the pump

bearing oil analysis required large amounts of oil to be collected because smaller sample

amounts had a tendency to show high/erratic wear levels. The sampling procedure was revised

to include requirements to draw a relatively large sample. The applicant stated that no operating

experience involving recurrence of heat exchanger degradations since implementation of the

associated corrective actions. The staff finds that the applicant's response satisfactorily

addresses the staff's concerns and RAI B.2.5(c) is considered closed. The staff finds that the

applicant's operating experience supports the conclusion that the program will be effective in

preventing aging of the components in the scope of this program; therefore, the staff finds this

acceptable.

Therefore, Confirmatory Item B.2.5-1 is closed.

3.0.3.16.3 Conclusions

On the basis of its review of the applicant's program, the staff finds that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR supplement for this AMP

and finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

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3.0.3.17 Periodic Inspection of Ventilation System Elastomers (B.2.3)

3.0.3.17.1 Summary of Technical Information in the Application

The applicant's periodic inspection of ventilation system elastomers is discussed in LRA Section

B.2.3, "Periodic Inspection of Ventilation Elastomers." The applicant noted that this program is

not addressed in the GALL Report and therefore summarized the program in terms of the 10-

element program described in Branch Technical Position Appendix A-1 of the SRP-LR. The

applicant stated that GALL Sections V.B1, V.62, Vll.F1, VIl.F3, and VII.F4 state that ventilation

system elastomers used for flexible boots, access door seals, and filter seals are susceptible to

hardening and loss of strength, and loss of material aging effects and that the GALL aging

management program column for these sections states that a plant-specific aging management

program is to be evaluated. The applicant claimed that the improved program for periodic

inspection of ventilation system elastomers provides routine inspection of certain elastomers in

ventilation systems in accordance with plant procedures and predefined tasks.

This AMP is credited with providing condition monitoring to detect degradation prior to a loss of

function via inspections for cracking, loss of material, or other evidence of aging of all flexible

boots, access door seals and gaskets, filter seals and gaskets, and room temperature

vulcanizing (RTV) silicone used as a duct sealant and testing of seals for hardening if evidence

of aging is found. This AMP calls for periodic inspection of ventilation system elastomers

including those in the standby gas treatment, reactor building ventilation, emergency diesel

generator building ventilation, station blackout diesel generator building ventilation, and main

control room ventilation systems.

The applicant performed elastomer inspections at intervals sufficient to detect aging prior to the

equipment failing a leakage test or filter efficiency test. Review of the plant-specific operating

experience indicates that, although Dresden and Quad Cities have experienced leaks in

ventilation systems due to deterioration of or damage to elastomers, including flexible boots and

access door seals and gaskets, the leaks were found and corrected in a timely manner and did

not result in a loss of function of the ventilation system train.

In its LRA, the applicant concludes that implementation of the Periodic Inspection of Ventilation

Elastomers program will either verify that there are no aging effects requiring management for

the subject components, or ensure that the appropriate corrective actions will be taken so that

the component intended functions will be maintained during the period of extended operations.

3.0.3.17.2 Staff Evaluation

In LRA Section B.2.3, "Periodic Inspection of Ventilation Elastomers," the applicant described

its AMP to routinely inspect elastomers for cracking, loss of material, or other evidence of aging

of all flexible boots, access door seals and gaskets, and filter seals and gaskets in the

components of those systems that are within the scope of license renewal. This AMP is not

consistent with a GALL AMP. Therefore, the staff reviewed this AMP against the 10 program

elements using the guidance in the Branch Technical Position RLSB-1 in Appendix A of the

SRP-LR.

The staff reviewed this program using the guidance in Branch Technical Position RLSB-1 in

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Appendix A of the SRP-LR and focused on how the program manages aging effects'through

the effective incorporation of the following 10 elements: scope, preventive actions, parameters

monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria,

corrective actions, confirmation process, administrative controls, and operating experience.

The applicant indicated that the corrective actions, confirmation process,'and administrative

controls for license renewal are in accordance with the site-controlled Quality'Assurance

Program. The staff's evaluation of the applicant's Quality Assurance Program is provided

separately in Section 3.0.4 of this SER; the evaluation of the remaining'seven elements is

provided below. The staff also reviewed the UFSAR supplement to determine whether it

provides an adequate description of the program.

In the second paragraph of the Description section of AMP B.2.3, the applicant stated, "The

improved program for periodic inspection of ventilation system elastomers provides routine

inspection of certain elastomers in ventilation systems in accordance with plant procedures and

predefined tasks." Elastomer wear and degradation of elasticity are functions of material

composition, dynamic load, environment, and time. All elastomer components with the same

material composition/dynamic load/environment will roughly have the same'degree of aging. By

letter dated August 4, 2003, the staff requested, in RAI B.2.3-a, the'applicant to explain what

are the certain elastomers and technical basis for selecting these certain elastomers.

In its response dated October 3, 2003, the applicant stated that the scope of the program

applies to the elastomer seals in the ventilation systems that are in the scope of license

renewal. The in-scope systems for Dresden and Quad Cities are control room ventilation,

station blackout diesel generator building ventilation, and standby gas treatment. Additionally,

the Dresden reactor building ventilation and the Quad Cities emergency diesel generator

building ventilation systems are included. The certain elastomers include flexible boots, access

door seals and gaskets, and RTV used as duct sealant. The basis for selecting these certain

elastomers was to provide an inspection' of the elastomers of in scope ventilation systems. On'

the basis of its review, the staff finds that the applicant's response to B.2.3-a adequate and

acceptable because the applicant explained the technical basis and the types of elastomers

included in the scope of license renewal. The staff considers this issue to be resolved.

[Program Scope] The applicant stated that this AMP is applicable to elastomers utilized in

ventilation systems within the scope of license renewal, including flexible boots, access door

seals, filter seals, and RTV silicone used as a duct sealant. Further the applicant stated (LRA

Section 3.3.1.1.5) that aging management of control room, emergency diesel generator

building, station blackout diesel generator building, and reactor building (using the requirements

of the containment ventilation) ventilation system elastomers will be performed by the periodic

inspection of elastomers in accordance with the plant-specific aging management program

Periodic Inspection of Ventilation System Elastomers. The applicant further states that Exelon

may elect to periodically replace certain ventilation system elastomer and RTV seals instead of

inspecting them and that periodic replacement will be evaluated on a case-by-case basis. By

letter dated August 4, 2003, the'staff requested,' in RAI B.2.3-b, the applicant to provide specific

information such as replacement frequency, replacement criteria and the associated technical

basis, including applicable operating experience about the proposed periodic replacement.

The staff further requested that the applicant describe how the variable combinations of

material composition, dynamic load, and environment will be weighed in determining the

frequency of inspection.

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In its response dated October 3, 2003, the applicant stated that there are no plans or schedules

to perform replacements of ventilation system elastomers at this time and the intent of this

statement in the program scope was to provide the opportunity to credit replacement of

elastomers in lieu of performing the inspection. By letter dated December 17, 2003, the

applicant stated that, upon further evaluation, it does not need to include the flexibility of being

able to replace elastomers in lieu of performing the inspection. Therefore, the applicant will

revise the AMP to delete the flexibility to replace the elastomers. The Scope of Activity for the

Periodic Inspection of Ventilation System Elastomers AMP will be revised as follows:

The program inspects elastomers utilized in ventilation systems within the scope of license renewal,

including flexibility boots, access door seals, filter seals, and RTV used as a duct sealant. These

elastomers prevent external leakage and bypass of HEPA and carbon filters. These inspections apply

to the standby gas treatment system and ventilation systems within the scope of license renewal; that

is, to the main control room ventilation, station blackout diesel generator building ventilation, Dresden

reactor building ventilation, and Quad Cities emergency diesel generator building ventilation systems.

This is part of Commitment #41 of Appendix A of this SER. The staff finds the applicant's

response acceptable because the replacement of elastomers is no longer an options;

therefore, the specific information for replacement of elastomers such as replacement

frequency, replacement criteria and the associated technical basis, including applicable

operating experience about the proposed periodic replacement is not required.

[Preventive Actions] The applicant stated that no actions are taken as part of this program to

prevent the aging effect; the inspections provide condition monitoring to detect degradation

prior to a loss of function. By letter dated August 4, 2003, the staff noted, in RAI B.2.3-e, that

elastomers may crack, harden, or lose strength due to relative motion between vibrating

equipment, exposure to warm moist air, temperature changes, oxygen, and/or radiation and

requested the applicant to clarify if the elastomer components are also used at Dresden and

Quad Cities as vibration isolators to prevent transmission of vibration and dynamic loading to

the rest of the system. If these isolators degrade, vibration and subsequent dynamic loads

applied to the ductwork and fasteners cannot be eliminated. The staff further requested that

the applicant provide the frequency of the subject inspection for the applicable elastomer

components, including a discussion of the operating history to demonstrate that the applicable

aging degradations will be detected prior to the loss of their intended function.

In its response dated October 3, 2003, the applicant stated that elastomer components are not

used in Dresden or Quad Cities HVAC systems as vibration isolators to prevent transmission of

vibration or dynamic loading to the rest of the system. On the basis of its review, the staff finds

that the applicant's response to B.2.3-e adequate and acceptable because the applicant

explained how, since there are no elastomeric isolators, their degradation is not an aging

management issue. The issue is characterized as resolved.

[Parameters Monitored or Inspected] The applicant stated that the parameters inspected as

part of this AMP include elastomers used in ventilation system; flexible boots, access door seals

and gaskets, filter seals and gaskets, and RTV used as a duct sealant are inspected to ensure

they are free of cracking, loss of material, and damage. The seals will be tested for hardening if

cracking or loss of material is noted. This is part of Commitment #41 of Appendix A of this

SER. For the standby gas treatment and main control room ventilation systems, the results of

the elastomer inspections are verified by the performance of system leakage tests and filter

efficiency tests. Since the applicant stated that the condition of elastomers used in ventilation

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systems will be determined by visual inspection, by letter dated August 4, 2003, the staff

requested, in RAI B.2.3-f, the applicant to'explain how this visual inspection will be conducted in

the inaccessible areas.

In its response dated October 3, 2003, the applicant stated that all elastomer components with

the same material composition/dynamic load/environment would roughly have the same degree

of aging. Therefore, the inspections of the accessible areas bound the inaccessible areas.

When unacceptable age related degradation is found, the impact of the degradation will be

evaluated for the remaining (inaccessible) portions of that system. On the basis of its review,

the staff finds that the applicant's response to RAI B.2.3-f adequate and acceptable because

the applicant explained how information from accessible areas would be extrapolated to

inaccessible areas. The staff considers RAI B.2.3 to be resolved.

[Detection of Aging Effects] The applicant stated that the AMP will rely on inspections of

elastomers performed at intervals sufficient to detect aging prior to the equipment failing a

leakage test or filter efficiency test and that seals will be inspected for hardening if cracking or

loss of material is observed. The applicant further states, in LRA Section 3.3.1.1.5, that the

AMP will manage the aging of elastomeric components due to hardening and cracking or loss

of strength due to elastomer degradation or loss of material due to wear for the period of

extended operation. Since the AMP does not contain a statement that the inspection will be

conducted by qualified personnel, or reference to authoritative criteria to detect hardening or

cracking due to elastomer degradation or loss of material due to wear, by letter dated August 4,

2003, the staff requested, in RAI B.2.3-c, the applicant to address this issue.

In its response dated October 3, 2003, the applicant stated that personnel that have been

trained and qualified in accordance with station procedures perform these examinations. The

inspections visually look for evidence of cracking and loss of material. When indications are

found, additional examinations are performed for hardening of the material. On the basis of its

review, the staff finds that the applicant's response to B.2.3-c adequate and acceptable

because the applicant verified that qualified personnel would conduct the inspection. The staff

considers this RAI B.2.3-c to be resolved.

[Monitoring and Trending] The applicant stated that the conditions of the elastomers used in

ventilation systems are monitored, but not trended and that flexible boots, filter seals, and

access door seals and gaskets are repaired or replaced if damage or deterioration is detected.

The staff finds the above monitoring acceptable; the staff did not identify the need for trending

in this AMP.

[Acceptance Criteria] The applicant stated that the acceptance criteria are no unacceptable

cracking, loss of material, and damage. The seals will be inspected for hardening if cracking or

loss of material is observed and repaired or replaced if a degraded condition is found.

Surveillance tests of the standby gas treatment and main control room ventilation systems

ensure that system leakage meets the requirements of the current licensing basis. Since the

AMP does not specifically refer to an acceptance criterion to evaluate indications related to

hardening or cracking due to elastomer degradation or loss of material due to wear, by letter

dated August 4, 2003, the staff requested, in RAI B.2.3-d, the applicant to address this issue.

In its response dated October 3, 2003, the applicant stated that the elastomers are inspected

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for signs of cracking, loss of material, damage, or other abnormal conditions. If signs of

cracking or loss of material is noted then an inspection for hardness is performed. Discrepant

conditions are recorded in the corrective action program for further evaluation and disposition.

On the basis of its review, the staff finds that the applicant's response to B.2.3-d adequate and

acceptable because the applicant explained its procedure for identifying and recording

discrepant conditions in the corrective action program for further evaluation and disposition. The

staff considers RAI B.2.3-d to be resolved.

[Operating Experience] The applicant stated that Dresden and Quad Cities have experienced

leaks in ventilation systems due to deterioration of or damage to elastomers, including flexible

boots and access door seals and gaskets. The leaks were found and corrected in a timely

manner and did not result in a loss of function of the ventilation system train. By letter dated

August 4, 2003, the staff requested, in RAI B.2.3-g, the applicant to discuss how the program

has been modified to avoid seepage or leakage through boots, seals, and gaskets.

In its response dated October 3, 2003, the applicant stated that the operating experiences

summarized in element 10 of B.2.3 are indicative of an effective program identifying age related

degradation prior to loss of intended function of a component and taking appropriate and timely

corrective action. As such, there were no program enhancements made. However, the

applicant noted that some of the specific examples cited include:

* In 1987, Dresden identified minor leakage in the reactor building ventilation access doors.

The door seals were replaced and stiffeners were added to the door.

* In 1988, Dresden identified cracking in some HVAC system piping flexible boot seal. All of

the HVAC system piping flexible boot seals were replaced.

* In 1988, Dresden identified minor leakage in the reactor building ventilation inspection

doors. The door seals were replaced and new latches were installed.

* In 1994, Quad Cities identified a high efficiency particulate air (HEPA) filter door leak. The

damaged door and seal were replaced.

* In 1996, Quad Cities identified minor leakage in the standby gas treatment access doors.

The doors were re-adjusted and the seals were replaced.

On the basis of its review, the staff finds that the applicant's response to B.2.3-g adequate and

acceptable because the applicant explained and provided examples of how the program

adequately provides remediation to any seepage or leakage through boots, seals, and gaskets.

The issue is characterized as resolved.

The staff reviewed the UFSAR supplement in LRA Appendix A.2.3 and found that the

description of the periodic inspection of ventilation system elastomers is consistent with Section

B.2.3 of the LRA. The staff finds that the information provided in the UFSAR supplement

provides an adequate summary of the program activities as required by 10 CFR 54.21 (d).

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3.0.3.17.3 Conclusions

On the basis of its review of the applicant's program, the staff finds that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP.

and finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.18 Periodic Inspection of Components Subject to Moist Environments (B.2.9)

3.0.3.18.1 Summary of Technical Information in the Application

The applicant's Periodic Inspection of Components Subject to Moist Environments program is

discussed in the applicant's letter dated March 25, 2004. This program manages loss of

material for stainless steel, carbon steel, cast iron, aluminum, copper, brass, and bronze

components in various systems exposed to moist air environments and subject to wetting

conditions based on system operation. The program also inspect flexible hoses for age-related

degradation. Thickness measurements and visual inspections will be used to detect

degradation. The periodic inspections will be performed once before the end of the current

operating term and periodically at intervals of approximately every 10 years during the period of

extended operation. The program is not based on a GALL report program; therefore, the

applicant summarized the program in terms of the 10-element program as described in Branch

Technical Position, Appendix A of the SRP-LR.

The applicant concluded that periodic inspections of selected components exposed to alternate

wetting and drying conditions are representative of the population of components normally

exposed to most air environments. The Periodic Inspection of Components Subject to Moist

Environments program provides reasonable assurance that the components are routinely

inspected for deterioration and corrective action is taken to maintain the intended functions

consistent with the current licensing basis during the period of extended operation.

3.0.3.18.2 Staff Evaluation

By letter dated March 25, 2004, the applicant described the Periodic inspection of Components

Subject to Moist Environments program to manage the loss of material for stainless steel,

carbon steel, cast iron, aluminum, copper, brass, and bronze components and degradation

(such as elastomer hardening or cracking) of flexible hoses located in moist air environments

and subject to wetting conditions. Ultrasonic and visual inspections will be performed on

selected carbon steel and cast iron components as representative samples for all materials

managed by this program since these materials have a greater susceptibility to loss of material.

The staff reviewed this program using the guidance in Branch Technical Position RLSB-1 in

Appendix A of the SRP-LR and focused on how the program manages aging effects through

the effective incorporation of the following 10 elements: program scope, preventive actions,

parameters monitored or inspected, detection of aging effects, monitoring and trending,

acceptance criteria, corrective actions, confirmation process, administrative controls, and

operating experience. The applicant indicated that the corrective actions, confirmation process,-

and administrative controls are part of the site-controlled Quality Assurance Program. The

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staff's evaluation of the Quality Assurance Program is provided separately in Section 3.0.4 of

this SER. The remaining seven elements are discussed below. The staff also reviewed the

UFSAR supplements for Dresden and Quad Cities to determine whether they provide an

adequate description of the program.

[Program Scope] The applicant stated that this program will manage age related degradation of

selected components such as piping and fittings, valves, turbine casings, flexible hoses,

filter/strainers, air accumulator vessels, and mufflers normally exposed to moist air

environments. These components are located in various systems. The staff finds that the

scope is acceptable because it includes those components that rely on the program for aging

management.

[Preventive or Mitigative Actions] The applicant's program monitors the condition of the

components and does not provide preventative or mitigative actions. This is a condition

monitoring program that does not rely on preventative or mitigative actions; therefore, the staff

finds this acceptable.

[Parameters Monitored'or Inspected] The applicant stated that the program would perform

periodic thickness measurements (UT) of a representative sample of steel piping, fittings, and

air accumulator vessels, and periodic visual inspections (VT-3) of a representative sample of

valves, filters/strainers, and mufflers to determine if aging degradation is occurring. The

components are inspected to ensure they are free of unacceptable loss of material dueto

general corrosion, pitting and crevice corrosion. Inspections will be performed in accordance

with ASME Code requirements and certified NDE examiners will conduct UT and VT-3

inspections. Visual inspections of flexible hoses will be performed to determine the presence of

age-related degradation. The staff concludes that the applicant is inspecting the appropriate

parameters to identify the aging effects; therefore, the staff finds this acceptable.

[Detection of Aging Effects] The applicant stated that periodic thickness measurements and

visual inspections will be performed to determine if loss of material aging degradation is

occurring to the interior surfaces of selected components subject to moist air environments.

The applicant also stated that visual inspections of the flexible hoses will be performed to

determine any age-related degradation of the flexible hose. If the hoses exhibit such

degradation, they will be replaced. The staff concludes that the applicant is inspecting the

appropriate parameters to detect the aging effects; therefore, the staff finds this acceptable.

[Monitoring and Trending] The applicant states that periodic inspections will be performed once

before the end of the current operating term and at intervals of approximately every 10 years

during the period of extended operation. Abnormal corrosion or pitting found during visual

inspections will be evaluated by engineering to determine if loss of material aging is occurring,

and if so, the rate at which the material is being lost. Engineering evaluations of the test or

inspection results will determine the need for follow-up examinations to monitor the progression

of aging degradation, and identify appropriate corrective actions to mitigate any excessive rates

of loss of material discovered. The staff finds the periodic inspection and engineering

evaluation of material loss is acceptable for monitoring these aging effects.

[Acceptance Criteria] The applicant stated that Engineering will determine the component

thickness measurement acceptance criteria prior to conducting the examinations. Thickness

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measurements will be conducted in accordance with approved plant procedures and will be

consistent with ASME Code requirements. Results of the UT examinations and abnormal

corrosion or pitting found during visual inspections will be evaluated by engineering to

determine if loss of material aging is occurring, and if so, the rate at which the material is being

lost. Engineering evaluations of the test or inspection results will determine the need for'followup examinations to monitor the progression of aging degradation, and identify appropriate

corrective actions to mitigate any excessive rates of loss of material discovered. Corrective

actions, if necessary, would expand to include other components. Any degradation (such as

elastomer hardening or cracking) found during the inspection of flexible hoses requires an

Engineering evaluation to determine acceptance criteria. Corrective actions will include

replacement and, if necessary, inspection of additional hoses. The staff finds that the

applicant's proposal to perform engineering evaluations of degradation for plant heating system

piping components and hoses will provide acceptance criteria against which the need for

corrective actions will be evaluated; therefore, staff finds this acceptable.

[Operating Experience] Dresden and Quad Cities have experienced age-related degradation of

components exposed to moist air environments. The degradation was found during routine

maintenance activities, corrected in a timely manner and did not result in a loss of function of

any safety-related systems, structures or components (SSCs). The staff finds that the

operating experience supports the conclusion that the Periodic Inspection of Components

Subject to Moist Environments program used in conjunction with routine maintenance is

effective at preventing age-related degradation of components exposed to moist air

environments; therefore, the staff finds this acceptable.

3.0.3.18.3 Conclusion

On the basis of its review of the applicant's program, the staff finds that the program'

adequately addresses the ten program elements defined in Branch Technical Position RLSB-1

in Appendix A.1 of the SRP-LR, and that the program will adequately manage the aging effects

for which it is credited. The staff also reviewed the UFSAR supplement for this aging'

management program and finds that it provides an adequate summary description of the

program, as required by 10 CFR 54.21(d).

Therefore, on the basis of its review, the staff finds that the applicant has demonstrated that the

effects of aging will be adequately managed by the Periodic Inspection of Components Subject

to Moist Environments program so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.0.4 Quality Assurance for Aging Management Programs

Pursuant to 10 CFR 54.21 (a)(3), a license renewal applicant is required to demonstrate that the

effects of aging on structures and components subject to an Aging Management Review (AMR)

will be adequately managed so that their intended functions will be maintained consistent with

the CLB for the period of extended operation. NUREG-1800, Branch Technical Position ' '

RLSB-1, "Aging Management Review - Generic," describes ten attributes of an acceptable '

aging management program. Three of these ten attributes are associated with the quality

assurance activities of corrective action, confirmation processes, and administrative controls.

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Table A.1-1, "Elements of an Aging Management Program for License Renewal," of Branch

Technical Position RLSB-1 provides the following description of these quality attributes:

* corrective actions, including root cause determination and prevention of recurrence, should

be timely

* the confirmation process should ensure that preventive actions are adequate and that

appropriate corrective actions have been completed and are effective

* administrative controls should provide a formal review and approval process

NUREG-1 800, Branch Technical Position IOMB-1, "Quality Assurance For Aging Management

Programs," noted that those aspects of the aging management program that affect quality of

safety-related structures, systems, and components are subject to the quality assurance (QA)

requirements of 10 CFR Part 50 Appendix B. Additionally, for non-safety-related structures and

components subject to an aging management review, the existing 10 CFR Part 50 Appendix B

QA program may be used by the applicant to address the elements of corrective actions, the

confirmation process, and administrative controls. Branch Technical Position IQMB-1 provides

the following guidance with regard to the quality assurance attributes of aging management

programs:

* Safety-related structures and components are subject to. 10 CFR Part 50 Appendix B

requirements, which are adequate to address all quality-related aspects of an aging

management program consistent with the CLB of the facility for the period of extended

operation.

* For non-safety-related structures and components that are subject to an AMR for license

renewal, an applicant has an option to expand the scope of its 10 CFR Part 50 Appendix B

program to include these structures and components to address corrective actions, the

confirmation process, and administrative controls for aging management during the period

of extended operation. In this case, the applicant should document such a commitment in

the UFSAR supplement in accordance with 10 CFR 54.21 (d).

3.0.4.1 Summary of Technical Information in the Application

Chapter 3.0, "Aging Management Review Results," of the LRA provides an AMR summary for

each unique structure, component, or commodity group at the Dresden and Quad Cities

Nuclear Power Stations determined to require aging management during the period of

extended operation. This summary includes identification of aging effects requiring

management and AMPs utilized to manage these aging effects. Appendix B to the LRA

demonstrates how the identified programs manage aging effects using attributes consistent

with the industry and NRC guidance. The applicant's programs and activities that are credited

with managing the effects of aging can be divided into two types of programs: (1) aging

management programs evaluated in NUREG-1801, and (2) plant-specific aging management

programs. Aging management program evaluated in NUREG-1 801 are described in

Appendices A.1 and B.1 of the LRA while plant specific aging management programs are

described in Appendices A.2 and B.2 of the LRA.

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In Section A.2.1," Corrective Action Program," of the LRA, the applicant describes the quality

attributes of the plant specific aging management programs. The applicant stated that the

10 CFR Part 50, Appendix B program provides corrective actions, confirmation processes, and

administrative controls for license renewal aging management programs. Additionally, prior to

the period of extended operation the scope of the program will be expanded to include

non-safety-related structures and components that are subject to an aging management review

for license renewal. The applicant stated that the corrective action program applies to all plant

systems, structures and components (both safety-related and non-safety-related) within the

scope of license renewal. Administrative controls are in place for existing aging management

programs and activities. Administrative controls will also be applied to new and enhanced

programs and activities as they are implemented.

In Section B.2.1, 'Corrective Action Program," of the LRA, the applicant provided the following

generic description of the quality attributes common to all the plant specific aging management

programs:

* Corrective Actions: Corrective action is initiated following the identification of conditions

adverse to quality, and is documented. The corrective action program is described in

Chapter 16 of the QAP. The various components of the corrective action program provide

for timely actions, including determination of the cause of the condition and corrective action

taken to preclude recurrence for significant conditions adverse to quality. Condition reports

are analyzed for adverse trends. Identified adverse trends are reported to the appropriate

manager and documented on a condition report.

* Confirmation Process: Condition reports are reviewed by supervisors. Operations shift

management is contacted as necessary to discuss potential operability or regulatory

reportability of the condition. Items determined to be significant conditions adverse to

quality are reported to the appropriate levels of management. An effectiveness review is

completed for root cause analysis corrective actions to prevent recurrence.

* Administrative Controls: Activities affecting quality are prescribed by documented

instructions, procedures, drawings, or specifications of a type appropriate to the

circumstances and are accomplished in accordance with these instructions, procedures,

drawings or specifications. They contain appropriate acceptance criteria and

documentation requirements for determining whether important activities have been

satisfactorily accomplished. The document control process is described in Chapter 6 of the

QAP.

3.0.4.2 Staff Evaluation

The NRC staff reviewed the applicant's aging management programs described in Appendix A,

"Updated Final Safety Analysis Report (UFSAR) Supplement," and Appendix B, "Aging

Management Activities," of the Dresden and Quad Cities license renewal application. The

purpose of this review was to assure that the aging management activities were consistent with

the staff's guidance described in NUREG-1 800, Section A.2, "Quality Assurance for Aging

Management Programs (Branch Technical Position IQMB-1)," regarding quality assurance

attributes of aging management programs. Based on the staff's evaluation, the descriptions

and applicability of the plant-specific aging management programs and their associated quality

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attributes provided in Appendix A.2 and Appendix B.2 of the LRA are consistent with the staff's

position regarding quality assurance for aging management. However, the applicant did not

sufficiently describe the use of the quality assurance program and its associated attributes

(corrective action, confirmation process, and administrative controls) in the discussions

provided for aging management programs described in Appendix A.1 and Appendix B.1. In RAI

2.1-4, the staff requested that the applicant supplement the descriptions in the Appendix A,

"Updated Final Safety Analysis Report (UFSAR) Supplement," and Appendix B, "Aging

Management Activities" to include a'description of the quality assurance program attributes,

including references to pertinent implementing guidance as necessary, which are credited for

the programs described in Appendix A.1 and Appendix B.1 of the LRA.

In their October 3, 2003, response to RAI 2.1-4, the applicant stated that the LRA Sections

A.2.1 and B.2.1, "Corrective Action Program," apply to all of the aging management programs

and activities that are credited for license renewal and to all plant systems, structures and

components within the scope of license renewal. Based on this response, the staff concluded

that the applicant will apply the corrective action program, as described in LRA Sections A.2.1

and B.2.1, to all plant systems, structures and components (both safety-related and non-safetyrelated) within the scope of license renewal and subject to the AMPs described in Section A.1

and B.1 of the LRA. Therefore, RAI 2.1-4 is resolved.

3.0.4.3 Conclusions

The staff finds that the quality assurance attributes of the applicant's AMPs are consistent with

10 CFR 54.21 (a)(3) and the staff's BTP IQMB-1. Specifically, the applicant described the

quality attributes of the programs and activities for managing the effects of aging for both

safety-related and non-safety-related SSCs within the scope of license renewal. The applicant

further stated that the 10 CFR Part 50 Appendix B Quality Assurance Program provides

corrective actions, confirmation processes, and administrative controls. The staff also reviewed

the UFSAR Supplement for this AMP and finds that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

3.0.4.4 References

1. NUREG-1800, Standard Review Plan for Review of License Renewal Applications for

Nuclear Power Plants," April 2001

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

Part 54 - The License Renewal Rule," August 2001

3. Letter from Exelon Generation Company, LLC, to US NRC, "Additional Information for the

Review of the License Renewal Applications for Quad Cities Nuclear Power Station, Units 1

and 2 and Dresden Nuclear Power Station, Units 2 and 3," RS-03-178, dated October 3,

2003

3.0.5 Aging Management Review for Additional In-Scope Components

The staff's evaluation of the mechanical systems included in the LRA is documented in SER

Sections 3.1, 3.2, 3.3, and 3.4. Additional mechanical systems and components were added to

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the scope of license renewal during the closeout of Open Item 2.1-1. This open item relates to

the applicant's methodology utilized for scoping under 10 CFR 54.4(a)(2) of low to moderate

energy systems in the vicinity of safety-related systems. The applicant's original criterion was

that spray or wetting from a non-safety-related moderate-energy system could only affect

active, safety-related components located within 20 feet. In response to the open item, by letter

dated May 18, 2004, the applicant revised the methodology and assumed that all safety-related

components, active or passive, located in the same general area of the plant could be

adversely affected. As a result, additional systems and components were brought into the

scope of license renewal. The applicant provided additional information by letter dated June

22, 2004.

The applicant stated that all of the aging management programs were evaluated for impact

resulting from the scoping changes. The applicant determined that, because all of the scoping

changes involved the addition of similar equipment in the same environments as those already

included in the LRA, only one aging management program had to be revised. The Generator

Stator Water Chemistry Activities AMP (B.2.7) had previously only applied to Quad Cities, but

was revised to apply to Dresden also. The staff' s review of the Generator Stator Water

Chemistry Activities program is in Section 3.4.2.3.1 of this SER.

The staff's review of each system affected by the change in scoping is described below:

Reactor Recirculation System

Additional piping and components from the reactor recirculation system were added to the

scope of license renewal at Quad Cities due to the potential for spatial interaction with safety

related components. Specifically, the recirculation motor generator oil subsystem was added to

the scope of license renewal at Quad Cities. The system did not require a boundary expansion

at Dresden because the physical plant layout is different than Quad Cities. As a result of the

scoping change, the applicant added component groups for pumps and tanks for spacial

interaction (Quad Cities only) to LRA Table 2.3.3-1. The applicant also added three new (e.g.,

not previously in the LRA) AMR references to address the new component groups.

To address the general corrosion of the external surfaces of carbon steel and cast iron

components, the applicant credits the Bolting Integrity AMP (B.1.12) or the Structures

Monitoring AMP (8.1.30). These AMPs were evaluated in Sections'3.0.3.5 and 3.0.3.14 and

found to be acceptable for managing this aging effect. To address the corrosion of cast iron

and carbon steel components in lubricating oil (with contaminants and/or moisture), the

applicant proposed to credit the One-Time In-spection AMP (8.1.23). Since the degradation of

components in an oil environment depends upon the quality of the oil (contaminants and water),

the staff asked about the applicant's controls on the quality of the oil. In its response, the

applicant stated that the components would be included in the Lubricating Oil Monitoring

Activities AMP (8.2.5), which is evaluated in Section 3.0.3.16 of this SER. Since there are

adequate controls on the oil qualify, the staff finds the-proposed aging management

acceptable. The staff finds that the applicant has identified the applicable aging effects'and has

proposed adequate aging management for the components in the expanded scope of the

reactor recirculation system.

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On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Control Rod Drive Hydraulic System

The applicant expanded the system boundaries for the control rod drive hydraulic system at

both Dresden and Quad Cities due to the potential for spatial interaction with safety related

components. The resulting changes to the LRA Table 2.3.3-3 include four additional

component groups and one additional aging management reference for valves. The new

component groups are filters/strainers, pumps, tubing, and restrictive orifices for spacial

interaction for Quad Cities only. The same components at Dresden are already in scope with a

pressure boundary intended function (which bounds the spacial interaction intended function).

The staff reviewed the AMR of the new component groups and the additional AMR references.

All of the AMR references for the component groups in the expanded scope were already being

used for the same combinations of materials and environments in the control rod drive hydraulic

system, and had been previously reviewed by the staff, as discussed in SER Section 3.3.2.4.3.

Therefore, the staff finds that the applicant has identified the applicable aging effects and has

proposed adequate aging management for the components in the expanded scope of the

control rod hydraulic system.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Reactor Water Clean ut System

The applicant stated that additional piping and components from the reactor water clean up

system were added to the scope of license renewal at Dresden due to the potential for spatial

interaction with safety related equipment. The applicant further stated that this boundary

expansion includes more of the same type of components already represented on Table 2.3.3-4

of the LRA. The applicant concluded that no changes to Table 2.3.3-4 were required.

Since there were no changes to Table 2.3.3-4 of the LRA, the finds that the applicant has

identified the applicable aging effects and has proposed adequate aging management for the

components in the expanded scope of the reactor water cleanup system.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Diesel Generator Cooling Water System

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For the diesel generator cooling water system, the system boundary was expanded to include

additional components in the scope of license renewal. This resulting change to Table 2.3.3-12

of the LRA was the addition of two new component groups and one additional AMR reference

for on existing component. The new component groups are piping and fittings, and tanks for

spacial interaction.

The staff reviewed the AMR of the new component group and the additional AMR reference for

existing component groups. The additional AMR references for the diesel generator cooling

water system include appropriate aging effects and aging management programs necessary to

manage those aging effects, where applicable. On the basis of its review, the staff finds that the

applicant has identified the applicable aging effects and has proposed adequate aging

management for the components in the expanded scope of the diesel generator cooling water

system.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21(a)(3).

Service Water System

For the service water system, the system boundary was expanded to include additional

components in the scope of license renewal. The resulting changes to Table 2.3.3-16 of the

LRA include in new component groups and additional AMR references for existing component

groups. The new component groups include strainer bodies, tanks, and tubing for spacial

interaction. The applicant clarified that the component group for piping and fittings includes

heat exchanger shells.

The staff reviewed the AMR of the new component groups and the additional AMR references

for existing component groups. All of the AMR references were already being used for the

service water system and had been previously reviewed and approved by the staff for

components in the service water system, as discussed in SER Section 3.3.2.4.16. Therefore,

the staff finds that the applicant has identified the applicable aging effects and has proposed

adequate aging management for the components in the expanded scope of the service water

system.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Reactor Building Closed Cooling Water System

The applicant expanded the system boundaries for the reactor building closed cooling water

system at both Dresden and Quad Cities. The resulting changes to Table 2.3.3-17 of the LRA

include new component groups and a revision to existing component groups (to delete "Quad

Cities only'). The new component groups include pumps, tubing, and tanks for spacial

interaction.

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The staff reviewed the AMR of the additional component groups and the additional AMR

references for existing component groups. All of the AMR references for the component

groups in the expanded scope were already being used for the same combinations of materials

and environments in the reactor building closed cooling water system, and had been previously

reviewed and approved by the staff, as discussed in SER Section 3.3.2.4.17. Therefore, the

staff finds that the applicant has identified the applicable aging effects and has proposed

adequate aging management for the components in the expanded scope of the reactor building

closed cooling water system.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Turbine Building Closed Cooling Water System

For Dresden, the applicant stated that additional components were added to the scope of

license renewal. At Dresden the added components include all of the turbine building closed

cooling pumps, heat exchangers, piping, valves, surge tank, and other passive system

components. For Quad Cities, where this system had previously been excluded from the scope

of license renewal at Quad Cities, the system has been added. At Quad Cities the added

components include all of the turbine building closed cooling pumps, heat exchangers, piping,

valves, surge tank, and other passive system components.

The resulting changes to Table 2.3.3-18 of the LRA include the addition of four new component

groups and two new aging management references. These new component groups include

piping and fittings (includes heat exchanger shells), valves, pumps, and tanks for spacial

interaction. The two new AMR reference numbers are 3.3.2.211 and 3.3.2.319.

The staff reviewed the AMR of the additional new component groups and the additional AMR

references for existing component groups. Except for new (e.g., not previously used in the

LRA) AMR references 3.3.2.21 1 and 3.3.2.319, all of the AMR references for the component

groups in the expanded scope were already being used for the same combinations of materials

and environments in the turbine building closed cooling water system, and had been previously

reviewed by the staff, as discussed in SER Section 3.3.2.4.18. The combinations of material,

environment, and aging effect addressed by new AMR reference 3.3.2.211 is adequately

covered in SER Section 3.3.2.4.18. New AMR reference 3.3.2.319 addresses crack initiation

and growth/SCC and IGSCC of cast iron components in chemically treated demineralized

water, and credits the Closed-Cycle Cooling Water System AMP (B. 1.14). The staff finds the

Closed-Cycle Cooling Water System AMP appropriate and acceptable for this aging effect, as

identified in SER Section 3.0.3.7. Therefore, the staff finds that the applicant has identified the

applicable aging effects and has proposed adequate aging management for the components in

the expanded scope of the turbine building closed cooling water system.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21(a)(3).

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Demineralized Water Makeu, System

For the demineralized water makeup system, additional piping and components were added to

the scope of license renewal. This resulted one new component group and additional AMR

references for existing component groups. The new component group is tubing for spacial

interaction.

The staff reviewed the AMR of the new component group and the additional AMR references

for existing component groups. The staff finds that the additional AMR references for the

demineralized water makeup system include appropriate aging effects and aging management

programs necessary to manage those aging effects, where applicable.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Residual Heat Removal Service Water System

Section 2.3.3.20 of the LRA describes the Residual Heat Removal (RHR) Service Water system

(Quad Cities only) which was originally included within the scope of license renewal. The RHR

service water pumps are contained in vaults that have non-safety related sumps. Using the

revised scoping methodology, the applicant determined that the sump pumps and associated

piping can spatially interact with the safety related RHR service water pumps. Therefore, the

RHR service water system boundary was expanded to include additional components in the

scope of license renewal. This resulted in new component groups and additional AMR

references for existing component groups. The new component groups include NSR vents or

drains, piping, valves and pumps for spacial interaction.

The staff reviewed the AMR of the new component groups and the additional AMR references

for existing component groups. All of the AMR references were already being used for the

RHR service water system and had been previously reviewed by the staff, as discussed in SER

Section 3.3.2.4.20. Therefore, the staff finds that the applicant has identified the applicable

aging effects and has proposed adequate aging management for the components in the

expanded scope of the RHR service water system.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Fuel Pool Cooling and Filter Demineralizer System

The applicant stated that the revised scoping methodology affected the fuel pool cooling and

filter demineralizer system at both Dresden and Quad Cities. At Dresden, additional piping and

components were added to the scope of license renewal. At Quad Cities, the system was

brought into scope.

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The resulting changes to Table 2.3.3-23 of the LRA include the addition of one component

group (pumps for spacial interaction) and several aging management references to existing

component groups. The statements "Dresden only" were deleted from component groups that

are also applicable to Quad Cities, due to the new scoping, and a clarification was added that

piping and fittings includes heat exchanger shells.

The staff reviewed the AMR of the new component group and the additional AMR references

for existing component groups. The staff finds that the additional AMR references for the fuel

pool cooling and filter demineralizer system include appropriate aging effects and aging

management programs necessary to manage those aging effects, where applicable.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Plant Heating System

For the plant heating system, additional piping and components were added to the scope of

license renewal. The applicant stated that this boundary expansion includes more of the same

type of components already represented on Table 2.3.3-24 of the LRA, such that no changes to

Table 2.3.3-24 were required.

Since all of the AMR references for the component groups in the expanded scope were already

being used for the same combinations of materials and environments in the plant heating

system, and had been previously reviewed by the staff, as discussed in SER Section 3.3.2.4.24,

the staff finds that the applicant has identified the applicable aging effects and has proposed

adequate aging management for the components in the expanded scope of the control rod

hydraulic system.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Circulating Water System

The circulating water system was added to the scope of license renewal due to the potential for

a portion of the system to have spacial interactions with a safety-related system. For Quad

Cities, only the Unit 1 circulating water system is in scope. For Dresden, the system is in scope

for Units 2 and 3. Aging management of the passive, long-lived components is provided by

new Table 2.3.3-29. The component groups include piping and fittings, valves, and pumps

(pumps are for Dresden only) for spacial interaction.

For various materials (can include carbon steel, aluminum-bronze, brass, copper-nickel, and/or

stainless steel) in raw water covered by the GALL (AMR Reference 3.3.1.15), the applicant

uses the Open Cycle Cooling Water System AMP (B.1.13) to manage the loss of material due

to general, pitting, crevice, and galvanic corrosion, MIC, biofouling, and buildup of deposit due

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to biofouling, which is consistent with the GALL recommendations.. For the cast iron pumps in

raw water, which are not addressed by GALL, the applicant uses the Open Cycle Cooling Water

System AMP (B.1.13) and the Selective Leaching of Material AMP (B.1.24) to address the loss

of material. For the external surfaces of carbon steel, low-alloy steel, or cast iron, the applicant

credits the walkdowns and other activities in the Bolting Integrity AMP (6.1.12), Structures

Monitoring AMP (B.1.30), or the Open Cycle Cooling Water System AMP (B.1.13) to manage

the loss of material.

The staff reviewed the AMR of the new component groups. All of the AMR references were

already being used for other auxiliary systems and had been previously reviewed by the staff,

as discussed in SER Section 3.3. On the basis of its review, the staff finds that the applicant

has identified the applicable aging effects and has proposed adequate aging management, for

the components in the circulating water system.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Laundry Treatment System (Dresden only)

The laundry treatment system at Dresden was brought into the scope of license renewal due to

the potential for a portion of the system to have spacial interactions with a safety-related

system. The discharge piping used to transfer water to the radwaste system is located in the

same general areas as safety-related electrical switchgear. Aging management of the passive,

long-lived components is provided by new Table 2.3.3-30. The only component group is piping

and fittings for spacial interaction.

The AMR for the piping and fittings uses AMR Reference 3.3.2.130, which uses the One-Time

Inspection AMP (6.1.23) to manage the loss of material of carbon steel, stainless steel, brass,

or bronze in air, moisture, humidity, and leaking fluid. In RAI B.1.23-2.2, the staff asked for

additional justification for the use of a one-time inspection for such items as carbon steel vents,

drains, piping, and valves in moisture, humidity, and leaking fluid. By letter dated January 26,

2004, the applicant stated that the corrosion rates would be sufficiently slow because the

components are attached to normally closed isolation valves and are not expected to contain

moisture. The applicant also stated that the vents were periodically operated and monitored

during operation, and any appreciable leakage or condensation would be identified and

corrective actions initiated, if applicable. From this, the staff concurred that the rate of

corrosion would be slow and that the rate would not change significantly over time. The staff

asked how the above justification applied to the components in the laundry treatment system.

By letter dated June 22, 2004, the applicant stated that .the portion of laundry drain system that

was brought into scope is infrequently operated (approximately quarterly) and has the same

operating environment as the rest of the vents and drains. Based on the above, the staff.

agrees that the corrosion should be slow and relatively constant for this system, such that a

one-time inspection is acceptable to manage the corrosion. On the basis of its review, the staff

finds that the applicant has identified the applicable aging effects and has proposed adequate

aging management for the components in the laundry treatment system.

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On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Zinc Iniection System

The zinc injection system was added to the scope of license renewal due to the potential for

spacial interactions with safety-related systems. The system is mounted on a skid near the

reactor feedwater pumps. The system boundary includes the all associated piping, inline

manual isolation globe valves, rupture discs, and strainers. Aging management of the passive,

long-lived components is provided by new Table 2.3.3-31. The component groups include

piping and fittings, tubing, and valves for spacial interaction.

For the external surfaces of carbon steel or low-alloy steel, the applicant credits walkdowns in

the Bolting Integrity AMP (B.1.12) and Structures Monitoring AMP (B.1.30) to manage the loss

of material. For carbon steel and stainless steel in treated water, the applicant credits the

Water Chemistry AMP (B.1.2) and the One-Time Inspection AMP (B.1.23) to mange the loss of

material. The applicant does not identify any AERMs for stainless steel in moist air.

The staff reviewed the AMR of the new component groups. On the basis of its review, the staff

finds that the applicant has identified the applicable aging effects and has proposed adequate

aging management, for the components in the zinc injection system.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Main Steam System

For the main steam system, the system boundary was expanded to include additional

components in the scope of license renewal. Through plant walkdowns, the applicant identified

main steam instrumentation racks and (for Dresden) steam lines that feed the radwaste

reboilers that are in the general areas containing safety-related components. This resulted in

new component groups being brought into the scope of license renewal. The new component

groups include piping and fittings, tubing, and valves for spacial interaction.

The staff reviewed the AMR of the new component groups. The staff questioned the use of

AMR reference 3.4.1.2, which was not previously used for this system. For the expanded

scope of the main steam system, this GALL reference is used for piping and valves in the

steam lines to the radioactive waste reboilers. This reference is for corrosion of carbon steel

and stainless steel in steam or treater water environments, and the GALL recommends further

evaluation of this aging effect. The applicant discussed its further evaluation in Section

3.4.1.1.2 of the LRA, which lists several plant locations where the one-time inspections will be

performed. These are areas that are generally exposed to stagnant water that occasionally

experience flow to replenish the oxygen supply, and the staff questioned how these locations

were bounding for the main steam system.

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By letter dated June 22, 2004, the applicant responded that the flow through the new

components is intermittent and that the components use 2 AMR references, 3.4.1.2 and

3.4.1.4. Reference 3.4.1.2 addresses the general corrosion for the periods when the water is

stagnant. Reference 3.4.1.4 (flow accelerated corrosion) addresses corrosion due to the flow

of high moisture steam when the radioactive waste reboilers are operating. The applicant also

stated that the locations identified in LRA Section 3.4.1.1.2 are the same materials, are

exposed to the same fluids, and experience flow to replenish oxygen more frequently than the

components in the main steam system. Based on the above, the staff concludes that the

locations identified in LRA Section 3.4.1.1.2 are acceptable as leading indicators of corrosion

due to stagnant conditions in the main steam system. On the basis of its review, the staff finds

that the applicant has identified the applicable aging effects and has proposed adequate aging

management, for the components in the main steam system.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Feedwater System

For the feedwater system, the scope was expanded to include the entire feedwater system at

both Dresden and Quad Cities, including the sample lines. This resulted in adding AMR

references to existing component groups and adding new component groups. The new

component groups are pumps and tubing for spacial interaction.

The staff reviewed the additional AMR references and the AMR of the new component groups.

All of the AMR references had been previously used for the SPCS, as discussed in SER

Section 3.4.2.4. Therefore, the staff finds that the applicant has identified the applicable aging

effects and has proposed adequate aging management, for components in the feedwater

system.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21(a)(3).

Condensate and Condensate Storage System

For the condensate and condensate storage system, the scope was expanded to include the

condensate transfer pumps, condensate jockey pumps, and associated suction and discharge

piping. As a result, almost the entire system is in the scope of license renewal. The exceptions

are the condensate demineralizers, steam jet air ejectors, and gland seal condensers, all of

which reside in their own rooms isolated from safety-related equipment, and the Dresden Unit 1

contaminated demineralized water storage tank, which is located outside away from other plant

equipment. Additional AMR references were added to the piping and fittings component group,

LRA Table 2.3.4-3 was revised to indicate that this component group also applies to Quad

Cities, and clarifications were made regarding the components that are included in this group

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I

(such as strainers, flow elements, and heat exchanger shells). Also, the applicant added new

component groups for pumps, tanks, tubing, and valves for spacial interaction.

The staff reviewed the AMR of the new component groups and the additional AMR references

for existing component groups. All of the AMR references were already being used for the

condensate and condensate storage systems and had been previously reviewed by the staff, as

discussed in SER Section 3.4.2.4.3. Therefore, the staff finds that the applicant has identified

the applicable aging effects and has proposed adequate aging management, for the

components in the condensate and condensate storage system.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Main Condenser

The Main Condenser was originally included within the scope license renewal at both Dresden

and Quad Cities because the main condenser provides for post accident containment holdup

and plateout of main steam isolation valve bypass leakage. The main condenser at Quad

Cities station is a non-safety related component that resides in the same general area as the

discharge piping from the emergency diesel cooling water system. As such, the potential for

spatial interaction could occur and an additional system component function and appropriate

aging management has been assigned. This change only applies to Quad Cities as the same

physical equipment configuration does not exist at Dresden.

The staff reviewed the AMR of the main condenser. The staff notes that all of the AMR

references have previously been accepted for use for the main condenser, as discussed in SER

Section 3.4.2.4.4. The materiaVenvironment is carbon steel in steam and treated water, which

would be subject to loss of material due to various corrosion mechanisms; however, the

applicant determined that there are no aging effects requiring management based on the

intended function of containment, holdup, and plateout of iodine. The applicant demonstrated

that the intended function was achieved by the physical presence of the main condenser, and

that the ability of the main condenser to maintain vacuum during normal operation was

sufficient to demonstrate that the intended function (physical presence) was met, so no

additional aging management was needed. Similarly, by letter dated June 22, 2004, the

applicant demonstrated that the ability of the condenser to maintain vacuum was sufficient to

demonstrate that corrosion has not affected the leakage boundary function of the system.

Therefore, the staff finds that the applicant has identified the applicable aging effects and has

proposed adequate aging management, for the components in the main condenser.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Main Turbine and Auxiliaries

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The applicant stated that the original scoping results described inSection 2.3.4.5 of the LRA

included a portion of the main turbine electrohydraulic control (EHC) at both sites due to spatial

interaction with some safety related components.- However, portions of the EHC system were

excluded from the scope of license renewal because of they were separated from safety related

components by a distance greater than 20 feet. The change in scoping methodology has

resulted in the addition of the entire system within the scope of license renewal at both sites. - Additional components such as EHC pumps, coolers, strainers, filters, accumulators, and the

EHC fluid reservoir were added to the scope of license renewal. The new component groups

are filters/strainers, pump casings, and tanks for leakage boundary (spacial). The applicant

clarified that the heat exchanger shell was evaluated with the filter/strainer component group.

The staff reviewed the AMR of the new component groups. AMR reference 3.4.2.11 for

stainless steel in air had already been accepted for use in this system. The applicant added

three new AMR references to the LRA to address aging management not previously addressed

in the LRA. These AMR references address stainless steel in EHC oil, and rely on the Lube Oil

Monitoring Activities AMP and the One-Time Inspection AMP to manage the potential for loss of

material. This approach had already been found acceptable to the staff, as discussed in SER

Section 3.4.3.4.5. On the basis of its review, the staff finds that the applicant has identified the

applicable aging effects and has proposed adequate aging management, for the components in

the main turbine and auxiliary system.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Turbine Oil System

The original scoping results described in Section 2.3.4.6 of the license renewal application only

included a portion of the turbine oil system (hydrogen seal oil system), at Quad Cities. The

change in scoping methodology resulted in the addition of the hydrogen seal oil system within

the scope of license renewal at Dresden. The result is a clarification to the LRA that this

system is applicable to both Dresden and Quad Cities. No new component groups or AMR

references were added due to the change in scoping criteria; however, the applicant added

components to the piping and fittings component group. Since all of the aging management for

this system was previously approved by the staff, as described in SER Section 3.4.2.4.6, and

since there are no changes to the aging management of this system, the staff finds that the

applicant has identified the applicable aging effects and has proposed adequate aging

management, for the components in the turbine oil system.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21(a)(3).

Main Generator and Auxiliaries (Stator Water Cooling)

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The original scoping results described in Section 2.3.4.7 of the LRA only included a portion of

the main generator and auxiliaries, the stator water cooling, at Quad Cities. However, portions

of the stator water cooling system were excluded from the scope of license renewal because of

they were separated from a safety related component by a distance greater than 20 feet. The

change in scoping methodology has resulted in the addition of the entire stator water cooling

system within the scope of license renewal at both sites. The result is a clarification to the LRA

that this system and the Generator Stator Water Chemistry Activities AMP (LRA Section B.2.7)

are applicable to both Dresden and Quad Cities. No new component groups or AMR

references were added due to the change in scoping criteria; however, the components were

added to the housings component group. Since all of the aging management for this system

was previously approved by the staff, as described in SER Section 3.4.2.4.7, and since there

are no changes to the aging management of this system, the staff finds that the applicant has

identified the applicable aging effects and has proposed adequate aging management, for the

components in the main generator and auxiliary system.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Extraction Steam System

As a result of the revised scoping methodology, the extraction steam system was added to the

scope of license renewal at Quad Cities. Specifically, the entire extraction steam piping system

was added to the scope of license renewal because the system could spatially interact with

safety related pipe located in the feedwater heater area.

The purpose of the extraction steam system is to preheat feedwater as it passes through the

feedwater heaters prior to being returned to the reactor vessel. Steam is extracted from various

points on the main turbine and is routed along with water from the moisture separator drains to

the feedwater heaters. This steam is added to heat the condensate and feedwater which flows

through the tube side of the feedwater heaters. The component groups include piping and

fittings, and valves for leakage boundary (spacial) for Quad Cities only.

For aging management, the applicant cites three GALL AMR references. AMR reference

3.4.1.2 addresses carbon steel and stainless steel in steam and water environments, and

credits the Water Chemistry AMP (B.1.2) and the One-Tine Inspection AMP (B.1.23) to manage

the loss of material due to general (carbon steel only), pitting, and crevice corrosion. For this

AMR reference, the GALL recommends that the one-time inspections verify the effectiveness of

the chemistry controls. The applicant's programs are consistent with the GALL

recommendations. AMR reference 3.4.1.3 credits the Bolting Integrity AMP (B.1.12) or the

Structures Monitoring AMP (6.1.30) to address the general corrosion of the external surfaces of

carbon steel components. These AMPs were evaluated in Sections 3.0.3.5 and 3.0.3.14 and

found to be acceptable for managing this aging effect. AMR reference 3.4.1.4 addresses the

flow-accelerated corrosion of carbon steel components. For this the applicant credits the Flow

Accelerated Corrosion AMP (6.1.11), which has been reviewed and found to be acceptable, as

discussed in Section 3.0.3.4 of this SER. The staff questioned the applicant's choice of plant

locations for the one-time inspections identified in AMR Reference 3.4.1.2. In its response

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dated June 22, 2004, the applicant clarified that the components that use AMR Reference

3.4.1.2 also use AMR Reference 3.4.1.4. The applicant also stated that the locations chosen

for the one-time inspections had the same materials and fluids, but more severe conditions for

corrosion due to the higher oxygen replenishment from the monthly flow test. Based on the

above, the staff concurs that the aging management is appropriate. On the basis of its review,

the staff finds that the applicant has identified the applicable aging effects and has proposed

adequate aging management, for the components in the extraction steam system.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

Feedwater Heater Drains and Vents

As a result of the revised scoping methodology, the feedwater heater drains and vents system

at Quad Cities was added to the scope of license renewal. The feedwater heater vents are

included within this system but contain non-condensible gases that could not spatially interact

(spray) with safety related pipe. As such, only drain piping and associated components from

the heater drain system have been included within the scope of license renewal. The

component groups include piping and fittings, and valves for leakage boundary (spacial) for

Quad Cities only.

For aging management, the applicant cites three GALL AMR references. AMR reference

3.4.1.2 addresses carbon steel and stainless steel in steam and water environments, and

credits the Water Chemistry AMP (B.1.2) and the One-Tine Inspection AMP (B.1.23) to manage

the loss of material due to general (carbon steel only), pitting, and crevice corrosion. For this

AMR reference, the GALL recommends that the one-time inspections verify the effectiveness of

the chemistry controls. The applicant's programs are consistent with the GALL

recommendations. AMR reference 3.4.1.3 credits the Bolting Integrity AMP (B.1.12) or the

Structures Monitoring AMP (B.1.30) to address the general corrosion of the external surfaces of

carbon steel components. These AMPs were evaluated in Sections 3.0.3.5 and 3.0.3.14 and

found to be acceptable for managing this aging effect. AMR Reference 3.4.1.4 addresses the

flow-accelerated corrosion of carbon steel components. For this the applicant credits the Flow

Accelerated Corrosion AMP (B.1.11), which has been reviewed and found to be acceptable, as

discussed in Section 3.0.3.4 of this SER. The staff questioned the applicant's choice of plant

locations for the one-time inspections identified in AMR Reference 3.4.1.2. In its response

dated June 22, 2004, the applicant clarified that the components that use AMR Reference

3.4.1.2 also use AMR Reference 3.4.1.4. The applicant also stated that the locations chosen

for the one-time inspections had the same materials and fluids, but more severe conditions for

corrosion due to the higher oxygen replenishment from the monthly flow test. Based on the

above, the staff concurs that the aging management is appropriate. On the basis of its review,

the staff finds that the applicant has identified the applicable aging effects and has proposed

adequate aging management, for the components in the feedwater heater drains and vents

system.

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that there is reasonable assurance that the intended

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functions will be maintained consistent with the current licensing basis for the period of

extended operation, as required by 10 CFR 54.21(a)(3).

Conclusions

On the basis of its review of the aging management of the components that were brought into

scope due to the revised scoping methodology, the staff finds that the applicant has

demonstrated that the effects of aging will be adequately managed so that there is reasonable

assurance that the intended functions will be maintained consistent with the current licensing

basis for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.1 Reactor Vessel, Internals. and Reactor Coolant System

As discussed in Section 3.0.1 of this SER, the components in each of the systems are rolled up

into one of two LRA tables. LRA Table 3.1-1 consists of reactor vessel, internals, and reactor

coolant system components that are evaluated in the GALL Report and LRA Table 3.1-2

consists of reactor system components that are not evaluated in the GALL Report.

3.1.1 Summary of Technical Information in the Application

In LRA Section 3.1, the applicant described its AMRs for the reactor vessel, internals, and

reactor coolant system. The description of this system can be found in Section 2.3.1 of the

LRA. The passive, long-lived components in this system that are subject to an AMR are

identified in LRA Tables 2.3.1-1 through 2.3.1-9.

The applicant's AMRs included an evaluation of plant-specific and industry operating

experience. The plant-specific evaluation included reviews of condition reports and discussions

with appropriate site personnel to identify aging effects that require management. These

reviews concluded that the aging effects requiring management based on plant-specific

operating experience were consistent with the aging effects identified in GALL.

The applicant's review of industry operating experience included a review of operating

experience through 2002. The results of this review concluded that the aging effects requiring

management based on industry operating experience were consistent with the aging effects

identified in GALL. The applicant's ongoing review of plant-specific and industry-wide operating

experience is conducted in accordance with the Exelon Operating Experience Program.

3.1.2 Staff Evaluation

In Section 3.1 of the LRA, the applicant described its AMR for the reactor vessel, internals, and

reactor coolant system. The staff reviewed LRA Section 3.1 to determine whether the applicant

had provided sufficient information to demonstrate that the effects of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB throughout

the period of extended operation, in accordance with the requirements of 10 CFR 54.21(a)(3),

for the reactor system components that are determined to be within the scope of license

renewal and subject to an AMR.

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The applicant referenced the GALL Report in its AMR. The staff has previously evaluated the

adequacy of the aging management of reactor system components for license renewal as

documented in the GALL Report. Thus, the staff did not repeat its review of the matters

described in the GALL Report except to ensure that the material presented in the LRA was

applicable, and to verify that the applicant had identified the appropriate programs as described

and evaluated in the GALL Report. The staff evaluated those aging management issues

recommended for further evaluation in the GALL Report; this evaluation is presented in Section

3.1.2.2 of this SER. The staff also evaluated aging management information submitted by the

applicant that was different from that in the GALL Report or was not addressed in the GALL

Report; this evaluation is presented in Section 3.1.2.4 of this SER. Finally, the staff reviewed

the UFSAR Supplement to ensure that it provided an adequate description of the programs

credited with managing aging for the reactor system components.

Table 3.1-1 below provides a summary of the staff's evaluation of components, aging

effects/mechanisms, and AMPs listed in LRA Section 3.1 that are addressed in the GALL

Report.

Table 3.1-1. Summary of Aging Management Programs for Reactor Vessel, Internals, and

Reactor Coolant System Evaluated in Chapter IV of the GALL Report

Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

Group Mechanism Report

Reactor coolant Cumulative fatigue TLAA evaluated in Evaluated in Consistent with

pressure boundary damage accordance with10 accordance with 10 NUREG-1801 which

components CFR 54.21 (c) CFR 54.21 (c) recommends further

evaluation. (See

Section 3.1.2.2.1

below.)

Isolation condenser Loss of material Inservice Inspection; Inservice Inspection Consistent with

due to general, Water Chemistry Program (Appendix NUREG-1801 which

pitting, and crevice B.1.1); Water recommends further

corrosion Chemistry Program evaluation. (See

(Appendix B.1.2) Section 3.1.2.2.2

below.)

Pressure vessel ferritic Loss of fracture TLAA, evaluated in Evaluated in Consistent with

materials that have a toughness due to accordance with accordance with 10 NUREG-1 801 which

neutron fluence greater neutron irradiation Appendix G of 10 CFR 54.21 (c)(1) recommends further

than 1017 n/cm 2 embrittlement CFR Part 50 and RG evaluation. (See

(E>1 MeV) 1.99 Section 3.1.2.2.3

below.)

Reactor vessel beltline Loss of fracture Reactor Vessel Reactor Vessel Consistent with

shell and welds toughness due to Surveillance Surveillance NUREG-1801 which

neutron irradiation Program (Appendix recommends further

embrittlement B.1.22) evaluation. (See

Section 3.1.2.2.3

| below.)

Small-bore reactor Crack initiation and Inservice Inspection; Inservice Inspection Consistent with

coolant system and growth due to Water Chemistry; Program (Appendix NUREG-1801 which

connected systems SCC, IGSCC, and One-Time Inspection B.1.1); Water recommends further

piping thermal and Chemistry Program evaluation. (See

mechanical loading (Appendix B.1.2) Section 3.1.2.2.4(1)

below.)

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Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

Group Mechanism Report

Jet pump sensing line Crack initiation and Plant specific Plant specific Consistent with

and reactor vessel growth due to NUREG-1801 which

flange leak detection line SCC, IGSCC, or recommends further

cyclic loading evaluation. (See

Section 3.1.2.2.4(2)

below.)

Isolation condenser Crack initiation and Inservice Inspection; Inservice Inspection Consistent with

growth due to SCC Water Chemistry Program (Appendix NUREG-1801 which

or cyclic loading B.1.1); Water recommends further

Chemistry Program evaluation. (See

(Appendix B.1.2) Section 3.1.2.2.4(3)

below.)

Reactor vessel closure Crack initiation and Reactor Head Reactor Head Consistent with

studs and stud assembly growth due to SCC Closure Studs Closure Studs NUREG-1801.

and/or IGSCC Program (Appendix (See Section

B..1.3) 3.1.2.1 below.)

CASS pump casing and Loss of fracture Inservice Inspection Inservice Inspection Consistent with

valve body toughness due to program (Appendix NUREG-1801.

thermal aging B.1.1) (See Section

embrittlement 3.1.2.1 below.)

CASS piping Loss of fracture Thermal Aging No AMP (CASS Not applicable

toughness due to Embrittlement of piping does not exist

thermal aging CASS at D/QCNPS)

embrittlement

BWR piping and fittings; Wall thinning due Flow-Accelerated Flow-Accelerated Consistent with

steam generator to FAC Corrosion Corrosion Program NUREG-1801. (See

components (Appendix B.1.11) Section 3.1.2.1

below.)

RCPB valve closure Material loss due Bolting Integrity Bolting Integrity Consistent with

bolting, manway, and to wear, loss of Program (Appendix NUREG-1801. (See

holding bolting, and preload due to B.1.12) Section 3.1.2.1

closure bolting in high stress relaxation; below.)

pressure and high crack initiation and

temperature systems growth due to

cyclic loading

and/or SCC

Feedwater and CRD Crack initiation and Feedwater Nozzle; Feedwater Nozzle Consistent with

return line nozzles growth due to CRD Return Line Program (Appendix NUREG-1801. (See

cyclic loading Nozzle B.1.5); Control Rod Section 3.1.2.1

Drive Return Line below.)

Nozzle Program

(Appendix B.1.6)

Vessel shell attachment Crack initiation and BWR Vessel ID BWR Vessel ID Consistent with

welds growth due to Attachment Welds; Attachment Welds NUREG-1801. (See

SCC, IGSCC Water Chemistry Program (Appendix Section 3.1.2.1

B.1.4); Water below.)

Chemistry Program

(Appendix B.1.2)

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Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

Group Mechanism Report

Nozzle safe ends, Crack initiation and BWR Stress BWR Stress Consistent with

recirculation pump growth due to Corrosion Cracking; Corrosion Cracking NUREG-1801. (See

casing, connected SCC, IGSCC Water Chemistry Program (Appendix Section 3.1.2.1

systems piping and B.1.7); Water below.)

fittings, body and bonnet Chemistry Program

of valves (Appendix B.1.2)

Penetrations Crack initiation and BWR Penetrations; BWR Penetrations Consistent with

growth due to Water Chemistry Program (Appendix NUREG-1801. (See

SCC, IGSCC, B.1.8); Water Section 3.1.2.1

cyclic loading Chemistry Program below.)

(Appendix B.1.2)

Core shroud and core Crack initiation and BWR Vessel BWR Vessel Consistent with

plate, support structure, growth due to Intemals; Water Intemals Program NUREG-1801. (See

top guide, core spray SCC, IGSCC, Chemistry (Appendix B.1.9; Section 3.1.2.1

lines and spargers, jet IASCC Water Chemistry below.)

pump assemblies, CRD Program (Appendix

housing, nuclear B.1.2)

instrumentation guide

tubes

Core shroud and core Crack initiation and ASME Section Xl Inservice Inspection Consistent with

plate access hole cover growth due to Inservice Inspection; Program (Appendix NUREG-1801. (See

(welded and mechanical SCC, IGSCC, Water Chemistry B.1.1); Water Section 3.1.2.1

covers) IASCC Chemistry Program below.)

(Appendix. B.1.2)

Jet pump assembly Loss of fracture Thermal Aging and Thermal Aging and Consistent with

castings; orificed fuel toughness due to Neutron Irradiation Neutron Irradiation NUREG-1801. (See

support thermal aging and Embrittlement Embrittlement Section 3.1.2.1

neutron Program (Appendix below.)

embnttlement B.1.10)

Unclad top head and Loss of material Inservice Inspection; Inservice Inspection Consistent with

nozzles due to general, Water Chemistry Program (Appendix NUREG-1801. (See

pitting, and crevice B.1.1); Water Section 3.1.2.1

corrosion Chemistry Program below.)

(Appendix B.1.2)

3.1.2.1 Aging Management Evaluations in the GALL Report That Are Relied on for License

Renewal, Which Do Not Require Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL does not recommend further evaluation, the staff sampled

components in these groups to determine whether the plant-specific components contained in

these GALL component groups were bounded by the GALL evaluation. The staff also sampled

component groups to determine whether the applicant had properly identified those component

groups in GALL that were not applicable to its plants. The staff also identified several areas

where additional information or clarification was needed.

On the basis of its review, the staff has verified the applicant's claim of consistency with the

GALL report. The staff finds that the applicant has demonstrated that the effects of aging will

be adequately managed so that the intended functions will be maintained consistent with the

CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.1.2.2 Aging Management Evaluations in the GALL Report That Are Relied on for License

Renewal, for Which GALL Recommends Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL recommends further evaluation, the staff reviewed the applicant's

evaluation to determine whether it adequately addressed the issues for which GALL

recommended further evaluation. In addition, the staff sampled components in these groups to

determine whether the plant-specific components contained in these GALL component groups

were bounded by the GALL evaluation.

The GALL Report indicates that further evaluation should be performed for the aging effects

discussed in the following sections.

3.1.2.2.1 Cumulative Fatigue Damage (NUREG-1800, Section 3.1.2.2.1)

Fatigue is a time-limited aging analysis (TLAA) as defined in 10 CFR 54.3. TLAAs are required

to be evaluated in accordance with 10 CFR 54.21 (c)(1). The staff reviewed the evaluation of

this TLAA in Section 4.3 of this SER, following the guidance in Section 4.3 of the SRP-LR.

3.1.2.2.2 Loss of Material Due to Pitting and Crevice Corrosion (NUREG-1 800,

Section 3.1.2.2.2.2)

The GALL Report recommends augmented inspection to manage this aging effect. The staff

review verifies that the applicant has proposed a program that will manage loss of material due

to pitting and crevice corrosion by providing enhanced inspection and supplemental methods to

detect loss of material and ensure that the component intended function would be maintained

during the period of extended operation.

The applicant stated in LRA Table 3.1-1, Reference No. 3.1.1.2, that the program for managing

this aging effect is consistent with NUREG-1801 with exceptions, as described in LRA

Appendices B.1.1, "ASME Section Xl Inservice Inspection Program," and B.1.2, 'Water

Chemistry Program." As discussed in Section 3.1.2.2.4(1) of this SER, these exceptions are

acceptable. In addition, the applicant referred to LRA Sections 3.1.1.1.2 and 3.1.1.2.3 for

further evaluation of loss of material due to general (carbon steel only), pitting, and crevice

corrosion as an aging effect for the isolation condenser components at Dresden Units 2 and 3.

LRA Section 3.1.1.1.2 states that LRA Appendix B.1.1, "ASME Section Xl Inservice Inspection

Program," will be augmented by a plant-specific AMPs described in LRA Appendix B.2.6, "Heat

Exchanger Test and Inspection Activities." This plant-specific AMP includes temperature and

radioactivity monitoring of the shell-side water and eddy current testing of the tubes as

recommended by NUREG-1801. However, LRA Section 3.1.1.1.2 does not identify any

augmented inspection to detect loss of material in the isolation condenser tubesheet, channel

head, and shell as recommended by Item C1.4-b, Chapter IV.C1, of NUREG-1801. LRA

Appendix B.1.1 requires VT-2 examinations of the reactor coolant pressure boundary of

isolation condenser components during system pressure testing. This is not adequate for

detecting loss of material in the isolation condenser components before their intended function

(pressure boundary) is compromised. Therefore, the staff issued RAI 3.1-11 requesting the

applicant to provide augmented inspection for detecting loss of material in the isolation

condenser tubesheet, channel head, and shell.

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In response to RAI 3.1-11, in a letter dated October 3, 2003, the applicant stated that the aging

management activities identified in LRA Sections 3.1.1.1.2 and 3.1.1.1.7 are consistent with the

augmented activities recommended by NUREG-1801, Items IV.C.1.4-a and b and implied that

no additional inspection program is needed. The staff finds this response unacceptable

because the activities identified in LRA Sections 3.1.1.1.2 and 3.1.1.1.7 do not include

augmented inspections for detecting loss of material and cracking in the tubesheet, channel

head, and shell of the isolation condenser as recommended by NUREG-1801, Items IV.C.1 .4-a

and b. Therefore, in Supplemental RAI 3.1-11, the staff requested the applicant to provide

augmented inspection of the Dresden isolation condenser (i.e.. VT or UT) to manage loss of

material and crack initiation and growth in the isolation condenser tubesheet, channel head,

and shell, as required by NUREG-1801.

In response to Supplemental RAI 3.1-11, in a letter dated November 21, 2003, the applicant

stated that AMP B.2.6, 'Heat Exchanger Test and Inspection Program," is a 1 0-element

program that was developed to address heat exchangers within the scope of license renewal

that are not inspected under other AMPs. The intent of AMP B.2.6, as originally developed and

described in the LRA, is to require a visual inspection of the isolation condenser channel head,

tubesheet, and shell, in addition to performing eddy current testing of the tubes and

temperature and radiation monitoring of the shell-side water. These new activities will be

implemented prior to the period of extended operation. This is Commitment #44 of Appendix A

of this SER.

The applicant further stated that AMP B.2.6 did not clearly describe the visual inspection of the

isolation condenser tubesheet, channel head, and shell in the description of the isolation

condenser augmented activities. In addition to identifying the augmented isolation condenser

inspection activities of temperature and radiation monitoring of the shell-side water and eddy

current testing of the tubes, AMP B.2.6 provides for condition monitoring, inspection, and

performance testing of heat exchangers in scope of license renewal that are not inspected

under other AMPs, including the isolation condensers.

The applicant further stated that AMP B.2.6 requires the following two inspections of the

isolation condenser by qualified inspectors:

(a) In conjunction with the periodic eddy current testing of the tubes, a visual inspection to

detect cracking and loss of material of the channel head and tubesheets will be performed

on the tube side of the isolation condenser in accordance with the station's Heat Exchanger

Inspection Program as an augmented inspection to manage loss-of material and crack

initiation and growth in the isolation condenser tubesheet and channel head.

(b) Shell-side visual inspections are presently periodically performed to verify the integrity of

shell-side internal structural components. -These inspections will be expanded in

accordance with the station's Heat Exchanger Inspection Program to visually inspect the

shell to detect cracking and loss of material of the shell as an augmented inspection to

manage loss of material and crack initiation and growth in the isolation condenser shell.

The staff finds the applicant's response to Supplemental RAI 3.1-11 acceptable because it

ensures that the isolation condenser tubesheet, channel head, and shell will be visually

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inspected during the extended period of operation for detecting loss of material and crack

initiation and growth, as recommended by NUREG-1 801.

However the applicant's update to the UFSAR does not provide a complete description of the

inspection program, including VT of the isolation condenser tubesheet, channel head , and

shell. In a letter dated December 22, 2003, the applicant revised their response to RAI 3.1-11

to specify that the UFSAR Supplement, Section A.2.6 of the LRA includes visual inspections of

the channel head, tube sheets and internal surfaces of the shell.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of loss of material due to pitting and crevice corrosion, as recommended

in the GALL report. Since the applicant's AMR results are otherwise consistent with the GALL

report, the staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement (NUREG1800, Section 3.1.2.2.3)

Certain aspects of neutron irradiation embrittlement are TLAAs as defined in 10 CFR 54.3.

TLAAs are required to be evaluated in accordance with 10 CFR 54.21 (c)(1). The staff reviewed

the evaluation of this TLAA separately following the guidance in Section 4.2 of the SRP-LR.

The results of the staff's review can be found in Section 4.2 of this SER.

Loss of fracture toughness due to neutron irradiation embrittlement could occur in the reactor

vessel. A reactor vessel materials surveillance program monitors neutron irradiation

embrittlement of the reactor vessel. Reactor vessel surveillance programs are plant-specific,

depending on matters such as the composition of limiting materials, availability of surveillance

capsules, and projected fluence levels. In accordance with Appendix H to 10 CFR Part 50, an

applicant is required to submit its proposed withdrawal schedule for approval prior to

implementation. Thus, further staff evaluation is required for license renewal. The GALL

Report recommends further evaluation of a plant's reactor vessel materials surveillance

program for the period of extended operation. The staff verified that the applicant has

proposed an adequate reactor vessel materials surveillance program for the period of extended

operation.

D/QCNPS has an existing program, the Reactor Vessel Surveillance Program, described in

LRA Appendix B.1.22, for managing loss of fracture toughness in reactor vessel beltline shell

and welds due to neutron irradiation embrittlement. The applicant had submitted its license

amendment to implement a program consistent with Boiling Water Reactor Vessel and Intemals

Project (BWRVIP)-78, Integrated Surveillance Program," and BWRVIP-86, "BWR Integrated

Surveillance Program Implementation Plan." The staff has reviewed the license amendment.

and approved it in SERs to John Skolds, Exelon, from the NRC, dated September 29, 2003,

and August 28, 2003, for Dresden and Quad Cities, respectively. Therefore, the applicant has

committed to and implemented the BWRVIP Integrated Surveillance Program, consistent with

GALL Program XL.M31, "Reactor Vessel Surveillance," described in NUREG-1 801. The

evaluation of the enhanced program is presented in Section 3.1.2.3.8 of the SER.

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On the basis of its review, the staff finds that the applicant appr6priately evaluated AMR results

involving management of loss of fracture toughness due to neutron irradiation embrittlement, as

recommended in the GALL report. Since the applicant's AMR results are otherwise consistent

with the GALL report, the staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.1.2.2.4 Crack Initiation and Growth Due to Thermal and Mechanical Loading or StressCorrosion Cracking (NUREG-1800, Section 3.1.2.2.4)

Crack initiation and growth due to thermal and mechanical loading or SCC (including IGSCC)

could occur in small-bore reactor coolant system and connected system piping less than

nominal pipe size (NPS) 4. The existing program relies on ASME Section Xl inservice

inspection and on control of water chemistry to mitigate SCC. The GALL Report recommends

that a plant-specific destructive examination or a nondestructive examination (NDE) that

permits inspection of the inside surfaces of the piping be conducted to ensure that cracking has

not occurred and the component intended function will be maintained during the extended

period. The AMPs should be augmented by verifying that service-induced weld cracking is not

occurring in the small-bore piping less than NPS 4, including pipe, fittings, and branch

connections. A one-time inspection of a sample of locations is an acceptable method to ensure

that the aging effect is not occurring and that the component's intended function will be

maintained during the period of extended operation. GALL Chapter XL.M32, "One-Time

Inspection" contains an acceptable verification method.

The GALL Report recommends that the inspection include a representative sample of the

system population, and, where practical and prudent, focus on the bounding or lead

components most susceptible to aging due to time in service, severity of operating conditions,

and lowest design margin. For small-bore piping, actual inspection locations should be based

on physical accessibility, exposure levels, NDE examination techniques, and locations identified

in IN 97-46, "Unisolable Crack in High-Pressure Injection Piping." Combinations of NDE,

including visual, ultrasonic, and surface techniques, are performed by qualified personnel

following procedures consistent with the ASME Code and 10 CFR Part 50, Appendix B. For

small-bore piping less than NPS 4, including pipe, fittings, and branch connections, a plantspecific destructive examination or NDE that permits inspection of the inside surfaces of the

piping should be conducted to ensure that cracking has not occurred. Follow up of

unacceptable inspection findings should include expansion of the inspection sample size and

locations. The inspection and test techniques prescribed by the program should verify any

aging effects because these techniques, used by qualified personnel, have been proven

effective and consistent with staff expectations. The staff's review confirms that the program

includes measures to verify that unacceptable degradation is not occurring, thereby validating

the effectiveness of existing programs, or confirming that there is no need to manage agingrelated degradation for the period of extended operation. If an applicant proposes a one-time

inspection of select components and susceptible locations to ensure that corrosion is not

occurring, the reviewer verifies that the proposed inspection will be performed using techniques

similar to ASME Code and ASTM standards, including visual, ultrasonic, and surface

techniques, to ensure that the component's intended function will be maintained during the

period of extended operation.

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The applicant stated in LRA Table 3.1-1 that the program for managing this aging effect is

consistent with NUREG-1801, with exceptions, as described in LRA Sections B. 1.1 for the

Inservice Inspection Program and B.1.2 for the Water Chemistry Program. These exceptions

are described in the following paragraphs.

Inservice Inspection

NUREG-1801 indicates that the Inservice Inspection Program is to use the 1995 Edition

through the 1996 Addenda of ASME Section Xl. The applicant stated that the current code of

record for Dresden and Quad Cities is the 1989 Edition of ASME Section Xl. The applicant's

program will be enhanced to be consistent with the requirements of the 1995 Edition through

the 1996 Addenda of ASME Section Xl. This enhancement is scheduled for implementation

prior to the beginning of the period of extended operation. The evaluation of the Inservice

Inspection Program is presented in Section 3.0.3.1 of this SER.

Water Chemistry

NUREG-1 801 indicates that water chemistry control is in accordance with BWRVIP-29 for water

chemistry in BWRs. BWRVIP-29 references the 1993 revision of EPRI TR-103515, "BWR

Water Chemistry Guidelines." The D/QCNPS Water Chemistry Program is based on EPRI TR103515-R2, which is the 2000 revision of "BWR Water Chemistry Guidelines." As an

enhancement to the applicant's Water Chemistry Program, the applicant stated that procedures

will be revised to provide for increased sampling to verify corrective actions taken to address

abnormal chemistry conditions. The evaluation of the Water Chemistry Program is presented in

Section 3.0.3.2 of this SER.

The staff finds the applicant's exception to the GALL Inservice Inspection Program to be

acceptable because the applicant has committed to meeting the requirements of the 1995

Edition through the 1996 Addenda of ASME Section Xl, which the staff has endorsed in

10 CFR 50.55a, prior to the period of extended operation. This is Commitment #1 in Appendix

A of this SER. The staff finds the applicant's exceptions to the GALL water chemistry program

to be acceptable because it is based on updated industry experience (EPRI TR-103515).

In LRA Section 3.1.1.1.5, the applicant stated that an inspection of small-bore reactor coolant

piping is to be conducted in accordance with its One-Time Inspection Program to verify that

service-induced weld cracking is not occurring in the small-bore piping less than 4 NPS,

including pipe, fittings, and branch connections. The applicant's One-Time Inspection Program

is described in LRA Section B.1.23, and the applicant stated that it is consistent with NUREG1801, Chapter XI.M32, "One-Time Inspection." In Section 3.1.1.1.5 of the LRA, the applicant

further stated that thermal stratification, thermal cycling and thermal stripping, thermal

transients, and flow-accelerated corrosion are potential aging mechanisms for small-bore

piping. The LRA also states that a review of the Dresden and Quad Cities risk informed

inservice inspection (RI-ISI) evaluations on degradation mechanism assessment demonstrated

that only Dresden had a high failure potential on a small-bore pipe due to thermal fatigue.

Therefore, one-time inspection will consist of an ultrasonic exam on one of the 2-inch drain lines

off the Dresden main steam header. These lines are Class 1 and within the scope of license

renewal.

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The staff issued RAI 3.1-9(a) requesting information related to one-time inspection of small

diameter piping. In RAI 3.1-9(a)(1), the staff requested the applicant: to identify all Class 1,

small-bore piping in all units (Dresden, Units 2 and 3, and Quad Cities, Units 1 and 2), including the pipe sizes, material, and type of weld (i.e., butt or socket). If there are no UT-inspectable full penetration butt welds within scope, then the applicant should destructively test the socket

welds that are replaced due to modifications to confirm the effectiveness of the existing AMPs.

This is consistent with NUREG-1 801, Chapter XI.M32, which allows a plant-specific destructive

examination of replaced piping in lieu of NDE that permits inspection of the inside surfaces of

the piping. In response to RAI 3.1 -9(a)(1), in a letter dated October 15, 2003, the applicant provided a listing of the ASME Class 1, NPS less than NPS 4 piping. including pipe sizes,

material, and type of weld for Dresden Units 2 and 3 and Quad Cities Units 1 and 2. The

applicant stated that no destructive examination will be performed of the socket welds because

there are full penetration butt welds that can be UT-inspected at Dresden and Quad Cities. The

staff agrees with the applicant that it does not have to perform destructive testing of the socket

welds because Dresden and Quad Cities have UT-inspectable full penetration butt welds in the

small diameter piping.

In RAI 3.1-9(a)(2), the staff provided the following comments to the applicant on the use of riskinformed inservice inspection and requests for additional information. As currently written, 10

CFR Part 54 does not allow the staff to accept the elimination of SSCs from aging management

based on risk-informed arguments. Therefore, RI-ISI evaluations can be used to select

susceptible SSCs locations, but cannot eliminate SSCs from being inspected for a one-time

inspection program. A sampling of butt welds from each unit should be developed that is

consistent with the ASME Code and is sufficient to confirm the effectiveness of existing AMPs

and/or to confirm that there is no need to manage aging-related degradation for the period of

extended operation. Inspecting one weld in one unit is not a sufficient sample size. The

applicant must provide a sampling plan with a suitable sample size and an explanation of the

selection process. This plan should also include a discussion regarding expansion of the

inspection sample size and locations for follow up of unacceptable inspection findings as

required by NUREG-1 801, Chapter XL.M32. This plan is to be reviewed by the staff on a plant- specific basis, as required by NUREG-1801, Chapter XI.M32.

In response to RAI 3.1 -9(a)(2), in a letter dated October 15, 2003, the applicant stated that the

butt welds identified in the response to RAI 3.1 -9(a)(1) will be evaluated based on risk and

placed into high, medium, and low risk categories consistent with the currently approved RI-ISI

program. The applicant further stated that a sample of 10 percent of the high and medium risk

butt welds from each of the four Dresden/Quad Cities units will be selected for volumetric

examination. The sample expansion will be consistent with that described in Code Case N-578-

1, Section 2430. This is part of Commitment #23 of Appendix A in this SER. The staff finds the

sample size acceptable because it includes the most susceptible sites, and the sample expansion guideline acceptable because it follows the recommendation of NUREG-1 801,

Chapter XL.M32. Thus, the staff finds the sample size and sample expansion acceptable for

the one-time inspection to verify that SCC is not occurring in the small-bore piping.

In RAI 3.1-9(a)(3), the staff noted that Section 3.1.1.1.5 of the LRA does not specify an

inspection program for SCC as an aging mechanism in small-bore piping. Therefore, the staff

requested the applicant to identify the AMPs that will be used for managing cracking due SCC

in small-bore piping. In response to RAI 3.1-9(a)(3), in a letter dated October 15, 2003, the

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applicant stated that the following two programs are credited with managing cracking due to

SCC in small-bore piping-(1) LRA Section B.1.2, "Water Chemistry," and (2) LRA Section

B.1.23, "One-Time Inspection," as amended in response to RAI 3.1-9(a)(2) above. The staff

finds the response acceptable because the applicant has identified the One-Time Inspection

Program for verifying the effectiveness of the Water Chemistry Program in mitigating cracking

due to SCC.

As mentioned above, the applicant stated that the One-Time Inspection Program for small-bore

Class 1 piping less than 4 inches will consist of a volumetric examination of 10 percent of high

and medium risk butt welds from each of the four units. These lines were identified as part of a

review of the Dresden and Quad Cities RI-ISI evaluations on degradation mechanism

assessments on Class 1 piping. The aging mechanisms cited by the report for these lines are

thermal stratification, cycling, and stripping (TASCS), thermal transients (TT), and flowaccelerated corrosion. Nuclear industry service experience, documented in several industry

and NRC reports, has shown that the majority of reported piping leaks occur in small-bore

piping less than 4-NPS. A significant number of these failures have been reported in the

reactor coolant system, main steam system, feedwater system, and auxiliary systems in BWR

plants. Also, a large portion of the reported Class 1 small-bore piping failures occurred in

piping 1 NPS and less that were caused primarily by mechanical vibration, thermal

fatigue/turbulent penetration, SCC, and erosion-corrosion aging mechanisms. Since Class 1

small-bore piping 1 NPS and less is exempt from NDE examinations in ASME Section Xl, these

lines will typically receive only periodic VT-2 visual examination. In addition, many RI-ISI

evaluations do not include Class 1 piping 1 NPS and less in their evaluation scope and specific

degradation mechanism assessments are not performed for these lines. Therefore, it is not

clear that the applicant's proposed One-Time Inspection Program for small-bore piping will be

representative of all Class 1 piping 1 NPS and less with full penetration butt welds (socket

welds are excluded).

In RAI 3.1-9(b), the applicant was requested to clarify whether the Dresden and Quad Cities RIISI degradation mechanism assessments included Class 1 piping 1 NPS and less with full

penetration butt welds. The applicant is also requested to describe how the proposed OneTime Inspection Program will confirm that the aging mechanisms associated with the Class 1

small-bore piping 1 NPS and less with full penetration butt welds at Dresden and Quad Cites

are either not occurring and/or there is no need to manage age-related degradation for the

period of extended operation. In response to RAI 3.1-9(b), in a letter dated October 3, 2003,

the applicant stated that neither Dresden nor Quad Cities have butt welds in ASME Class 1

piping 1 NPS and less. Therefore, the One-Time Inspection Program does not apply to the 1

NPS and less piping. The staff agrees with the applicant's response that the proposed OneTime Inspection Program does not apply to the piping 1 NPS and less because, at Dresden and

Quad Cities, this piping does not include full penetration butt welds.

Crack initiation and growth due to thermal and mechanical loading or SCC (including IGSCC)

could also occur in the BWR reactor vessel flange leak detection line and BWR jet pump

sensing line. The GALL Report recommends that a plant-specific AMP be evaluated for the

management of crack initiation and growth due to thermal and mechanical loading or SCC

(including IGSCC) in the BWR reactor vessel flange leak detection line and BWR jet pump

sensing line. The staff reviewed the applicant's proposed program on a case-by-case basis to

ensure that an adequate program will be in place for the management of these aging effects.

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The applicant stated that the Dresden reactor vessel flange leak detection line is fabricated of

carbon steel, rather than stainless steel or a nickel-based alloy, as given in NUREG-1 801, and

it is therefore evaluated as a non-NUREG-1801 item. The AMR results for the carbon steel

leak detection line are presented in Section 3.1.2.4.5 of the SER.

In LRA Section 3.1.1.1.6, the applicant stated that the reactor vessel flange leak detection line

at Quad Cities is a Class 2 stainless steel component, and is susceptible to cracking due to

SCC. The Quad Cities ASME Section Xl Inservice Inspection Program, Relief Request PR-02

(relief granted per SER dated September 15, 1995), provides for an alternate inspection of the

reactor vessel flange leak detection line. This alternate examination utilizes a VT-2 visual

examination on the line during vessel floodup during a refueling outage. Future relief requests

may be submitted by the applicant in accordance with 10 CFR 50.55a. Otherwise, the applicant

must comply with the appropriate requirements of ASME Section Xl. The staff issued RAI 3.1-

25 requesting the applicant to confirm that cracking of the reactor vessel flange leak detection

line at Quad Cities will be managed in accordance with the requirements of ASME Section Xl,

Table IWC-2500-1, for license renewal. In response to RAI 3.1-25, in a letter dated October 3,

2003, the applicant confirmed that Quad Cities will manage the aging effects for the reactor

vessel flange detection lines in accordance with the requirements of ASME Section Xl, Table

IWC-2500-1, as amended by NRC-approved relief requests in accordance with 10 CFR 50.55a.

The staff finds this response acceptable because the applicant committed to follow the

requirements of ASME Section Xl, Table IWC-2500-1. This is Commitment #1 in Appendix A of

this SER.

The applicant stated in its LRA that the jet pump sensing lines at Dresden and Quad Cities are

not within the scope for license renewal, but provided no explanation. The staff issued RAI

2.3.1.2-5 requesting the applicant to provide a technical basis to support this determination. In

response to RAI 2.3.1.2-5, in a letter dated October 3, 2003, the applicant submitted the

following explanation. The main function of the jetpump sensing line is to monitor jet pump

integrity. If a sensing-line fails, the Dresden/Quad Cities Plant Technical Specifications require

either a plant shut down or safety assessment to justify continued operation. Therefore, the

applicant concluded that a sensing line failure has no adverse safety consequences and no

inspection is required. The applicant supported its conclusion by pointing out that BWRVIP-41,

UBWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines," Section 2.3.12.7, also

concludes that inspection of sensing lines is essentially occurring continuously by plant

operations. The staff finds the applicant's decision of not including the jet pump sensing line

within the scope of license renewal acceptable because plant operation essentially provides for

continuous monitoring of the sensing line integrity and, if a line fails, Plant Technical

Specifications require either a plant shut down or safety assessment to justify continued

operation. Therefore, the failure of the sensing line has no adverse safety consequences and

does not need to be included within the scope of license renewal.

Crack initiation and growth due to thermal and mechanical loading or SCC (including IGSCC)

could also occur in BWR isolation condenser components. The existing program relies on

control of reactor water chemistry to mitigate SCC and on ASME Section Xl inservice

inspection. However, the existing program should be augmented to detect cracking due to SCC

or cyclic loading. The GALL Report recommends an augmented program to include

temperature and radioactivity monitoring of the shell-side water and eddy current testing of

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tubes to ensure that the component's intended function will be maintained during the period of

extended operation. The staff reviewed the applicant's proposed program on a case-by-case

basis to ensure that an adequate program will be in place for the management of these aging

effects.

The applicant stated in LRA Table 3.1-1, Reference No. 3.1.1.7, that the program for managing

this aging effect is consistent with NUREG-1 801 with exceptions, as described in LRA

Appendices B.1.1, "ASME Section Xl Inservice Inspection Program," and B.1.2, "Water

Chemistry Program." As discussed in Section 3.1.2.2.4.1 of this SER, these exceptions are

acceptable. In addition, the applicant referred to LRA Sections 3.1.1.1.7 and 3.1.1.2.3 for

further evaluation of crack initiation and growth due to SCC and cyclic loading as an aging

effect for the isolation condenser components at Dresden Units 2 and 3. LRA Section 3.1.1.1.7

states that LRA Appendix B.1.1, "ASME Section Xl Inservice Inspection Program," will be

augmented by a plant-specific AMP described in LRA Appendix B.2.6, "Heat Exchanger Test

and Inspection Activities." This plant-specific AMP includes temperature and radioactivity

monitoring of the shell-side water and eddy current testing of the tubes, as recommended by

NUREG-1 801. However, LRA Section 3.1.1.1.7 does not identify any augmented inspection to

detect crack initiation and growth in the isolation condenser tubesheet, channel head, and shell,

as recommended by Item C1.4-a, Chapter IV.C1, of NUREG-1801. LRA Appendix B.1.1

requires VT-2 examinations of the reactor coolant pressure boundary during system pressure

testing. This is not adequate for detecting crack initiation and growth in the isolation condenser

components before their intended function (pressure boundary) is compromised. Therefore,

the staff issued RAI 3.1-11 and Supplemental RAI 3.1-11 requesting the applicant to provide

augmented inspection for detecting loss of material in the isolation condenser tubesheet,

channel head, and shell. The staff's evaluation of the applicant's responses to RAI 3.1-11 and

Supplemental RAI 3.1-11 is presented in Section 3.1.2.2.2 of this SER. The staff finds the

applicant's responses acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of crack initiation and growth due to thermal and mechanical loading or

SCC, as recommended in the GALL report. Since the applicant's AMR results are otherwise

consistent with the GALL report, the staff finds that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.1.2.3 Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant

System Components

The applicant credits 17 AMPs to manage the aging effects associated with components in the

reactor coolant systems as listed below. Nine of the AMPs are credited to manage aging for

components in other system groups (common AMPs) while eight AMPs are credited with

managing aging only for reactor system components. The staff's evaluation of the common

AMPs that are credited with managing aging in reactor system components are provided in

Section 3.0.3 of this SER.

* ASME Section Xl Inservice Inspection Program (B.1.1)

* Water Chemistry Program (B.1.2)

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* Reactor Head Closure Studs'Program (B.1.3)

* BWR Vessel Inner Diameter (ID) Attachment Welds Program (B.1.4)

* Feedwater Nozzle Program (B.1.5)

* Control Rod Drive Return Line Nozzle Program (B.1.6)

* BWR Stress Corrosion Cracking Program (B.1.7)

* BWR Penetrations Program (B.1.8)

* BWR Vessel Internals Program (B.1.9)

* Thermal Aging and Neutron Irradiation Embrittlement Program (B.1.10)

* Flow-Accelerated Corrosion Program (B.1.1 1)

* Bolting Integrity Program (8.1.12)

* Compressed Air Monitoring Program (B.1.16)

* Reactor Vessel Surveillance Program (B.1.22)

* One-Time Inspection Program (8.1.23)

* Structures Monitoring Program (B.1.30)

* Heat Exchanger Test and Inspection Activities Program (B.2.6)

The staff's evaluation of the eight AMPs for the reactor vessel, internals, and reactor coolant

system is provided in the following sections.

3.1.2.3.1 Reactor Head Closure Studs Program

Summary of Technical Information in the Application. The applicant's Reactor Head Closure

Studs Program is discussed in LRA Section B.1.3, "Reactor Head Closure Studs." The

applicant stated that the program is consistent with GALL Program XI.M3, "Reactor Head

Closure Studs" with two exceptions. These exceptions are with respect to the NUREG-1 801

requirement that the inspections be carried out in accordance with the requirements of ASME

Section Xl, Subsection IWB, Table IWB 2500-1. Table IWB 2500-1 specifies volumetric

(radiographic, ultrasonic, or eddy current) inspection for studs in place and both surface

(magnetic particle, liquid penetration, or eddy current) and volumetric examination of studs

when removed. Instead of a surface examination, the Dresden and Quad Cities plants utilize a

VT-1 visual inspection, as granted under relief requests CR-13 and CR-11, respectively.

Likewise, instead of a volumetric examination with a conventional UT, the Dresden and Quad

Cities reactor closure head studs are examined by end-shot UT, as approved in relief request

CR-12.

The LRA also indicates that the current code of record for the Dresden and Quad Cities

inspection programs is the 1989 Edition of ASME Section Xl, rather than the 1995 Edition

through the 1996 Addenda, as specified in NUREG-1801. The applicant stated that its

inspection program will be revised to be consistent with these NUREG-1801 requirements prior

to the period of extended operation.

This AMP is credited with managing aging-related cracking and loss of material in reactor head

closure bolts. The applicant stated in the LRA'that the Dresden and Quad Cities reactor head

closure studs AMP activities have detected aging degradation and have implemented

appropriate corrective actions to maintain system and component intended functions, including

prompt repair or replacement of degraded components prior to failure.

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The applicant concluded in its LRA that the Reactor Head Closure Studs Program provides

reasonable assurance that loss of material and cracking aging effects in the reactor head

closure studs are adequately managed so that their intended functions, consistent with the

CLB, are maintained during the period of extended operation.

Staff Evaluation. In LRA Appendix B.1.3, "Reactor Head Closure Studs," the applicant

described its AMP to manage aging-related cracking and loss of material in the reactor head

closure studs. The applicant stated that this AMP is consistent with GALL AMP XI.M3, "Reactor

Head Closure Studs," with exceptions to the NUREG-1801 requirements regarding inspection

for studs in place and when removed. The staff confirmed the applicant's claim of consistency

during the AMR inspection. Furthermore, the staff reviewed the deviations and their

justifications to determine whether the AMP, with the deviations, remains adequate to manage

the aging effects for which it is credited. The staff also reviewed the UFSAR Supplement to

determine whether it provides an adequate description of the revised program. In addition, the

staff determined whether the applicant properly applied the GALL program (NUREG-1 801) to its

facility.

The staff notes that NUREG-1801, in accordance with the requirements of ASME Section Xl,

Subsection IWB, Table IWB 2500-1, specifies volumetric inspection for studs in place and both

surface and volumetric examination of studs when removed. The applicant stated in the LRA

that, instead of a surface inspection, Dresden and Quad Cities employ a VT-1 visual inspection,

as granted under relief requests CR-13 and CR-1 1, respectively. Likewise, instead of a

volumetric examination, the Dresden and Quad Cities reactor closure head studs are examined

by end-shot UT, as approved in relief request CR-12. Use of VT-1 visual inspection when the

studs are removed is acceptable based on current revisions of the ASME Code. However, use

of the end-shot UT inspection procedure was not approved per relief request CR-12 since it

does not provide the required sensitivity (see Section 3.1.1.3 of the staff's safety evaluation

(SE) dated September 15, 1995). The staff's SE did approve the use of the bore probe

inspection procedure through the third ISI interval.

Future relief requests may be submitted by the applicant in accordance with 10 CFR 50.55a.

Otherwise, the applicant must comply with the requirements of ASME Section Xl, Subsection

IWB, Table IWB 2500-1, which specifies volumetric inspection for studs in place and both

surface and volumetric examination of studs when removed. In RAI B.1.3-a, the staff requested

the applicant to confirm that aging effects for the reactor closure head studs will be

monitored/managed in accordance with the requirements of ASME Section Xl, Subsection IWB,

Table IWB 2500-1, during the period of extended operation. The applicant provided the

following response to RAI B.1.3-a in a letter dated October 3, 2003. The applicant stated that

since submittal of the LRA, Dresden and Quad Cities have updated their ISI programs to be

consistent with the 1995 Edition through the 1996 Addenda of ASME Section Xl. The applicant

further stated that the requirements of ASME Section Xl, Subsection IWB, Table IWB 2500-1,

will be augmented by Code Case N-307-2, "Revised Ultrasonic Examination Volume for Class 1

Bolting, Table IWB-2500-1, Examination Category B-G-1, When the Examinations Are

Conducted From the End of the Bolt or Stud or From the Center-Drilled Hole," as endorsed by

NRC RG 1.147, Revision 13. Thus, with this update of its ISI programs as augmented by Code

Case N-307-2, Dresden and Quad Cities removed the exception noted as Relief Request CR12. The staff finds the response acceptable because the applicant has confirmed that cracking

and loss of material in the reactor closure head studs will be managed during the license

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renewal period in accordance with ASME Section Xl, Subsection IWB, Table IWB 2500-1, as

augmented by Code Case N-307-2, as required by the staff in accordance with 10 CFR 50.55a.

In LRA Appendix B.1.3, "Reactor Head Closure Studs," the applicant stated that the Reactor

Head Closure Studs Program provides for condition monitoring and preventive actions to

manage stud cracking and loss of material. However, loss of material is not identified as an

aging effect for reactor head closure studs in LRA Tables 3.1-1 or 3.1-2. In RAI B.1.3-c, the

staff requested the applicant to clarify this discrepancy and discuss D/QCNPS operating

experience with respect to loss of material for the reactor head closure studs. In response to

RAI B.1.3-c ,in a letter dated October 3, 2003, the applicant states that the loss of material was

inadvertently added to LRA Appendix B.1.3, "Reactor Head Closure Studs," and should have

been deleted. The applicant further stated that Dresden and Quad Cities do not have any

operating experience that would indicate that loss of material is an applicable aging effect for

reactor head closure studs. The staff finds the applicant's clarification acceptable because it is

consistent with the operating experience of Dresden and Quad Cities and is consistent with

NUREG-1801, Table IV.A1, Item A1.1-c.

The applicant stated in LRA Appendix B.1.3, uReactor Head Closure Studs," that the reactor

head studs at Dresden and Quad Cities are not metal-plated and have had manganese

phosphate coatings applied. These preventative actions are consistent with those

recommended in Chapter XL.M3 of NUREG-1801 which recommends use of manganese

phosphate coatings for reducing SCC and IGSCC of closure studs. NUREG-1801 does not

recommend use of metal-plated studs because metal plating can result in corrosion and

hydrogen embrittlement. In RAI B.1.3-b, the staff requested the applicant to submit the

operating experience with manganese phosphate coatings. Specifically, the staff requested the

applicant to describe the experience related to any cracking of the reactor head closure studs

since the application of the manganese phosphate coatings. In response to RAI B.1.3-b, in a

letter dated October 3, 2003, the applicant stated that four studs at Dresden Unit 2 were found

to have cracking during refuel outages. These studs were replaced. The applicant further

stated that no other recordable indications have been identified on the Dresden or Quad Cities

reactor vessel closure head studs. The applicant has not identified the cause of cracking, when

the cracking was found, and mitigation actions to prevent cracking. The applicant needs to

provide this information. In a letter dated December 22, 2003, the applicant supplemented its

response to RAI 8.1.3(b). The response stated that the Reactor Head Closure Stud Program

for Dresden and Quad Cities provides inspections in accordance with NUREG-1 801, Program

XL.M3 requirements, which has been proven effective in detecting the aging effects (cracking

and loss of material). The four studs at Dresden, Unit 2 were found to have cracking during

refueling outages D2R1 1 and D2R1 5 and were subsequently replaced. The cracking was the

result of stress corrosion cracking (SCC) and the probable cause determined to be exposure of

the studs to oxygenated water during outages while in the tensioned condition. No other

recordable indications have been identified on the Dresden or Quad Cities reactor head closure

studs. The reactor vessel studs normally remain in the reactor vessel flange during refueling

activities and are exposed to water during reactor vessel flood up. Water collected in these

small areas can not be removed following a refueling outage. As part of the re-assembly, studs

are tensioned. The combination of oxygenated water and tensioning resulted in the SCC. Due

to the nature of the installation, the only possible corrective actions are stud inspections and

replacement. The staff finds this response acceptable because the operating experience

demonstrates the ability of the AMP to identify and replace degraded studs prior to a loss of

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function, which is consistent with the aging effect of cracking managed by Reactor Head

Closure Studs Program (LRA Appendix B.1.3).

The staff reviewed the UFSAR Supplement to determine whether it provides an adequate

description of the program. In RAI B.1.3-d, the staff requested the applicant to revise the

UFSAR Supplement by mentioning the use of VT-1 visual and bore-probe UT inspection

procedures for detecting cracking in the reactor head closure studs. In response to RAI B. 1.3-

d, in a letter dated October 3, 2003, the applicant stated that the UFSAR Supplement described

in LRA Appendix A, Section A.1.3, provides a level of detail consistent with that provided in

NUREG-1 800, Table 3.1-2. The applicant further stated that identifying specific examinations

required by ASME Section Xi is redundant to the stated information and is not required. The

staff finds the applicant's response unacceptable because, as stated in the response to RAI

B.1.3-a, the applicant plans to augment the requirements of ASME Section Xl by Code Case N307-2, so that it can use end-shot UT and bore probe UT inspection procedures for detecting

cracking in the reactor head closure studs. Therefore, in Supplemental RAI B.1.3(a), the staff

requested the applicant to include ASME Section XI Code Case N-307-2 in the UFSAR

Supplement for the Reactor Head Closure Studs Program. In response to Supplemental RAI

B.1.3(a), in a letter dated November 21, 2003, the applicant stated that Exelon will update the

UFSAR Supplement to indicate that the requirements of ASME Section Xi will be implemented

in accordance with 10 CFR 50.55a. The staff finds the response acceptable because 10 CFR

50.55a allows the use of ASME Section Xl Code Cases, including Code Case N-307-2, that are

accepted by the staff. These code cases are listed in RG 1.147, "Inservice Inspection Code

Case Acceptability-ASME Section Xl Division 1."

Conclusions. On the basis of its review and audit of the applicants program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. In addition, the staff has reviewed the

exceptions to the GALL program and finds that the applicant has demonstrated that the effects

of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB during the period of extended operation, as required by 10 CFR

54.21 (a)(3). The staff also reviewed the UFSAR supplement for this AMP and finds that it

provides an adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.1.2.3.2 BWR Vessel ID Attachment Welds Program

Summary of Technical Information in the Application. The applicant's BWR Vessel ID

Attachment Welds Program is discussed in LRA Appendix B.1.4, "BWR Vessel ID Attachment

Welds." The applicant stated that the program incorporates the inspection and evaluation

recommendations of BWRVIP-48, "Vessel ID Attachment Weld Inspection and Evaluation

Guidelines," as well as the water chemistry recommendations of EPRI TR-1 03515-R2, "BWR

Water Chemistry Guidelines." The applicant further stated that because of the incorporation of

these recommendations, the program is consistent with GALL Program XI.M4, "BWR Vessel ID

Attachment Welds."

The applicant identified one exception to NUREG-1801. GALL Program XL.M4 indicates that

the BWR water chemistry control is in accordance with BWRVIP-29, which references the 1993

revision of EPRI TR-103515, "BWR Water Chemistry Guidelines." However, the D/QCNPS

Water Chemistry Programs are based on the 2000 revision of EPRI TR-103515-R2.

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LRA Appendix B.1.4 also indicates that the-current code of record for the D/QCNPS inspection

programs is the 1989 Edition of ASME Section XI, rather than the 1995 Edition through the

1996 Addenda, as specified in NUREG-1801. The applicant stated that its inspection program

will be revised to be consistent with these NUREG-1801 requirements prior to the period of:

extended operation.

This AMP is credited with managing crack initiation and growth due to SCC and IGSCC in the

vessel ID attachment welds. The applicant stated that the DIQCNPS inspection and testing

methodologies have not detected cracking in the attachment welds. The applicant concluded

that the BWR Vessel ID Attachment Welds Program provides reasonable assurance that

cracking aging effects in the ID attachment welds are adequately managed so that their

intended functions, consistent with the CLB, are maintained during the period of extended

operation.

Staff Evaluation. In LRA Appendix B.1.4, UBWR Vessel ID Attachment Welds," the applicant

described its AMP to manage crack initiation and growth in the vessel ID attachment welds due

to SCC and IGSCC. The LRA stated that this AMP is consistent with GALL AMP XL.M4, "BWR

Vessel ID Attachment Welds" with an exception regarding water chemistry. The staff confirmed

the applicant's claim of consistency during the AMR inspection. In addition, for D/QCNPS, the

staff determined whether the applicant properly applied the GALL program to its facility. The

staff also reviewed the UFSAR Supplement to determine whether it provides an adequate

description of the program.

The staff finds the applicant's exception to the GALL water chemistry program to be acceptable

because it is based on updated industry experience. The evaluation of the applicant's Water

Chemistry Program (LRA Appendix B.1.2) is presented in Section 3.0.3.2 of this SER.

The applicant stated that the inspection guidelines for the BWR Vessel ID Attachment Welds

Program (LRA Appendix B.1.4) are consistent with BWRVIP-48, which has been approved by

the NRC staff. The letter dated January 17, 2001, from C.1. Grimes, NRC, to C. Terry,

BWRVIP Chairman, lists required license renewal applicant action items, in accordance with 10

CFR Part 54, when incorporating the BWRVIP-48 report in a renewal application. These

license renewal applicant action items are also required for the other applicable BWRVIP

reports, which are approved by the staff. These action items are listed below:

* The license renewal applicant is to verify that its plant is bounded by the report. Further, the

renewal applicant is to commit to programs described as necessary in the BWRVIP reports

to manage the effects of aging during the period of extended operation. Applicants for

license renewal will be responsible for describing any such commitments and identifying

how such commitments will be controlled. Any deviations from the AMPs within these

BWRVIP reports described as necessary to manage the effects of aging during the period

of extended operation and to maintain the functionality of the components or other

information presented in the report, such as materials of construction, will have to be

identified by the renewal applicant and evaluated on a plant-specific basis in accordance

with 10 CFR 54.21(a)(3) and (c)(1).

* Section 54.21(d) of Title 10 of the Code of Federal Regulations requires that an FSAR

Supplement for the facility contain a summary description of the programs and activities for

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managing the effects of aging and the evaluation of TLAAs for the period of extended

operation. Those applicants for license renewal referencing the applicable BWRVIP report

shall ensure that the programs and activities specified as necessary in the applicable

BWRVIP reports are summarily described in the FSAR Supplement.

* As required by 10 CFR 54.22, each application for license renewal must include any

technical specification changes (and the justification for the changes) or additions

necessary to manage the effects of aging during the period of extended operation as part of

the renewal application. The applicable BWRVIP reports may state that there are no

generic changes or additions to technical specifications associated with the report as a

result of its AMR, and that the applicant will provide the justification for plant-specific

changes or additions. Those applicants for license renewal referencing the applicable

BWRVIP reports shall ensure that the inspection strategy described in the reports does not

conflict with or result in any changes to their technical specifications. If changes in technical

specifications do result, then the applicant must ensure that those changes are included in

its application for license renewal.

* If required by the applicable BWRVIP report, the applicant referencing a particular report for

licensing renewal should identify and evaluate any potential TLAA issues and/or

commitments to perform future inspections when inspection tooling is made available.

In RAI 4.2-BWRVIPs, the staff requested the applicant to submit the necessary commitments,

information, and changes as described above for each of the following applicable BWRVIP

reports:

* BWRVIP-05

* BWRVIP-18

* BWRVIP-25

* BWRVIP-26

* BWRVIP-27

* BWRVIP-38

* BWRVIP-41

* BWRVIP-42

* BWRVIP-47

* BWRVIP-48

* BWRVIP-49

* BWRVIP-74

* BWRVIP-75

* BWRVIP-76

* BWRVIP-78

* BWRVIP-86

* Other BWRVIP reports applicable to license renewal

In response to RAI 4.2-BWRVIPS, in a letter dated October 3, 2003, the applicant summarized

the NRC's request for information in the seven elements listed below and presented its

response to each of those elements.

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(1) Verify that Dresden and Quad Cities are bounded by the conditions (materials configuration

and inspection methodologies) specified in the applicable BWRVIP documents.

Response: The BWRVIP documents were assembled with participation from the NSSS

supplier and a wide representation from the BWR Owners Group, providing a level of

confidence in accuracy and bounding conditions of these documents. However, during a

preliminary review when preparing this response, some material differences were noted.

Exelon will perform a detailed review of the applicable BWRVIP documents and verify that

Dresden and Quad Cities are bounded by the conditions specified or identify and evaluate any

exceptions noted.

(2) Provide a commitment to implement programs consistent with the applicable BWRVIP

documents or identify the applicable exceptions.

Response: At the completion of the review noted in item 1 above, Exelon will provide a list of

commitments to the applicable BWRVIP documents or identify specific exceptions taken.

(3) Describe how the commitments will be tracked.

Response: The commitments, once identified, will be placed in the site implementing

procedures with traceability back to the license renewal commitment being made.

(4) Summarize a program description of the applicable BWRVIP documents in the LRA

Appendix A, UFSAR Supplement.

Response: Several of the BWRVIP programs are identified in the LRA Appendix A, such as

BWRVIP-75, A.1.7; BWRVIP-27, A.1.8; BWRVIP-48, A.1.4; BWRVIP-49, A.1.8; BWRVIP-78,

A.1.22; and BWRVIP-86, A.1.22. Once the comprehensive list of commitments is identified in

item 2 above, Exelon will update the LRA Appendix A to provide a summary program

description to address each applicable BWRVIP document.

(5) Verify that technical specification changes needed to support implementation of the

applicable BWRVIP documents have been identified and processed.

Response: There are no additional technical specification changes anticipated. However, once

the detailed review summarized in item 1 above is complete, Exelon will confirm that no

technical specification changes are needed or identify the needed changes to be processed

prior to the start of the extended term of operation.

(6) Identify and evaluate any potential TLAA issue identified by the applicable BWRVIP

documents and/or commitments to perform future inspections when inspection tooling is made

available.

Response: All applicable TLAAs are discussed in Section 4 of the LRA.

(7) Address items 1 through 6 above for the 16 specific BWRVIP documents listed in the RAI

and identify and address other BWRVIP documents applicable to license renewal.

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Response: Based on a preliminary review, there appears to be several other BWRVIP

documents applicable to license renewal, such as BWRVIP-07 and BWRVIP-63 for core shroud

repairs, and BWRVIP-26 for Water Chemistry. Once the detailed review is completed, Exelon

will provide an amended response addressing items 1 through 6 for all BWRVIP documents

applicable to license renewal.

The staff found the applicant's response incomplete. The response committed to perform a

detailed review of the BWRVIP documents applicable to license renewal, prepare an amended

response addressing items 1 through 7 for all of those documents applicable to license renewal,

and submit it to the staff for review and approval. Therefore, this response was incomplete until

an amended response was submitted and approved by the staff. This was identified as

Confirmatory Item 3.1.2.3.2-1.

In a letter dated April 9, 2004, the applicant submitted the following amended response to RAI

4.2-BWRVIPs addressing the seven items, which were listed in the initial response to RAI

4.2-BWRVIPs, for all of the BWRVIP documents applicable to license renewal.

1. Verify that Dresden and Quad Cities are bounded by the conditions (materials, configuration

and inspection methodologies) specified in the applicable BWRVIP documents.

Amended Response: The site-specific procedures at D/QCNPS implemented all of the

inspection methodologies contained in the applicable BWRVIP documents. Additionally, the

materials and configurations at D/QCNPS are similar to those specified in the BWRVIP

documents with an exception related to the steam dryer hold-down bracket attachment weld

addressed later in this section in response to Supplementary RAI B.1.4. Regarding inspection

methodologies, the applicant has identified two exceptions related to BWRVIP-74: (1) use of

risk-informed ISI to supplement the ISI and GL 88-01 programs for reactor pressure vessel

nozzles and safe ends, and (2) use of an NRC-approved code case for the inspection of the

reactor vessel leak detection line. The first exception is evaluated in SER Section 3.1.2.4.1 and

the second one in SER Section 3.1.2.2.4.

2. Provide a commitment to implement programs consistent with the applicable BWRVIP

documents or identify the applicable exceptions.

Amended Response: D/QCNPS provided a commitment for implementing the programs

consistent with the applicable BWRVIP documents and identified several exceptions. These

exceptions are associated with BWRVIP-38, BWRVIP-41, BWRIP-74, and BWRVIP-75 and are,

described in SER Sections 3.1.2.3.6 and 3.1.2.4 as appropriate. In addition, the applicant has

committed to implement several BWRVIP reports that are being reviewed by the NRC, and will

identify any exceptions associated with these reports after the staff's reviews are completed.

See amended response 7 for the several BWRVIP reports being reviewed by the NRC. This is

part of Commitment #9 in Appendix A of this SER.

3. Describe how the commitments will be tracked.

Amended Response: All license renewal commitments are controlled by the Exelon

commitment management process described in LS-AA-1 10, Commitment Management.

Commitment tracking files will be generated for each individual activity credited to implement

the requirements of the AMP. In addition, steps in site procedures that implement the various

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activities specified in the BWRVIP documents are annotated as NRC commitments and are

referenced to commitment tracking files that contain sufficient documentation describing the

source of the commitment.

4. Summarize a program description of the applicable BWRVIP documents in the LRA

Appendix A, UFSAR Supplement.

Amended Response: The FSAR Supplement (LRA Appendix A) Programs A.1.1, A.1.2, A.1.4,

A.1.8, A.1.9, and A.1.22 have been updated to reflect the applicable BWRVIP documents, and

exceptions as noted in response to Item 2 above. A revised FSAR supplement incorporating

these changes was submitted to NRC in the attachment to Exelon transmittal letter dated March

5, 2004 as part of the annual update required by 10 CFR 54.21 (b).

5. Verify that technical specification changes needed to support implementation of the

applicable BWRVIP documents have been identified and processed.

Amended Response: The only Technical Specification change required for both sites involves

revision to the site pressure temperature (P-T) curves. The existing P-T curves will be revised

for 54 EFPY prior to the extended term of operation.

6. Evaluate any potential TLAA issue identified by the applicable BWRVIP documents and/or

commitments to perform future inspections when inspection tooling is made available.

Amended Response: All applicable TLAAs were discussed in Section 4 of the LRA. The

applicant also committed to perform future inspections, as recommended by the BWRVIP

documents, when inspection tooling is made available. This commitment is discussed in SER

Section 3.1.2.3.6.

7. Address Items 1 through 6 above for the 16 specific BWRVIP documents listed in the RAI

and identify and address other BWRVIP documents applicable to license renewal.

Amended Response: In addition to the 16 specific BWRVIP documents listed in RAI

4.2-BWRVIPs, the applicant has identified four additional documents applicable to license

renewal: BWRVIP-29, BWRVIP-79, BWRVIP-104, and BWRVIP-116. NRC has issued a safety

evaluation report for the first document (BWRVIP-29) but not for the remaining three. However,

the applicant has provided an amended response in their letter dated April 9, 2004, addressing

items 1 through 6 for all 20 BWRVIP documents applicable to license renewal and has

committed to implement these 20 BWRVIP documents as discussed in the amended response

to Item 2.

The staff found the responses to RAI 4.2-BWRVIPs acceptable because they addressed all the

license renewal applicant action items as identified in the applicable BWRVIP reports, which are

listed in the response. In addition, the exceptions identified by the applicant are approved by

the staff. The staff has reviewed the updated FSAR Supplement programs and found that they

include adequate summary descriptions of the applicable BWRVIP documents. Thus the

responses are consistent with the BWRVIP reports applicable to license renewal. Therefore,

Confirmatory Item 3.1.2.3.2-1 is closed.

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The staff-approved version of BWRVIP-48 recommends enhanced VT-1 (EVT-1) for furnacesensitized (from PWHT) welds, Alloy 182 welds, and the welds attaching certain components to

the vessel. To facilitate its review, the staff issued RAI B.1.4 requesting the applicant to identify

the D/QCNPS vessel ID attachment welds, weld materials, and the welds that are furnace

sensitized. The staff also requested the applicant to identify the attachment welds that will be

inspected with enhanced VT-1. In response to RAI B.1.4, in a letter dated October 3, 2003, the

applicant identified the vessel ID attachment welds at the Dresden and Quad Cities plants.

However, it did not include the steam dryer holddown bracket attachment welds at Dresden Unit

3. However, Table 2-2 in BWRVIP-48 states that Dresden Unit 3 does have these welds. The

applicant has identified all other vessel ID attachment welds. Some of these welds are furnace

sensitized, whereas others are not. None of these welds are Alloy 182 welds. The applicant

examines all of these welds, except the surveillance sample holder attachment welds, by

enhanced VT-1 examination, as recommended by BWRVIP-48. The surveillance sample

holder attachment welds are non-safety-related welds, and the applicant examines them with

VT-1 visual examination as part of its ASME Section Xl program.

In Supplementary RAI B.1.4, the staff requested the applicant to confirm whether the steam

dryer holddown bracket attachment weld at Dresden 3 is a furnace-sensitized weld that requires

enhanced VT-1 in accordance with BWRVIP-48. In its response to Supplemental RAI B.1.4, in

a letter dated December 12, 2003, the applicant stated that the steam dryer support brackets

discussed in the response to RAI B.1.4 include the configuration for Dresden Unit 3. The

applicant further stated that the steam dryer holddown bracket attachment weld described in

Table 2-2 of BWRVIP-48 does not exist at Dresden Unit 3, and Dresden Unit 3 is the same

configuration as Dresden Unit 2 and Quad Cities Units 1 and 2. The staff finds the response

acceptable because the steam dryer holddown bracket attachment weld does not exist at

Dresden Unit 3, and therefore, the applicant does not have to provide for its inspection. The

applicant's response to RAI B.1.4 is acceptable because it is consistent with the

recommendations of BWRVIP-48.

Conclusions. On the basis of its review and audit of the applicant's program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. In addition, the staff has reviewed the

exception to the GALL program and finds that the applicant has demonstrated that the effects

of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and finds that it

provides an adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.1.2.3.3 BWR Feedwater Nozzle Program

Summary of Technical Information in the Application. The applicant's BWR Feedwater Nozzle

Program is discussed in LRA Appendix B.1.5, "BWR Feedwater Nozzle." The applicant stated

that the program is consistent with GALL Program XL.M5, "BWR Feedwater Nozzle" with no

exceptions. The applicant also stated that the program enhances the inservice inspections

specified in ASME Code Section Xl with the recommendations of General Electric (GE) NE523-A71-0594, "Alternate BWR Feedwater Nozzle Inspection Requirements."

This AMP is credited with managing aging-related cracking in reactor feedwater nozzles. The

applicant stated in the LRA that the Dresden and Quad Cities BWR Feedwater Nozzle

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Program activities have detected indications of cracking due to cyclic loading on feedwater

nozzles prior to loss of their intended function. The indications were repaired by grinding and

reexamination or the thermal sleeve was replaced. The applicant also stated that the Dresden

and Quad Cities feedwater nozzles have been modified to mitigate cracking by removing the

stainless steel cladding.

The applicant concluded that the BWR Feedwater Nozzle Program provides reasonable

assurance that cracking aging effects in the feedwater nozzles are adequately managed so that

their intended functions, consistent with the CLB, are maintained during the period of extended

operation.

Staff Evaluation. In LRA Section B.1.5, "BWR Feedwater Nozzle," the applicant described its

AMP to manage crack initiation and growth in the feedwater nozzles due to cyclic loading. The

LRA states that this AMP is consistent with GALL AMP XI.M5, "BWR Feedwater Nozzle," with

no deviations. The staff confirmed the applicant's'claim of consistency during the AMR

inspection. In addition, for D/QCNPS, the staff determined whether the applicant properly

applied the GALL program to its facility. The staff also reviewed the UFSAR Supplement to

determine whether it provides an adequate description of the program.

The applicant credited the GE report, GE-NE-523-A71-0594, "Alternate BWR Feedwater Nozzle

Inspection Requirements," for managing crack initiation and growth in the feedwater nozzle.

However, the report number does not imply a version of the report that is approved by the staff.

The report number for the version of the report that is approved by the staff is GE-NE-523-A71-

0594-A, Revision 1, published in May 2000; the designation "A" indicates the staff-accepted version. This report specifies UT of specific regions of the feedwater nozzle inner blend radius

and bore, and provides guidelines for the UT examination techniques and personnel qualifications. In Supplemental RAI B.1.5, the staff requested the applicant to confirm whether

it has implemented these guidelines as described in GE-NE-523-A71-0594-A, Revision 1. In

response to Supplemental RAI B.1.5, in a letter dated November 21, 2003, the applicant stated

that Exelon will implement the recommendations of Revision 1, Version A of the report (GE - NE-523-A71-0594-A, Revision 1), which was approved by the NRC staff. The staff finds the

response acceptable because the applicant's commitment to implement the recommendations

of the staff-approved version of the GE report would ensure that the feedwater nozzles will be

inspected as recommended in NUREG-1 801. This is Commitment #5 in Appendix A of this

SER.

Conclusions. On the basis of its review and audit of the applicant's program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. Since the GALL program is acceptable to the

staff, the applicant has demonstrated that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

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3.1.2.3.4 BWR Control Rod Drive Return Line Nozzle Program

Summary of Technical Information in the Application. The applicant's BWR Control Rod Drive

Return Line Nozzle Program is discussed in LRA Section B.1.5, "BWR Control Rod Drive

Return Line Nozzle." The applicant stated that the program is consistent with GALL Program

XI.M6, "BWR Control Rod Drive Return Line Nozzle," with one exception. This exception is

related to the NUREG-1801 requirement that the program include enhanced inservice

inspections in conformance with ASME Code Section Xl, Subsection IWB, Table IWB 2500-1,

and the recommendations of NUREG-0619, "BWR Feedwater Nozzle and Control Rod Return

Line Nozzle Cracking." The applicant stated that because the Dresden and Quad Cities CRD

return line nozzles are capped, the augmented inspections called out in NUREG-0619 are not

required. Instead, the applicant's inspections are consistent with the ASME Section Xl

requirements.

The LRA also indicated that the current code of record for the Dresden and Quad Cities

inspection programs is the 1989 Edition of ASME Section Xl, rather than the 1995 Edition

through the 1996 Addenda, as specified in NUREG-1801. The applicant stated that its

inspection program will be revised to be consistent with these NUREG-1 801 requirements prior

to the period of extended operation.

This AMP is credited with managing aging-related cracking in the CRD return line nozzles. The

applicant stated in the LRA that the Dresden and Quad Cities BWR Control Rod Drive Return

Line Nozzle Program activities have detected indications of cracking aging effects on CRD

return line nozzles prior to loss of their intended function. The indications were repairW by flaw

removal or weld overlay.

The applicant concluded in its LRA that the BWR Control Rod Drive Return Line Nozzle

Program provides reasonable assurance that cracking in the CRD return line nozzles is

adequately managed so that their intended functions, consistent with the CLB, are maintained

during the period of extended operation.

Staff Evaluation. In LRA Section B.1.5, "BWR Control Rod Drive Retum Line Nozzle," the

applicant described its AMP to manage cracking due to cyclic loading in the CRD return line

nozzles. The LRA states that this AMP is consistent with GALL AMP XL.M6, "BWR Control Rod

Drive Return Line Nozzle," with one exception concerning the implementation of augmented ISI

procedures described in NUREG-0619. The staff confirmed the applicant's claim of

consistency during the AMR inspection. Furthermore, the staff reviewed the deviation and its

justification to determine whether the AMP, with the deviation, remains adequate to manage the

aging effects for which it is credited. The staff also reviewed the UFSAR Supplement to

determine whether it provides an adequate description of the revised program. In addition, the

staff determined whether the applicant properly applied the GALL program to its facility.

The applicant stated that because the Dresden and Quad Cities CRD return line nozzles are

capped, the augmented inspections called out in NUREG-0619 are not required, and the

applicant's inspections are instead consistent with the requirements of ASME Section Xl,

Subsection IWB, Table IWB 2500-1. The staff finds this exception acceptable because the

capped CRD line nozzles are not subject to cyclic loads due to thermal stratification and

striping, and, therefore, not susceptible to cracking due to cyclic loading. However, the capped

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end of a CRD line nozzle could experience cracking due to SCC and it is evaluated in Section

3.1.2.4.1 of this SER.

Conclusions. On the basis of its review and audit of the applicant's program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. In addition, the staff has reviewed the

exception to the GALL program and finds that the applicant has demonstrated that the effects

of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21(a)(3). The staff also reviewed the UFSAR Supplement for this AMP and finds that it

provides an adequate summary description of the program, as required by 10 CFR 54.21(d).

3.1.2.3.5 BWR Penetrations Program

Summary of Technical Information in the ADplication. The applicant's BWR Penetrations

Program is discussed in LRA Appendix B.1.8, "BWR Penetrations." The applicant stated that

the program incorporates the inspection and evaluation recommendations of BWRVIP-27,

UBWR Standby Liquid Control System/Core Plate AP/SLC Inspection and Flaw Evaluation

Guidelines," and BWRVIP-49, "Instrument Penetration Inspection and Flaw Evaluation

Guidelines." The program also incorporates the water chemistry recommendations of EPRI

TR-103515-R2, "BWR Water Chemistry Guidelines." The applicant further stated that because

of the incorporation of these recommendations, the program is consistent with GALL Program

XI.M8, "BWR Penetrations."

The applicant identified one exception to NUREG-1801. GALL Program XI.M8 indicates that

the BWR water chemistry control is in accordance with BWRVIP-29, which references the 1993

revision of EPRI TR-1 03515, "BWR Water Chemistry Guidelines," whereas the D/QCNPS

Water Chemistry Programs are based on the 2000 revision of EPRI TR-1 03515-R2.

LRA Appendix B.1.8 also indicates that the current code of record for the D/QCNPS inspection

programs is the 1989 Edition of ASME Section Xl, rather than the 1995 Edition through the

1996 Addenda, as specified in NUREG-1801.. The applicant stated that its inspection program

will be revised to be consistent with these NUREG-1801 requirements prior to the period of

extended operation.

The applicant stated that the program uses relief request ISI CR-01 that provides for inspection

of the inner radius of the D/QCNPS standby liquid control system nozzles by a VT-2

examination, instead of the normal volumetric inspection required by the ASME Code.

This AMP is credited with managing crack initiation and growth due to SCC, including IGSCC,

in the BWR instrument penetrations and standby liquid control nozzles. The applicant stated

that the D/QCNPS inspection and testing methodologies have not detected cracking in these

penetrations or nozzles.

The applicant concluded that the BWR Penetrations Program provides reasonable assurance

that the aging effect of crack initiation and growth in the BWR penetrations are adequately

managed so that their intended functions, consistent with the CLB, are maintained during the

period of extended operation.

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Staff Evaluation. In LRA Appendix B.1.8, "BWR Penetrations," the applicant described its AMP

to manage crack initiation and growth in the BWR penetrations due to SCC and IGSCC. The

LRA stated that this AMP is consistent with GALL AMP XI.M8, "BWR Penetrations," with an

exception regarding water chemistry. The staff confirmed the applicant's claim of consistency

during the AMR inspection. In addition, for D/QCNPS, the staff determined whether the

applicant properly applied the GALL program to its facility. The staff also reviewed the UFSAR

Supplement to determine whether it provides an adequate description of the program.

The staff finds the applicant's exception to the GALL Water Chemistry Program to be

acceptable because it is based on updated industry experience. The evaluation of the

applicant's Water Chemistry Program (LRA Appendix B.1.2) is presented in Section 3.0.3.2 of

this SER.

Two memoranda dated July 8 and August 10, 1999, from W.H. Bateman, Division of

Engineering (NRC), to C.1. Grimes, Division of Reactor Program Management (NRC), list

several license renewal applicant action items to be addressed in the plant-specific LRA when

incorporating, respectively, the BWRVIP-27 and BWRVIP-49 reports in a renewal application.

The staff has issued a similar list of license renewal applicant action items for other BWRVIP

reports. The staff has issued a generic RAI, RAI 4.2-BWRVIPS, requesting the applicant to

submit the necessary commitments, information, and changes, as described in the license

renewal applicant action items, including an item related to UFSAR Supplement, for each of the

BWRVIP reports that are incorporated in the LRA. The details of the license renewal

applicant's action items and applicant's response to RAI 4.2-BWRVIPS is presented in Section

3.1.2.3.2 of this SER. The staff finds the applicant's response acceptable, but incomplete. The

response is acceptable, because it commits to perform a detailed review of the BWRVIP

documents applicable to license renewal, prepare an amended response addressing all the

items requested in the RAI for each of those documents, and submit it to the staff for review

and approval.

The response to RAI 4.2-BWRVIPS is incomplete because it does not address the request for

commitments to perform future inspections of currently inaccessible sites ,such as the AP/SLC

nozzle weld, when inspection tooling is made available. The AP/SLC nozzle at D/QCNPS is

welded to a stainless steel safe end. The nozzle-to-safe-end weld is susceptible to cracking

due to IGSCC. Therefore, though the ASME Code requires surface examination of this weld

because the AP/SLC line is less than 4inches in diameter, BWRVIP-27 recommends a more

stringent inspection requirement (volumetric inspection) for this weld, if accessible, when

inspection tooling is available. In Supplemental RAI 4.2-BWRVIPS, the staff requested the

applicant to commit to perform future inspections when inspection tooling is made available.

The applicant's response to Supplemental RAI 4.2-BWRVIPS is evaluated in Section 3.1.2.3.2

of this SER. The staff has found the response to be acceptable.

According to BWRVIP-27, D/QCNPS have AP/SLC nozzles made of low-alloy steel instead of

AP/SLC penetrations made of Alloy 600. BWRVIP-27 describes an inspection strategy for

these nozzles that recommends the inspection requirements of ASME Section Xl, IWB-2500,

Category B-D, which essentially includes volumetric examination for the nozzle-to-shell weld

and the nozzle inner blend radius at each inspection interval. NUREG-1801, Chapter XI.M8,

also recommends the same inspection requirements for the AP/SLC nozzles. In Appendix

B.1.8 of the LRA, the applicant stated that the Dresden and Quad Cities programs utilize relief

request ISI CR-01 (relief granted per SER dated September 15, 1995) that provides for

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inspection of the inner blend radius by a VT-2 examination instead of the normal volumetric

examination. Future relief requests may be submitted by the applicant in accordance with

10 CFR 50.55a. Otherwise, the applicant must comply with the appropriate requirements of the

ASME Code. In RAI B.1.8, the staff requested the applicant to confirm that the aforementioned

aging effects for the AP/SLC nozzles at D/QCNPS will be inspected in accordance with the

requirements of ASME Section Xl, Subsection IWB, for license renewal. In response to RAI

B.1.8, in a letter dated October 3, 2003, the applicant stated that D/QCNPS will inspect the

AP/SLC nozzles in accordance with the requirements of ASME Section Xl, Subsection IWB,

during the license renewal period, as part of the NRC-approved ISI plan in accordance with 10

CFR 50.55a. The staff finds the response acceptable because the applicant will follow the

inspection of the AP/SLC nozzles according to ASME Section Xl requirements as approved by

the staff.

Conclusions. On the basis of its review and audit of the applicant's program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. In addition, the staff has reviewed the

exceptions to the GALL program and finds that the applicant has demonstrated that the effects

of aging will be adequately manage so that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The

staff also reviewed the UFSAR Supplement for this AMP and finds that it provides an adequate

summary description of the program, as required by 10 CFR 54.21 (d).

3.1.2.3.6 BWR Vessel Internals Program

Summary of Technical Information in the Application. The applicant's BWR Vessel Internals

Program is discussed in LRA Appendix B.1.9, "BWR Vessel Internals." The applicant stated

that the program incorporates the inspection and evaluation recommendations of BWRVIP

guidelines. The program also incorporates the water chemistry recommendations of EPRI TR103515-R2, UBWR Water Chemistry Guidelines." The applicant further stated that because of

the incorporation of these recommendations, the program is consistent with GALL Program

XI.M9,"BWR Vessel Internals."

The applicant identified one exception to NUREG-1801. GALL Program XI.M9 indicates that

the BWR water chemistry control is in accordance with BWRVIP-29, which references the 1993

revision of EPRI TR-1 03515, "BWR Water Chemistry Guidelines," whereas the D/QCNPS

Water Chemistry Program is based on the 2000 revision of EPRI TR-103515-R2.

The LRA Appendix B.1.8 also indicates that the current code of record for the D/QCNPS

inspection programs is the 1989 Edition of ASME Section Xl, rather than the 1995 Edition

through the 1996 Addenda, as specified in NUREG-1801. The applicant stated that its

inspection program will be revised to be consistent with these NUREG-1 801 requirements prior

to the period of extended operation.

This AMP is credited with managing crack initiation and growth due to SCC, including IGSCC,

in the BWR vessel internals. The applicant stated that the BWR vessel internals aging

management activities have detected cracking in several vessel internals including Quad Cities

access hole covers and core spray piping at Dresden Unit 3. The applicant also reported that a

jet pump beam assembly failed at Quad Cities Unit 1 in January 2002. All similar beams at

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D/QCNPS have been replaced with beams fabricated with an improved heat treatment in

accordance with BWRVIP-41 to increase the resistance to IGSCC.

The applicant concluded that the BWR Vessel Internals Program provides reasonable

assurance that the aging effect of crack initiation and growth in the BWR vessel internals are

adequately managed so that their intended functions, consistent with the CLB, are maintained

during the period of extended operation.

Staff Evaluation. In LRA Appendix B.1.9, "BWR Vessel Internals," the applicant described its

AMP to manage crack initiation and growth in the vessel internals due to SCC, including

IGSCC. The applicant stated that this AMP is consistent with GALL AMP XI.M9, "BWR Vessel

Internals" with an exception regarding water chemistry. The staff confirmed the applicant's

claim of consistency during the AMR inspection. In addition, for D/QCNPS, the staff

determined whether the applicant properly applied the GALL program to its facility. The staff

also reviewed the UFSAR Supplement to determine whether it provides an adequate

description of the program.

The staff finds the applicant's exception to the GALL water chemistry program to be acceptable

because it is based on updated industry experience. The evaluation of the applicant's Water

Chemistry Program (LRA Appendix B.1.2) is presented in Section 3.0.3.2 of this SER.

The following letters from C.1. Grimes, NRC, to C. Terry, BWRVIP Chairman, identify several

license renewal applicant action items to be addressed in the plant-specific LRA when

incorporating the following BWRVIP reactor vessel internals guidelines in a renewal application;

dates of the letters are given in parentheses-BWRVIP-18, BWRVIP-25, BWRVIP-26,

BWRVIP-47 (December 7, 2000); BWRVIP-38 (March 1, 2001); and BWRVIP-41 (June 5,

2001). The staff has issued a generic RAI, RAI 4.2-BWRVIPS, requesting the applicant to

submit the necessary commitments, information, and changes as described in the license

renewal applicant action items, including an item related to the UFSAR Supplement for each of

the BWRVIP reports that are incorporated in the LRA. The details of the license renewal

applicant's action items and applicant's response to RAI 4.2-BWRVIPS is presented in Section

3.1.2.3.2 of this SER. The staff finds the applicant's response acceptable, but incomplete. The

response is acceptable because it commits to perform a detailed review of the BWRVIP

documents applicable to license renewal, prepare an amended response addressing all the

items requested in the RAI for each of those documents, and submit it to the staff for review

and approval.

The response to RAI 4.2-BWRVIPS is incomplete because it does not address the request for

commitments to perform future inspections of sites with limited access when inspection tooling

is made available. One such limited access site is in the BWR vessel internals. The D/QCNPS

shroud support consists of the shroud support plate with legs. It is difficult to inspect the welds

on the legs which are in the vessel lower plenum where the access is limited. The staff FSER

for BWRVIP-38, 'BWR Vessel and Internals Project, BWR Shroud Support Inspection and Flaw

Evaluation Guidelines," states that when the inspection tooling and methodologies are

developed that allow the welds in the lower plenum to be accessible, these welds should be

inspected with appropriate NDE methods. In Supplemental RAI 4.2-BWRVIPS, the staff

requested the applicant to commit to perform future inspections when inspection tooling is

made available. This is Commitment #9 in Appendix A of this SER. The applicant's response to

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Supplemental RAI 4.2-BWRVIPS is evaluated in Section 3.1.2.3.2.2 of this SER. The staff

finds the response acceptable.

BWRVIP-26, "BWR Vessel and internals Project, BWR Top Guide Inspection and Flaw

Evaluation Guidelines," states that the projected minimum end-of-life fluence at the grid beam

location after 48 EFPY of operation is approximately 6 x 1020 n/cm2 (E > 1 MeV), which is higher

than the IASCC threshold of 5 x 1020 n/cm2 (E > 1 MeV). Therefore, according to the staff final

SER for BWRVIP-26, one of the license renewal applicant action items is to identify and

evaluate the projected accumulated neutron fluence as a potential TLAA issue. In RAI B.1.9(a),

the staff requested the applicant to confirm whether D/QCNPS follows the BWRVIP-26

guidelines for managing cracking in the top guide due to IASCC. If so, then D/QCNPS needs

to evaluate the projected accumulated neutron fluence as a potential TLAA issue. The

applicant also needs to confirm that it will use EVT-1, as recommended by BWRVIP-26, to

inspect the sites on the top guide that are likely to receive neutron fluence higher than the

IASCC threshold before the end of extended operation.

In response to RAI B.1.9(a), in a letter dated October 3, 2003, the applicant stated that Dresden

and Quad Cities are following the recommendations of BWRVIP-26, "BWR Vessel and

Internals Project, BWR Top Guide Inspection and Flaw Evaluation Guidelines," including the

enhanced visual inspection technique, EVT-1, of the top guide. IASCC of the reactor internals

was evaluated as a potential TLAA and was determined not to be a TLAA. However, Dresden

and Quad Cities agree to perform inspections of the top guide similar to the inspections of the

control rod drive housing (CRDH) guide tube. The inspection of the CRDH guide tube is

performed in accordance with BWRVIP-47, 'BWR Lower Plenum Inspection and Flaw

Evaluation Guidelines." The examination extent and frequency is a 10 percent sample of the

total population within 12 years, one-half (5 percent) to be completed within 6 years.- The - -

method of examination is EVT-1. LRA Appendix 6.1.9, "BWR Vessel Internals Program," will

be enhanced to include inspection of the top guide with an examination extent and frequency

similar to the CRDH guide tube. The program enhancements will be implemented prior to the

end of the initial operating license term for Dresden and Quad Cities. The staff finds the .

applicant's response acceptable because the applicant has proposed an inspection plan that

was previously accepted by the staff. The applicant, however, needs to describe how it will

identify the sites that belong to the total population that it will consider for inspection.

Specifically, the applicant needs to confirm that only those sites where the neutron fluence

exceeds the IASCC threshold of 5 x 1020 n/cm2 (E > 1MeV) will be included in the total

population. In Supplemental RAI B.1-9(a), the staff requested the applicant to identify the

locations of the top guide, equivalent to Peach Bottom, that will be included in the total

population, and confirm that their fluences exceed the IASCC threshold limit of BWRVIP-26.

In response to Supplemental RAI B.1-9(a), in a letter dated November 21, 2003, the applicant

stated that Figures 2-1 and 2-3 of BWRVIP-26 identify 94 potential locations (total population)

of failure. The top guide grid beam locations selected for examination will be contingent on the

CRDH guide tube locations selected for inspection per BWRVIP-47. This is not necessarily

limited to the center or near the center of the core locations. However, the locations selected

for examination will be in areas that have surpassed the fluence threshold for.IASCC noted in

BWRVIP-26. As stated in BWRVIP-26, Section 2.1.1, "based on estimates made in the late

1980's all BWR/2 through BWR/5's have reached or surpassed the fluence threshold for IASCC

at the top guide grid beam locations." Dresden and Quad Cities (BWR/3 plants) are consistent

with this evaluation. The staff finds the response acceptable because it defines the total

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population of IASCC-susceptible locations on the top guide, which is consistent with BWRVIP26, and commits to select those locations for inspection that have reached or surpassed the

fluence threshold for IASCC. This is Commitment #9 in Appendix A of this SER.

The rim hold-down bolts are susceptible to stress relaxation. Therefore, the license renewal

action item for BWRVIP-25 recommends that the applicant for license renewal should identify

and evaluate the projected stress relaxation as a potential TLAA issue if a plant-specific

analysis satisfies the six criteria in 10 CFR 54.3 for a TLAA. The staff issued RAI B.1.9-b

requesting the applicant to confirm whether D/QCNPS follows the BWRVIP-25 guidelines for

managing aging of the rim hold-down bolts and, if so, to identify and evaluate whether the

projected stress relaxation in the rim hold-down bolts is a TLAA issue. In response to RAI

B.1.9-b, in a letter dated October 3, 2003, the applicant stated that D/QCNPS follows the

BWRVIP-25 guidelines for management of the hold-down bolts. However, the D/QCNPS core

plates had wedges installed along with the repair of their shrouds with tie rods. The applicant

further stated that BWRVIP-25 does not recommend inspection of rim hold-down bolts if

wedges are installed. The staff reviewed BWRVIP-25 and confirmed the accuracy of the

applicant's statements made in this response. The staff finds the applicant's response

acceptable because it follows the recommendations of BWRVIP-25, which is approved by the

staff. However, the applicant did not identify whether stress relaxation in the rim hold-down

bolts is a TLAA. The staff identified this issue as Confirmatory Item 3.1.2.3.6-1. In response,

the applicant stated that the stress relaxation of the rim hold-down bolts is not a TLAA for

Dresden or Quad Cities. Dresden and Quad Cities have installed wedge retainers, which

structurally replace the lateral load resistance provided by the rim hold-down bolts. As such,

the failure of the bolts due to stress relaxation is no longer a concern and inspection of the bolts

is not required. Therefore the stress relaxation of the rim hold-down bolts does not meet the

TLAA Criterion 5 - "involve conclusions or provide the basis for conclusion related to the

capability of the core plate to perform its intended function." Additionally, neither the rim holddown bolts, nor the wedges meets TLAA Criterion 3 - "time-limited assumptions defined by the

current operating term." The staff finds this response acceptable because the rim hold-down

bolts no longer provide structural load and do not meet the definition of a TLAA as defined in 10

CFR 54.3(a)(3) and (5). In a letter dated January 26, 2004, the applicant submitted the

information described above. Therefore, Confirmatory Item 3.1.2.3.6-1 is closed.

The applicant stated that the BWR vessel internals aging management activities at D/QCNPS

have detected cracking in several vessel internals, including core spray piping at Dresden Unit

3 and access hole covers at Quad Cities, Units 1 and 2. In RAI B. 1.9-c, the staff requested the

applicant to identify the specific BWRVIP guidelines upon which the BWR vessel internals

aging management activities at D/QCNPS are based. The applicant was also requested to

identify specific BWRVIP guidelines used to support the aging activities mentioned in LRA,

Appendix B.1.9. In its response to RAI B.1.9-c, in a letter dated October 3, 2003, the applicant

stated that the aging management activities associated with detecting these cracks in the core

spray piping were based on BWRVIP-18, "BWR Core Spray Internals Inspection and Evaluation

Guidelines." The examination methods included EVT-1. The staff finds the applicant's use of

the BWRVIP-18 recommendations acceptable for detecting cracks in the core spray piping

because BWRVIP-18 has been reviewed and approved by the staff. With respect to the access

hole covers, the applicant stated that the covers were inspected by VT-1 and VT-3 based on

the recommendations of GE SIL 462 and Supplement 1, "Shroud Access Hole Cover Cracks."

As a result of these inspections, cracks were found in the welded access hole covers for

Dresden 2 and Quad Cities 1 and 2 and all access hole covers at these three units were

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subsequently replaced with mechanical bolted covers. The applicant further stated that future inspections of the Dresden 3 welded access hole covers will continue to be based on the SIL guidance (GE SIL 462, Revision 1), as discussed in its response to RAI 3.1-8, which is

evaluated in Section 3.1.2.4.2.2 bf this SER. The inspection requirements of GE SIL 462, Revision 1, include visual and ultrasonic examination of the welded access hole covers. The staff finds the applicant's use of GE SIL 462, Revision 1, for inspecting welded access hole

covers acceptable because it is consistent with the recommendations of NUREG-1801, Item

IV.B1.1.4.

In LRA Appendix B.1.9, the applicant reported that a jet pump beam assembly failed at Quad Cities Unit 1 in January 2002, and all similar beams have been replaced with ones with

improved heat treatment. Section 2.3.2.4 of BWRVIP-41 details mitigation processes that include a specific heat treatment that improves on the old heat treatment of the jet pump beams. Section 2.3.2.7 of BWRVIP-41 also recommends, for the improved heat-treated beams

along with reduced preload, inspections consisting of no inspection during the first 10 years of service and inspection of these beams every following 10-year period at the same frequency as the old heat-treated beams with reduced preload. The staff issued RAI B.1.9(d) requesting the

applicant to submit information about how the new jet pump beams meet these BWRVIP-41

heat treatment guidelines and how they will be inspected accordingly. The RAI also requested the applicant to describe the beam assembly failure or provide a reference, and confirm

whether all the beams at all four D/QCNPS units have been replaced with ones with improved heat treatment. In response to RAI B.1.9(d), in a letter dated October 3, 2003, the applicant stated that on January 9, 2002, jet pump beam 20 for Quad Cities Unit 1 failed due to an IGSCC crack in the transition area, which was a low stress area. The applicant referred to

Quad Cities Licensee Event Report (LER) 1-02-001 for a more detailed explanation. Subsequent to this failure, Dresden and Quad Cities replaced all of the jet pump beams with

ones having improved heat treatment. The new beams are inspected based on the guidelines in BWRVIP-03 and BWRVIP-41. The review of the referenced LER, LER 1-02-001, indicates

that all of the original-style BWR/3 jet pump holddown beams were replaced with BWR/4

beams. The staff finds this corrective action acceptable because it follows the

recommendations of BWRVIP-41 (Section 2.3.2). Further review of the LER has raised the

following concern related to inspection of the jet pump beam.

LER 1-02-001 states that the crack was located in an area of the jet pump holddown beam

(transition area of the beam) that is not covered by the inspection requirements of BWRVIP-41, "BWR Jet Pump Assembly Inspection and Flow Evaluation Guidelines." The applicant therefore

stated that, although the Quad Cities Nuclear Power Station implemented the requirements of

BWRVIP-41, including periodic inspections of the required areas of the jet pump holddown

beams, the transition area of the beam was not required to be inspected and the crack was not

identified prior to failure. However, a review of Table 3.3-1, "Matrix of Inspection Options," of

BWRVIP-41 includes inspection requirements for the jet pump beam transition arm region. In

Supplemental RAI B.1.9(d), the staff requested the applicant to clarify this apparently conflicting information about inspection of the beam transition arm region.

In response to Supplemental RAI B.1.9(d), in a letter dated November 21, 2003, the applicant stated that the information it has provided not is contradictory and described the inspection of

the holddown beam as recommended by BWRVIP-41. The inspections recommended in

BWRVIP-41 are divided into both baseline and reinspection recommendations based on an

inspection cycle of 6 years. Baseline inspection required UT or another NDE technique of all

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beams during the next inspection cycle. Fifty percent of the inspections were to be performed

in the next refueling outage. Reinspection requirements are 50 percent per inspection cycle for

the first 20 years of service and 100 percent per inspection cycle beyond 20 years of service.

The applicant further stated that both Dresden and Quad Cities have performed 100 percent UT

inspections of area BB-1 (the area surrounding the bolt hole) and area BB-2 (the machined

radius or ear) during each refueling outage since 1995, which exceeds BWRVIP-41

recommendations. The beam regions that are required to be inspected per BWRVIP-41 are

location BB-1 and location BB-2, and not the transition area of the beam. However, the

cracking occurred in the transition area of the beam, located between BB-1 (the area

surrounding the bolt hole) and BB-2 (the machined radius or ear). The transition area is a low

stress location, outside the area of interest specified by the BWRVIP-41.

As part of the corrective actions from the LER root cause investigation, Exelon has requested

the BWRVIP committee to provide further evaluations of the adequacy of the examinations

performed on the holddown beams. Exelon will continue to perform the inspections required by

BWRVIP-41 (BB-1 and BB-2) and will incorporate the additional changes in inspection

methodology when incorporated into BWRVIP-41. The staff finds the response acceptable

because all of the jet pump beams have been replaced with beams fabricated with an improved

heat treatment in accordance with BWRVIP-41. This heat treatment improves the resistance to

SCC. Also, the applicant follows the BWRVIP-41 recommendations regarding inspection of the

holddown beams and commits to perform any additional inspections, such as inspection of the

transition area, when recommended by BWRVIP-41.

Conclusions. On the basis of its review and audit of the applicant's program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. In addition, the staff has reviewed the

exceptions to the GALL program and finds that the applicant has demonstrated that the effects

of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and finds that it

provides an adequate summary description of the program, as required by 10 CFR 54.21(d).

3.1.2.3.7 Thermal Aging and Neutron Irradiation Embrittlement Program

Summary of Technical Information in the Application. The applicant's Thermal Aging and

Neutron Irradiation Embrittlement Program is discussed in LRA Appendix B.1.10, 'Thermal

Aging and Neutron Irradiation Embrittlement." This is a new program for managing loss of

fracture toughness in CASS reactor internals within the scope of license renewal. The program

will be implemented prior to the period of extended operation.

The applicant stated that the program will include a component-specific evaluation of the loss of

fracture toughness. For those components where loss of fracture toughness may affect

function of the component, an inspection will be performed as part of the station ISI program.

The applicant stated that this program, when implemented, will be consistent with GALL

Program XI.M13, 'Thermal Aging and Neutron Irradiation Embrittlement."

Staff Evaluation. In LRA Appendix B.1.10, "Thermal Aging and Neutron Irradiation

Embrittlement," the applicant described its AMP to manage loss of fracture toughness in the

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CASS reactor internals due to thermal aging and neutron irradiation embrittlement. This is a

new program and will be implemented prior to the period of extended operation. This is

Commitment #10 in Appendix A of this SER. The applicant stated that this AMP, when

implemented, will be consistent with GALL AMP Xl.M1 3, "Thermal Aging and Neutron

Irradiation Embrittlement." The staff reviewed the UFSAR Supplement to determine whether it

provides an adequate description of the program.

In LRA Appendix B.1.10, the applicant stated that the component-specific evaluation for loss of

fracture toughness in CASS components will be performed. The applicant further stated that if

loss of fracture toughness affects the function of a given component, that component will be

inspected as part of the D/QCNPS ISI program. In RAI B.1.10, the staff requested the

applicant to confirm that the criteria given in GALL AMP XI.M13 will be applied to determine

whether loss of fracture toughness affects the function of the CASS vessel internals and that a

supplemental inspection program, qualified for detecting the critical flaw size with adequate

margin, will be provided for the CASS vessel internals whose function is affected.

In response to RAI B.1.10, in a letter dated October 3, 2003, the applicant submitted the

following information. AMP B.1.10 has been developed to evaluate thermal aging/neutron

embrittlement of CASS reactor internals components that are included within the scope of

license renewal. When implemented, the AMP will be consistent with the program described in

NUREG- 1801, AMP XI.M13. For each component, the ferrite content will be determined based

on Hull's equivalent factors (described in NUREG/CR-4513, Revision 1," Estimation of Fracture

Toughness of Cast Stainless Steels During Thermal Aging in LWR Systems," U.S. Nuclear

Regulatory Commission). Molybdenum content will be obtained from certified material test

reports. Based on these factors, the potentially susceptible components will be identified. For

these components, a mechanical loading assessment will be performed to determine maximum

tensile loading on the component during ASME Code Level A, B, C, and D conditions.

For components that do not satisfy the acceptance criteria, an inspection will be performed as

part of the ISI program. If any criteria are not met, a condition report will be generated for

engineering evaluation. The ISI program includes an enhanced visual inspection program for

detecting critical flaw size and is in accordance with BWRVIP-03, which has the ability to

achieve a 0.0005-in. resolution, as specified in NUREG-1801, AMP XL.M13. The staff finds the

applicant's response acceptable because it will apply the acceptance criteria given in GALL

AMP XL.M13 to determine whether loss of fracture toughness affects function of the CASS

vessel internals, and will perform enhanced visual inspection (as recommended by GALL AMP

XI.13) of components that do not satisfy these criteria.

Conclusions. On the basis of its review and audit of the applicant's program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. Since the GALL program is acceptable to the

staff, the applicant has demonstrated that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR Supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

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3.1.2.3.8 Reactor Vessel Surveillance Program

Summary of Technical Information in the Application. The applicant's Reactor Vessel

Surveillance Program is discussed in LRA Appendix B.1.22, "Reactor Vessel Surveillance."

The program is implemented through station procedures that conform to the requirements of 10

CFR Part 50, Appendix H, "Reactor Vessel Material Surveillance Program Requirements."

Neutron embrittlement for the period of extended operation is predicted using the chemistry

tables and Position 1.3, "Limitations," as described in RG 1.99, Revision 2, "Radiation

Embrittlement of Reactor Vessel Materials."

The applicant has enhanced the program by making it consistent with BWRVIP-78, "BWR

Vessel and Internals Project: BWR Integrated Surveillance Program Plan": BWRVIP-86, "BWR

Vessel and Internals Project: BWR Integrated Surveillance Program Implementation Plan:" and

the corresponding NRC safety evaluation reports and the associated RAIs. The enhanced

program provides for capsule testing consistent with BWRVIP-78 and BWRVIP-86 saving the

withdrawn capsules for future reconstitution. Existing capsules not included in the integrated

surveillance program will be maintained in the vessels as a contingency for the future. The

applicant stated that the enhanced program will be consistent with GALL AMP XI.M31, "Reactor

Vessel Surveillance."

The applicant indicated that the Reactor Vessel Surveillance Program provides that the aging

effects of irradiation embrittlement for the D/QCNPS reactor vessel components are adequately

managed so that their intended functions, consistent with the CLB, are maintained during the

period of extended operation.

Staff Evaluation. In LRA Appendix B.1.22, "Reactor Vessel Surveillance," the applicant

described its AMP to manage irradiation embrittlement of the reactor pressure vessel through

testing that monitors reactor vessel beltline materials. The LRA states that the Reactor Vessel

Surveillance Program will be enhanced by making it consistent with BWRVIP-78 and BWRVIP86 prior to the period of extended operation. The LRA further states that the enhanced

program will be consistent with GALL AMP XL.M31, "Reactor Vessel Surveillance," described in

NUREG-1801. For this AMP, GALL recommends further evaluation. The staff confirmed the

applicant's claim of consistency during the AMR inspection. The staff also reviewed the UFSAR

Supplement to determine whether it provides an adequate description of the program.

Furthermore, the staff reviewed the applicant's evaluation to determine whether it addressed

the additional issues recommended in the GALL Report, as well as in the final SERs for the

related BWRVIP documents, and confirmed that the AMP would adequately address these

issues. Finally, for D/QCNPS, the staff determined whether the applicant properly applied the

GALL program to its facility.

The applicant had submitted its license amendment to implement a program consistent with

BWRVIP-78, "Integrated Surveillance Program," and BWRVIP-86, "BWR Integrated

Surveillance Program Implementation Plan." The staff has reviewed the license amendment

and approved it in SERs to John Skolds, Exelon, from the NRC, dated September 29, 2003,

and August 28, 2003, for Dresden and Quad Cities, respectively. Therefore, the applicant has

committed and implemented the BWRVIP Integrated Surveillance Program, consistent with the

AMP XI.M31, "Reactor Vessel Surveillance," described in NUREG-1801 for the current license

period of 40 years. The staff has concluded that the final proposed BWRVIP integrated

surveillance program (ISP) was acceptable for BWR licensee implementation, provided that all

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participating licensees use one or more compatible neutron fluence methodologies acceptable

to the NRC staff for determining surveillance capsule and RPV neutron fluences. The NRC

acceptance of these reports for the current term is documented in the SER dated February 1,

2002, from Bill Bateman of the NRC to Carl Terry, BWRVIP Chairman. One of the provisions of

the ISP is for surveillance capsule material withdrawal and testing during the license renewal

period. In RAI B.1.22, the staff requested the applicant to commit that it will incorporate the

Reactor Vessel Surveillance Program consistent with the staff-approved versions of the revised

BWRVIP-78 and BWRVIP-86 documents and include this commitment in the UFSAR

Supplement for this program. This is part of Commitment #22 in Appendix A of this SER.

In response to RAI B.1.22, in a letter dated October 3, 2003, the applicant mentioned that

Section 8.1.22 of the LRA states that the Exelon Reactor Vessel Surveillance Program will be

enhanced to incorporate the reactor vessel surveillance program consistent with the staffapproved versions of BWRVIP-78 and BWRVIP-86. The applicant further stated that this

commitment is already included in Section A.1.22 of the Dresden and Quad Cities UFSAR

Supplement. The staff found the applicant's response not acceptable because it had not

committed to the revised versions of BWRVIP-78 and BWRVIP-86 that are prepared for the

period of extended operation. The staff also notes that the BWRVIP has combined these

revised versions of BWRVIP-78 and BWRVIP-86 into BWRVIP-1 16 for the period of extended

operation, which is being reviewed by the staff. The staff issued Supplemental RAI 8.1.22

requesting from the applicant additional information about the Reactor Vessel Surveillance

Program.

This RAI and the evaluation of the applicant's response to it are presented here in three parts.

In Part 1 of Supplemental RAI 8.1.22, the staff requested the applicant to commit to BWRVIP116, UBWRVIP Integrated Surveillance Program Implementation for License Renewal," July

2003, upon approval by the staff. In response to Part 1 of Supplemental RAI B.1.22, in a letter

dated November 21, 2003, the applicant stated that the Reactor Vessel Surveillance Program

(LRA Appendix 8.1.22) will be consistent with BWRVIP-1 16, "BWR Vessel and Internals

Project, Integrated Surveillance Program (ISP) Implementation for License Renewal," upon

approval by the NRC staff. This is part of Commitment #22 of Appendix A of this SER. The

staff finds the applicant's response acceptable because it has committed to make its Reactor

Vessel Surveillance Program (LRA Appendix B.1.22) consistent with BWRVIP-116, which

includes recommendations for implementing ISPs during license renewal, upon approval by the

staff.

In Part 2 of Supplemental RAI 8.1.22, the staff requested the applicant to submit plant-specific

reactor vessel surveillance programs for all four units of D/QCNPS, if the ISP program for

license renewal as described in BWRVIP-116 is not approved by the NRC, or if it is modified

such that D/QCNPS is not covered by the ISP. The staff also stated that these plant-specific

programs, if needed, should include the following actions:

* Capsules must be removed periodically to determine the rate of embrittlement and at least

one capsule with neutron fluence not less than once or greater than twice the peak beltline

neutron fluence must be removed before the expiration of the license renewal period.

* Capsules must contain material to monitor the impact of irradiation on the limiting beltline

materials and must contain dosimetry to monitor neutron fluence.

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* If capsules are not being removed from Dresden and Quad Cities plants during the license

renewal period, the applicant must supply operating restrictions (i.e., inlet temperature,

neutron spectrum and flux) to ensure that the RPV is operating within the environment of

the surveillance capsules, and must supply ex-vessel dosimetry for monitoring neutron

fluence.

In response to Part 2 of Supplemental RAI B.1.22, in a letter dated November 21, 2003, the

applicant stated that if the staff does not approve the proposed BWRVIP-1 16, Exelon will

provide a plant-specific surveillance plan for the license renewal period in accordance with

10 CFR Part 50, Appendices G and H, prior to entering the renewed license period. This is part

of Commitment #22 of Appendix A of this SER. The staff identified this issue as Confirmatory

Item 3.1.2.3.8-1. The staff finds the response acceptable because the applicant commits to

provide a plant-specific surveillance program for the license renewal period in accordance with

10 CFR Part 50, Appendices G and H, if the staff does not approve the proposed BWRVIP-1 16.

In a letter dated April 9, 2004, the applicant concurred with Commitment #22. Therefore,

Confirmatory Item 3.1.2.3.8-1 is closed.

The staff reviewed the UFSAR Supplement to determine whether it provides an adequate

description of the program. In Part 3 of Supplemental RAI B.1.22, the staff requested the

applicant to revise the UFSAR Supplement to reference the ISP for the license renewal period

(proposed BWRVIP-1 16) when approved by the NRC staff. In response to Part 3 of

Supplemental RAI B.1.22, in a letter dated November 21, 2003, the applicant revised the

UFSAR Supplements for Dresden and Quad Cities (LRA Appendix A.1.22) by including its

commitment that the Reactor Vessel Surveillance Program will be consistent with BWRVIP-1 16

upon approval by the NRC staff. This is part of Commitment #22 in Appendix A of this SER.

The staff finds the response acceptable because the revised UFSAR Supplements include the

applicant's commitment that the Reactor Vessel Surveillance Program will be consistent with

BWRVIP-1 16 upon approval by the NRC staff.

10 CFR Part 50, Appendix H, requires that an ISP used as a basis for a licensee-implemented

reactor vessel surveillance program be reviewed and approved by the NRC staff. The ISP to

be used by the applicant is a program that was developed by the BWRVIP. As discussed

above, as part of Commitment #22, the applicant will apply the BWRVIP ISP as the method by

which the Dresden and Quad Cities units comply with the requirements of 10 CFR Part 50,

Appendix H. The BWRVIP ISP identifies capsules that must be tested to monitor neutron

radiation embrittlement for all licensees participating in the ISP, and identifies capsules that

need not be tested (standby capsules). These untested capsules were originally part of the

licensee's plant-specific surveillance program and have received significant amounts of neutron

radiation.

In the most recent staff-approved version of the ISP, the RPV surveillance capsules from

Dresden and 2 and Quad Cities, Units 1 and 2, have not been designated for removal and

testing to support the ISP. However, as addressed in 10 CFR Part 50, Appendix H, Section III

(C)(1)(d) and in the staff-approved BWRVIP ISP, maintaining adequate contingencies to

support potential changes to the program is an important part of any ISP. The staff plans to

discuss with the BWRVIP the issue of maintenance of standby capsules for future use. Until

there is more detailed guidance regarding the treatment of standby capsules, the staff has

imposed the following license condition to ensure that any surveillance capsules removed from

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the Dresden or Quad Cities units, without the intent to test them, are maintained in a condition

which would permit their future use, including the period of extended operation, if necessary:

The integrated surveillance program to be implemented will be the most recent revision of the staffapproved Boiling Water Reactor Vessel and Internals Project program. If any surveillance capsules

are removed from the Dresden (Quad Cites) RPVs without the intent to test them, these capsules

must be stored in manner which maintains them in a condition which would support re-insertion into

the Dresden (Quad Cities) RPVs, if necessary."

The imposition of this license condition is consistent with actions that the staff has taken with

other, recent license renewal applicants with respect to the control of "standby" RPV

surveillance capsules.

Conclusions. On the basis of its review and audit of the applicant's program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. Since the GALL program is acceptable to the

staff, the applicant has demonstrated that the effects of aging will be adequately managed so.

that the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR Supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21 (d). Finally, the staff has included a license condition to ensure that

standby capsules will be maintained in such a manner as to ensure their usefulness should they

be needed in the future.

3.1.2.3.9 Metal Fatigue of Reactor Coolant Pressure Boundary

Summary of Technical Information in the Application. The applicant's aging management

program (AMP) for metal fatigue of the reactor coolant pressure boundary is described in LRA

section B.1.34, "Metal Fatigue of Reactor Coolant Pressure Boundary" (Metal Fatigue AMP). It,

provides means for monitoring fatigue stress cycles to ensure that the ASME Section Ill design

fatigue cumulative usage factor (CUF) limit is not exceeded during the period of extended

operation.

The applicant stated that, with enhancements, the program is consistent with the ten elements

of the NUREG 1801 AMP X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary." The

enhancements consist in the implementation of the EPRI-licensed "FatiguePro" cycle counting

and fatigue usage factor tracking computer program. The computer program provides the

capability for automated counting of fatigue stress cycles and automated calculation and

tracking of fatigue CUFs at various locations. The program will permit calculating and tracking

the cumulative usage factors for the reactor pressure vessel, Class 1 piping, the torus, torus

vents, and torus attached piping and penetrations, at the monitoring locations stated in Sections

4.3 and 4.6 of the LRA. The program will also provide for tracking of fatigue stress cycles for

the Dresden isolation condenser.

Under Element 10, "Operating Experience," of NUREG 1801 AMP X.M1, the applicant stated

that the reactor vessel cycle counting programs have been revised to incorporate changes in

design basis analysis cycles, because certain types of events were found to be more frequent

than anticipated in the original design, while others were found to be less frequent. The

applicant stated that the FatiguePro computer program was developed by the industry as a

result of NRC concerns that early-life operating cycles at some units had caused fatigue usage

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factors to increase at a greater rate than anticipated in the design analysis. The program is

designed to ensure that the code limits are not exceeded for the remainder of each unit's

licensed life and provides for incorporation of operating experience.

The applicant concludes that the aging management program for metal fatigue of reactor

coolant pressure boundary provides reasonable assurance that the thermal and pressure

transients aging effects are adequately managed so that the intended functions of pressure

boundary components within the scope of license renewal that are covered by this program are

maintained during the period of extended operation.

Staff Evaluation. In RAI B.1.34(a), the staff requested that the applicant explain how the

uFatiguePro" program and the AMP will account for CUFs at the selected monitoring locations

prior to the implementation for the period of extended operations. The applicant stated in his

response that FatiguePro has the capability of estimating the fatigue usage in one of two ways:

1) stress-based fatigue (SBF) monitoring, in which a real time stress history is determined by

the program at a given location on a given component. The program calculates the CUF at the

location from the computed stress history using appropriate cycle counting techniques and

appropriate ASME Code Section III fatigue analysis methodology. SBF monitoring duplicates

the methodology in the ASME Section III stress report for the component in question, but uses

actual transient severity in place of design transient severity. 2) Cycle-based fatigue (CBF)

monitoring, which consists of automated cycle counting and CUF computation based on the

counted cycles. The CUF is computed via a design-basis fatigue calculation where the design

basis transient severity in the fatigue table from the governing stress report is used as a basis,

but actual numbers of cycles are substituted for assumed design basis numbers of cycles. This

is Commitment #34 of Appendix A of this SER. For the time period prior to the implementation

of FatiguePro, the fatigue usage will be estimated in one of two ways. For the locations for

which SBF is specified, the initial CUF will be determined based on a linear projection of the

design basis CUF. For the locations for which CBF is specified, the initial CUF estimate will be

determined based on the cycle counts to-date since initial startup and the design basis fatigue

CUF calculation methodology. The staff finds these procedures acceptable since they conform

with accepted industry practice.

In RAI B.1.34(b), the staff requested that the applicant verify that fatigue stress cycles will be

tracked for both Dresden isolation condensers. The applicant stated that all thermal events that

have a significant impact on fatigue of critical isolation condenser components will be monitored

for both Dresden units. The staff finds this acceptable, since it states clearly that this

enhancement of the Metal Fatigue AMP will be applicable to both Dresden units.

In RAI B.1.34(c), the staff requested that the applicant provide a list, or a reference in the

Dresden/Quad Cities UFSARs, of the transients that will be monitored in the Metal Fatigue

AMP. In its response, the applicant provided the requested list of transients, which includes the

transients listed in Table 3.9-1 of the Dresden/Quad Cities UFSARs. The staff finds that this list

is acceptable since it contains the transients listed in the UFSARs and other representative

transients usually associated with BWR plant operation.

Conclusions. On the basis of its review and audit of the applicant's program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. Since the GALL program is acceptable to the

staff, the applicant has demonstrated that the effects of aging will be adequately managed so

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that the component intended functions will be maintained consistent with the CLB during the

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the

UFSAR supplement for this AMP and finds that it provides an adequate summary description of

the program, as required by 10 CFR 54.21 (d).

3.1.2.4 Aging Management Review of Reactor Vessel, Vessel Internals, and Reactor Coolant

System

In SER Sections 3.1.2.1 through 3.1.2.3, the staff determined that the applicant's AMPs will

adequately manage component aging in the reactor systems. The staff then reviewed specific

components in the reactor systems to ensure that they were properly evaluated in the

applicant's AMR. This evaluation included systems and components (LRA Table 3.1-1) that are

covered by GALL, as well as systems and components (LRA Table 3.1-2) not addressed by

GALL.

To perform this evaluation, the staff reviewed the components listed in LRA Tables 2.3.1-1

through 2.3.1-9 to determine whether the applicant had properly identified the applicable AMRs

and AMPs needed to adequately manage the aging effects for the components. This portion of

the staff review involved identification of the aging effects for each component, ensuring that

each aging effect was evaluated using the appropriate AMR in Section 3, and that management

of the aging effect was captured in the appropriate AMP. The results of the staff's review are

provided below. The staff also reviewed the UFSAR Supplements for the AMPs credited with

managing aging in reactor system components to determine whether the program description

adequately describes the program.

The following sections provide the results of the staff's evaluation of the adequacy of aging

management for components in each of the reactor vessel, vessel internals, and the reactor

coolant system.

3.1.2.4.1 Reactor Vessel

Summary of Technical Information in the Application. The description of the reactor pressure

vessel can be found in Section 2.3.1.1 of this SER. The passive, long-lived components in this

system that are subject to AMR are identified in LRA Table 2.3.1-1. The components, aging

effects, and AMPs are provided in LRA Tables 3.1-1 and 3.1-2.

Aging Effects

The applicant reviewed the industry experience (e.g., NRC information notices, generic letters,

and bulletins) and the D/QCNPS operating experience (e.g., plant maintenance history,

modifications, nonconformance reports, and licensee event reports) and identified the aging

effects, component intended functions, environment, and materials for each group of

components of the reactor pressure vessel in Tables 3.1-1 and 3.1-2 of the LRA.

The long-lived, passive pressure boundary components in this system that are subject to AMR

are fabricated of low-alloy steel with stainless steel cladding (vessel bottom heads, vessel

shells, top heads, nozzles); low-alloy steel without stainless steel cladding (top head enclosure

head flanges); Alloy 600 (penetrations including CRD stub tubes penetrations); stainless steel

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(nozzle safe ends, penetrations, vessel shell attachment welds); Alloy 82/182 (nozzle safe

ends); high-strength, low-alloy steel (top head enclosure studs and nuts, closure bolting);

carbon steel (nozzle safe ends, penetrations); and low-alloy steel (support skirts and

attachment welds).

The operating environments are reactor coolant water up to 288 0C (550 OF); steam at 288 0C

(550 OF); leaking reactor coolant water and/or steam at 288 0C (550 0F); ambient air and

humidity at metal temperatures up to 288 0C (550 0F); and containment nitrogen.

The LRA identified the following applicable aging effects for the reactor vessel:

* crack initiation and growth due to SCC, IGSSC, and cyclic loading

* cumulative fatigue damage

* loss of fracture toughness due to neutron embrittlement of beltline materials

* loss of material due to wear

In LRA Table 3.1-2 and Aging Management Review Aid Table 2.3.1-1, the applicant also listed

the following reactor vessel system components for which no aging effect (except cumulative

fatigue damage and loss of fracture toughness in the beltline region) is identified:

* external surfaces of carbon steel reactor vessel components exposed to containment

nitrogen environment

* carbon steel drain line penetrations exposed to reactor coolant water up to 288 0C (550 OF)

* low-alloy steel nozzles, head flanges, and vessel shells with or without stainless steel

cladding exposed to 288 0C (550 0F) steam

* Low-alloy steel nozzles, vessel shells and penetrations, and vessel bottom heads exposed

to reactor coolant water at 288 CC (550 OF)

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the reactor

vessel:

* Bolting Integrity Program

* Water Chemistry Program

* BWR Stress Corrosion Cracking Program

* Feedwater Nozzle Program

* Control Rod Drive Return Line Nozzle Program

* BWR Penetrations Program

* Reactor Head Closure Studs Program

* ASME Section Xl Inservice Inspection, Subsections IWB, IWC, and IWD

* BWR Vessel ID Attachment Welds Program

* Reactor Vessel Surveillance Program

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, in the reactor

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pressure vessel. The staff also reviewed the'applicable UFSAR Supplements for the AMPs to

ensure that the program descriptions adequately describe the AMPs.

Aging Effects

The aging effects for the reactor pressure vessel follow:

* crack initiation and growth due to SCC, IGSCC, and cyclic loading

* cumulative fatigue damage

* loss of fracture toughness due to neutron embrittlement of beltline materials

* loss of material due to wear

The applicant identified cracking due to SCC, IGSCC, and cyclic loading as an applicable aging

effect for the closure bolting, reactor vessel nozzle safe ends, vessel penetrations including

CRD stub tubes, feedwater nozzle, reactor head closure studs and nuts, and vessel shell

attachment welds. This identification of cracking as an applicable aging effect is consistent with

Sections IV.A1 and IV.C1 in NUREG-1801, as well as with the BWRVIP reports (BWRVIP-27,-

BWRVIP-48, BWRVIP-74, and BWRVIP-75).

LRA Table 3.1-1 (Reference Nos. 3.1.2.37 and 3.1.2.59) identifies cracking as an applicable

aging effect for a vessel head enclosure cladded with austenitic stainless steel, but NUREG1801 does not. In RAI 3.1-1, the staff requested the applicant to submit industry-wide and

plant-specific operating experience with the cladded vessel head enclosures and identify the

locations where cracking had occurred (cladding, weld metal, base metal). The staff also

requested the applicant to describe the methodology for detecting cracking and monitoring

crack growth and, if cracking is not planned to be repaired prior to the end of the current

license, provide an analysis or inspection program that will monitor the crack and provide a

basis for concluding that the ISI program will detect cracks. The staff further requested that the

applicant evaluate the cracking of the vessel head enclosure in accordance with the 10 CFR

Part 54.3, TLAA criteria. In response to RAI 3.1-1, in a letter dated October 3, 2003, the

applicant provided the following information:

* In 1990, Quad Cites Unit 2 visually detected defects (stain patches) at various points on the

RPV head cladding. Dye penetrant and UT examinations were performed to determine the

extent of the defects. The defects (cracks) were a maximum depth of approximately 6 mm

in the base material. The cracking was attributed to IGSCC and possibly hot cracking.

Subsequent examinations in 1990, 1992, and 1995, using ultrasonic through-wall sizing and

VT-1 and VT-3 methods, have indicated no change (no evidence of growth, increased

severity, or decrease in component integrity).

* In 1992, Vermont Yankee observed rust patches in the RPV head. This inspection was

performed to address the Quad Cites Unit 2 operating experience. The indications were

located primarily in the area of the flange, which had been clad by manual welding. There

was no evidence of cracking in the base material. The indications were fine, branched

cracks in the cladding, which is consistent with IGSCC.

The applicant further stated that Dresden and Quad Cities will continue to monitor the RPV

head cladding using the VT methods (VT-3) described in ASME Section Xl, IWB-2500-1, Item

B13.10. Once cracking occurs in the cladding,'the ferritic material under the cladding becomes

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exposed to the reactor water and steam environment and begins to oxidize or rust. The rust

seeps back through the cracked surface providing a readily detectable stain. The visual

examination required by ASME Section Xl was the method used to detect the evidence of

cracking (stain patches) at both Quad Cities and Vermont Yankee. The staff finds the use of

the VT-3 method to detect cracking in the cladding acceptable because this method can easily

detect stain patches resulting from rusting of ferritic material under the cracked cladding, which

allows the reactor water and steam environment to penetrate to the ferritic base metal and

oxidize it. However, the VT-3 method cannot monitor the growth of the existing cracks.

Therefore, the applicant needs to provide a method for sizing the flaws identified in the vessel

head enclosure cladded with stainless steel during the period of license renewal. This program

must satisfy the 10 elements of Branch Technical Position RLSB-1, and include, at a minimum,

the frequency, acceptance criteria, and qualifications of the inspection method. In response to

Supplemental RAI 3.1-1 in a letter dated December 17, 2003, the applicant stated that one

additional ultrasonic examination of the Quad Cities, Unit 2 reactor vessel head cladding will be

performed in 2018 (plus or minus 2 years), to verify that the relevant indication has remained

essentially unchanged. This is Commitment #7 in Appendix A of this SER. Previously, the

cracking was inspected using Ultrasonic-Through-Wall Sizing, with the last inspection

completed in 2000. The initial indication, 1990, was evaluated in accordance with ASME Code,

Section Xl, IWB-3142, which allows "Acceptance by Analytical Evaluation," proved subsequent

examinations of IWB 2420(b) and (c) were performed. IWB-2420(c) states that if the

reexaminations required by IWB-2420(b) reveal that the relevant indication remains essentially

unchanged for the three consecutive examinations, the component examination schedule may

revert to the original schedule for successive examinations. Since the three successive

examinations confirmed that the indication remained essentially unchanged, the original VT-3

examination in accordance with ASME Code, Section Xl was rescheduled for successive

examinations. This one time volumetric inspection, in addition to the scheduled VT-3

examinations, is acceptable because IGSSC of the low alloy steel head is not considered a

significant aging effect, the design is robust, and operating experience is benign as previous

years have shown. Therefore, this is a confirmatory inspection (Confirmatory Item #7), and the

one time inspection is considered to be acceptable and appropriate to confirm that the cracking

is not growing.

The applicant evaluated cracking as a potential TLAA in accordance with 10 CFR Part 54.3 and

concluded that this was not a TLAA because the analysis did not involve time-limited

assumptions defined by the current operating term at Dresden. In addition, the analysis was

not contained or incorporated by reference in the CLB at Quad Cities. The staff accepts the

applicant's conclusion that the cracking of RPV head cladding is not a TLAA because it does

not satisfy the definition of a TLAA according to 10 CFR 54.3.

The applicant stated that the CRD return line nozzles at D/QCNPS are capped, and therefore,

are not susceptible to cracking due to cyclic loading. The staff finds this acceptable because

the capped nozzle will not be subjected to cyclic loading due to thermal stratification and

striping. However, the cap and applicable weld may experience cracking due to SCC and the

applicant must provide a program to manage this cracking. The staff needed the following

information from the applicant so that it can evaluate the aging management of the capped

CRD nozzles-(1) description of the configuration and location of the capped nozzle including

the existing base material for the nozzle, piping (if piping remnants exist) and cap material, and

any welds and material type (i.e., 82/182), (2) description of how these welds and caps are

managed (e.g., the applicability of the BWRVIP-75 inspection requirements); and (3) discussion

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on whether the event at Pilgrim (leaking weld at capped nozzle, September 30, 2003) is

applicable to Dresden and Quad Cities. A description of the Pilgrim event is discussed in LER

2003-006-00, dated November 24, 2003, which states that the cracking was in an 82/182 weld

metal that was repaired extensively. The applicant also needs to include in the discussion the

past inspection techniques applied, the results obtained, mitigative strategies followed, weld

repairs carried out, and any other relevant information. The staff identified this issue as

Confirmatory Item 2.3.4.2-3.

In the applicant's letters dated January 26, 2004, and April 9, 2004, the applicant responded to

supplementary RAI 2.3.4.2-3. In the applicant's letters, the applicant provided information

related to configuration and locations of the capped nozzles for each plant and described how

they are managed. At Dresden and Quad Cities, the configuration consists of 304L and 316L

SS caps and safe-ends welded to the original carbon steel nozzles. Aging management for

these components includes examination in accordance with Section Xl of the ASME Code for

the nozzle as stated in AMP B.1.6, "CRD Return Line Nozzle," and one-time inspection in

accordance with AMP B.1.23, "One-Time InspectionsW for the remaining portion (safe-end, cap

and welds). AMP B.1.2, 'Water Chemistry" is also credited for these components.

In addition, the applicant stated that the Pilgrim event does not apply to Dresden and Quad

Cities because (1) Pilgrim used an Alloy 600 cap welded directly to the nozzle whereas

D/QCNPS used a SS cap and installed a SS safe-end between the cap and the nozzle, (2)

Pilgrim used Alloy 82/182 welds whereas D/QCNPS used 308L and 309L SS welds, and (3)

Pilgrim had initial weld defects (lack of fusion) that required repair, whereas D/QCNPS welds

were completed without requiring any repair. D/QCNPS further stated that their nozzles and

caps had radiographic and penetrant testing performed during installation, and had subsequent

ultrasonic inspection of the nozzle-to-safe end welds and safe end-to-cap welds in response to

the Pilgrim event with no reportable indications. Also, per the D/QCNPS ISI programs,

penetrant testing had been performed on these welds with no recordable indications. In

addition, Dresden and Quad Cities have placed their capped lines (small bore piping-less than 4

inches) in the One-Time Inspection Program, B.1.23. The staff finds the applicant's response

acceptable because it uses low carbon stress corrosion resistant stainless steel safe-ends,

caps, and weld material in lieu of Alloy 600, which has been known to be susceptible to stress

corrosion cracking based on operating experience. In addition, the caps were welded using low

carbon stainless steel weld metal (308L and 309L) with no weld repairs or recordable defects.

Pilgrim used Inconel 82/182 and had initial weld defects that required weld repairs, which may

have contributed to the cracking. Therefore, Dresden and Quad Cities capped return line

nozzle configuration is not similar to Pilgrim and the use of AMPs B.1.2, B.1.6 and B.1.23 is

acceptable for managing the aging of these components. Therefore, Confirmatory Item

2.3.4.2-3 is closed.

In LRA Table 3.1-1, the applicant identified cumulative fatigue damage as an applicable aging

effect for nozzles and their safe ends, vessel penetrations, support skirts and attachment welds,

top head flanges, vessel flanges, vessel shells, including upper shell, intermediate nozzle shell,

intermediate beltline shell, and lower shell, and vessel bottom heads. However, it is not clear

whether this identification of cumulative fatigue damage as an aging effect applies to all four

units (Dresden Units 2 and 3 and Quad Cities Units 1 and 2). Table 2.3.1-1 of the Aging

Management Review Aid provided by the applicant identifies cumulative fatigue damage as an

aging effect for support skirts exposed to ambient temperature air, but not for the ones exposed

to containment nitrogen. In RAI 3.1-2, the staff requested the applicant to confirm whether the

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identification of cumulative fatigue damage as an aging effect applies to all four units. If not,

the applicant was requested to provide a technical explanation. The staff also requested the

applicant to identify the containment environment in each unit. In response to RAI 3.1-2, in a

letter dated October 3, 2003, the applicant stated that the aging effect of cumulative fatigue

damage does apply to all four units (Dresden Units 2 and 3 and Quad Cities Units 1 and 2).

The applicant further stated that at all four units, the primary containment (drywell and

suppression pool) atmosphere is made inert with nitrogen to render the primary containment

atmosphere nonflammable by maintaining the oxygen content below 4 percent by volume

during normal operation. The drywell has an average temperature of 570C (135 'F) during

normal operations. The relative humidity in the drywell ranges between 20 percent and 90

percent. The staff finds the applicant's identification of cumulative fatigue damage as an

applicable aging effect for the vessel components at all four D/QCNPS units acceptable

because it is consistent with NUREG-1801, Chapter IV.A1, as well as with BWRVIP-74.

The applicant, however, did not identify cumulative fatigue damage as an applicable aging

effect for stabilizer brackets, the external attachment weld between reactor pressure vessel and

refueling bellows, and the reactor vessel closure studs, although BWRVIP-74 does identify

such aging effects. In addition, the applicant does not identify cumulative fatigue damage as an

applicable aging effect for closure bolting, but NUREG-1 801 (Item C1 .2-f, Chapter IV.C1) does.

In RAI 3.1-3, the staff requested the applicant to submit an explanation of why cumulative

fatigue damage is not identified as an applicable aging effect for stabilizer brackets, the

external attachment weld between reactor pressure vessel and refueling bellows, the reactor

vessel closure studs, and closure bolting. The staff further requested the applicant to provide

an appropriate program for managing cumulative fatigue damage, if this effect is identified as

an applicable aging effect for these components.

In response to RAI 3.1-3, in a letter dated October 3, 2003, the applicant stated that for

Dresden and Quad Cities there are no CLB TLAAs that evaluate cumulative fatigue of the RPV

stabilizer brackets or of the external attachment weld between reactor pressure vessel and

refueling bellows. The applicant provided the following additional explanation about the weld

between the reactor pressure vessel and refueling bellows. The refueling bellows attached to

the reactor pressure vessel prevent leakage from the flooded reactor cavity into the drywell

during refueling operations. However, the function of preventing leakage into the drywell during

refueling operations is not a safety-related function and failure of the vessel-to-bellows weld

cannot cause failure of a safety-related function. Therefore, the refueling bellows are not within

the scope of license renewal. Consequently, the external attachment weld between the reactor

pressure vessel and the refueling bellows is not within the scope of license renewal. The staff

finds the applicant's explanation for not identifying cumulative fatigue damage as an aging

effect for the RPV stabilizer brackets and the external attachment weld between the RPV and

refueling bellows acceptable because they are not in scope of license renewal.

Regarding the reactor vessel closure studs, the applicant stated that LRA Table 2.3.1-1,

"Component Groups Requiring Aging Management Review -Reactor Vessel," should have

included Aging Management Reference 3.1.1.1 in the Top Head Enclosure (Closure Studs and

Nuts) line. The applicant further pointed out that LRA Section 4.3.1, "Reactor Fatigue

Analysis," identifies the reactor vessel closure studs as components that may experience

cumulative fatigue damage. The reactor vessel closure studs are included in the Fatigue

Monitoring Program that is described in Section 4.3.1 of the LRA. The staff finds the applicant's

response acceptable because LRA Section 4.3.1 does identify the RPV studs as components

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that experience cumulative fatigue damage. This evaluation is presented in Section 4.3.1 of

this SER.

Regarding closure bolting, the applicant stated that Item C1.2-f, Chapter IV.C1, of NUREG1801 is the closure bolting for the recirculation pump. The aging effect of cumulative fatigue for

the recirculation pumps' closure bolting is shown in LRA Table 3.1-1, Aging Management

Reference 3.1.1.1, which links to the Closure Bolting line of LRA Table 2.3.1-5, "Component

Groups Requiring Aging Management Review-Recirculation System." The staff finds the

applicant's response acceptable because the LRA does identify cumulative fatigue damage as

an applicable aging effect for closure bolting.

The applicant identified loss of fracture toughness as an applicable aging effect for the reactor

pressure vessel flange, intermediate beltline shell, beltline welds, intermediate nozzle shell,

lower shell, and upper shell. NUREG-1801, however, identifies this aging effect only for the

intermediate beltline shell and beltline welds. In RAI 3.1-4, the staff requested the applicant to

identify the components that are expected to have neutron fluence greater than 1017 n/cm2 (E>1

MeV) by the end of the extended period of operation. In response to RAI 3.1-4, in a letter dated

October 3, 2003, the applicant identified the following four components that are expected to

have a neutron fluence greater than 1017 n/cm2 (E>1 MeV) by the end of the extended period of

operation-lower shell, intermediate beltline shell, axial welds in these two shells, and girth weld

between these two shells. The applicant identified LRA Appendix B.1.22, uReactor Vessel

Surveillance," as an AMP for managing loss of fracture toughness in these components. The

staff finds the response acceptable because the identification of an AMP to manage loss of

fracture toughness is consistent with NUREG-1 801. However, it is not clear to the staff whether

the applicant has taken into account the increased fluence on the RPV wall due to power

uprates that have been implemented at D/QCNPS. In Supplemental RAI 3.1-4, the staff

requested the applicant to clarify whether the fluence calculations for the reactor vessel

included the effects of power uprates when determining which components are susceptible to

loss of fracture toughness. In response to Supplemental RAI 3.1-4, in a letter dated November

21, 2003, the applicant stated that the fluence calculations for the reactor vessel did include the

effects of power uprates when determining the components that are susceptible to loss of

fracture toughness. The staff finds the response acceptable because it facilitates the proper

identification of reactor vessel beltline shell and welds that are susceptible to loss of fracture

toughness due to neutron irradiation embrittlement.

The applicant identified loss of material due to wear as an applicable aging effect for closure

bolting. This is consistent with NUREG-1801 Chapter IV.C1. However, the applicant did not

identify loss of preload as an aging effect for closure bolting in the reactor vessel system. In

LRA Section 3.1.1.2.2, the applicant referred to EPRI 1003056, Revision 3, which states that

loss of preload mechanisms are typically addressed during installation and subsequent

maintenance of closure bolting. The EPRI report further states that as the loss of preload is a

design driven effect, it is not an applicable aging effect and does not require aging

management. Loss of preload, however, may take place during operation when closure bolting

is subject to stress relaxation, cyclic loads, and differential thermal expansion. NUREG-1.801,

Chapter XI.M18, uBolting Integrity," requires this program to include periodic inspection of

closure bolting for indication of loss of preload. In RAI 3.1-13, the staff requested the applicant

to explain why periodic inspection of the closure bolting for indication of loss of preload due to

the aforementioned mechanisms is not required. The staff further requested the applicant, if

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periodic inspection is required, to reference the appropriate AMP and include the appropriate

inspection in the AMP.

In response to RAI 3.1-13, in a letter dated October 3, 2003, the applicant stated that Exelon

will manage the loss of preload for closure bolting in the reactor vessel system and other

systems, such as recirculation pumps, reactor recirculation valves, and reactor vessel head

vent valves, and the reactor pressure boundary portion of all other systems. This is part of

Commitment #12 of Appendix A in this SER. The applicant further stated that AMP, LRA

Appendix B.1.12, "Bolting Integrity," will be enhanced to include periodic inspections of the

closure bolting in accordance with the ASME Code Section Xl requirements. This part of

Commitment #12 of Appendix A in this SER. Closure bolting will be periodically inspected for

signs of leakage. The enhanced Bolting Integrity Program will be comprised of periodic ISI and

piping and component preventive maintenance inspections. These activities will detect early

leakage and material degradation of closure bolting (that may be caused by loss of material or

cracking) prior to loss of system or component intended functions.

The staff finds the applicant's response not to be completely acceptable because LRA Section

3.1.1.2.1 does not address loss of preload as an aging effect, and states that loss of preload

mechanisms is typically addressed during installation and subsequent maintenance of closure

bolting. However, the applicant's response to RAI 3.1-13 stated that loss of preload will be

managed, and that the enhanced Bolting Integrity Program will be comprised of periodic ISI and

piping and components preventive maintenance inspections.

In Supplemental RAI 3.1-13, the staff requested the applicant to describe the maintenance

program activities that are performed on the bolts so that loss of preload is significantly reduced

or eliminated, and to identify whether retorquing of the bolts to the design preload values is

performed after the component is reassembled. In response to Supplemental RAI 3.1-13, in a

letter dated November 21, 2003, the applicant stated that the Exelon procedure governing

'Torquing and Tightening of Bolted Connections" requires the inspection and documentation of

closure bolting connections prior to disassembly for signs of leakage; missing, cracked,

degraded or loose bolts or nuts; misalignment of connection; gasket condition; and corrosion.

When closure bolting connections are disassembled for maintenance, bolts are loosened in two

increments using a crossing sequence to prevent distortion of the mating surfaces. Bolts,

studs, and washers are cleaned of corrosion, grit, and dried lubricant. They are also inspected

for galling of threads or nut facing, dings and dents in threads, cracks, pits, erosion, corrosion,

bent bolts, dished or galled washers, and elongation. If damaged bolts, studs, nuts or washers

are found, they are replaced or repaired. Prior to reassembly, the correct torque value is

determined from history that has been validated by successful performance, design drawings,

vendor prints, plant design specification, or procedures. When required by design drawings,

vendor prints, plant design specifications, or procedures, approved lubricant is applied to the

bolts, studs, and nuts. Bolts or nuts are first hand tightened using a crossing sequence and

then torque tightened using a diametrically opposed pattern in three passes (for as low as

reasonably achievable (ALARA) areas) or four passes (non-ALARA areas). This is part of

Commitment #12 of Appendix A of this SER.

Conditions that involve leakage, insufficient gasket compression, or other situations that require

torque values to be increased require engineering review. All torque values are documented.

The staff finds the applicant's response acceptable because the applicant's procedure

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governing torquing and tightening of bolted connections ensures that the loss of preload will be

eliminated or reduced when the bolted connections are reassembled.

The staff finds that the applicant's identification of no aging effect (except cumulative fatigue

damage and loss of fracture toughness in the beltline region) for the low-alloy steel vessel

shells, nozzles, and flanges internally exposed to 288 °C (550 OF) steam or reactor coolant

water is acceptable because it is supported by industry operating experience and it is consistent

with GALL. However, the applicant's identification of no aging effect for the external surface of

carbon steel reactor vessel components exposed to a containment nitrogen environment is not

acceptable because the BWR containment environment typically has high humidity. The

carbon steel components exposed to this environment may experience loss of material due to

corrosion. In RAI 3.1-5, the staff requested the applicant to explain why loss of material is not

identified as an aging effect for these components, or provide a program for managing that

effect. In response to RAI 3.1-5, in a letter dated October 3, 2003, the applicant first described

the environment of the drywell and then explained why loss of material is not an applicable

aging effect for the carbon steel RPV components exposed to the containment environment.

The drywell is made inert with nitrogen to render the primary containment atmosphere

nonflammable by maintaining the oxygen content below 4 percent by volume during normal

operation. The drywell has an average temperature of 135 0F during normal operations. The

relative humidity in the drywell ranges between 20 percent and 90 percent.

According to EPRI 1003056, "Non-Class 1 Mechanical Implementation Guideline and

Mechanical Tools, Revision 3," loss of material due to corrosion is not considered a credible

aging effect for carbon steel components in a containment nitrogen environment because of the

negligible amounts of free oxygen (less than 4 percent). Both oxygen and moisture must be

present for general corrosion to occur because oxygen alone or water free of dissolved oxygen

(high humidity in a nitrogen atmosphere) does not corrode carbon steel to any practical extent.

The staff finds the applicant's identification of no loss of material for the carbon steel

components exposed to a containment nitrogen environment acceptable because, with the

negligible amounts of free oxygen, anodic reactions do not take place and the corrosion cell

does not form. Therefore, no loss of material due to corrosion takes place.

The applicant's identification of no aging effect for the carbon steel drain line penetrations

exposed to reactor coolant water up to 288 °C (550 OF) is not acceptable because the drain line

is likely to experience loss of material due to corrosion. This assessment is consistent with Item

D2.1 -a, Chapter V.D2, of NUREG-1801. In RAI 3.1-6, the staff requested the applicant to

explain why loss of material is not an applicable aging effect for the drain line, or provide a

program for managing such effect. In response to RAI 3.1-6, in a letter dated October 3, 2003,

the applicant states that the drain line penetration is an unclad hole drilled into the reactor

vessel bottom head with an unclad carbon steel nozzle welded to the outside of the vessel

bottom head. The applicant further stated that Aging Management Reference 3.1.2.58 should

have shown loss of material/general, pitting, and crevice corrosion as an applicable aging

effect. The applicant identified the ASME Section XI Inservice Inspection (LRA Appendix

8.1.1) and Water Chemistry (LRA Appendix B.1.2) Programs for managing this aging effect.

The staff finds the response acceptable because the applicant has identified loss of material as

an applicable aging effect and provided the AMPs that are consistent with GALL to manage it.

The aging effects identified in the LRA for the reactor vessel are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

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applicant identified all plausible aging effects, and that the aging effects listed are appropriate

for the combination of materials and environments specified.

Aging Management Programs

The applicant credits the following programs for managing aging in the reactor pressure

vessels. The staff reviewed these programs in the sections of the SER listed in the

parentheses.

* ASME Section Xl Inservice Inspection Program (Section 3.0.3.1)

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress Corrosion Cracking Program(Section 3.0.3.3)

* Bolting Integrity Program (Section 3.0.3.5)

* Reactor Head Closure Studs Program (Section 3.1.2.3.1)

* BWR Vessel ID Attachment Welds Program (Section 3.1.2.3.2)

* Feedwater Nozzle Program (Section 3.1.2.3.3)

* Control Rod Drive Return Line Nozzle Program (Section 3.1.2.3.4)

* BWR Penetrations Program (Section 3.1.2.3.5)

* Reactor Vessel Surveillance Program (Section 3.1.2.3.8)

The first four AMPs (ASME Section XI Inservice Inspection, Water Chemistry, BWR Stress

Corrosion Cracking, and Bolting Integrity) are credited with managing the aging effects in

several components in various different structures and systems and are, therefore, considered

common AMPs. The staff has evaluated these common AMPs and found them to be

acceptable for managing the aging effects identified for reactor pressure vessels. The staff's

evaluation of these AMPs is documented in Section 3.0 of this SER. The remaining six AMPs

are credited with managing aging effects only in reactor pressure vessels and the staff's

evaluation of those AMPs is documented in Section 3.1.2.3 of this SER.

The applicant credited the BWR Stress Corrosion Cracking (LRA Appendix B.1.7) and Water

Chemistry (LRA Appendix B.1.2) Programs for managing cracking due to IGSCC in reactor

vessel safe ends. The BWR Stress Corrosion Cracking Program is based on BWRVIP-75,

"Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules." In RAI B.1.7-a,

the staff requested the applicant to submit information about its plant-specific experience

related to IGSCC cracking of the reactor vessel safe ends and reactor coolant pressure

boundary piping, mitigative actions taken, and the revised inspection schedules following the

BWRVIP-75 guidelines. The staff also requested the applicant to submit information about

whether hydrogen water chemistry (HWC) and noble metal chemical application (NMCA) are

implemented at D/QCNPS and how this implementation has affected monitoring of water

chemistry parameters. The applicant's response to this RAI is evaluated in Section 3.1.2.4.3 of

this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the reactor

vessel will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds that the applicant has demonstrated that

the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

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3.1.2.4.2 Reactor Vessel Internals (Including Fuel Assemblies and Control Blades)

Summary of Technical Information in the Application. The description of the reactor pressure

vessel internals can be found in Section 2.3.1.2 of this SER. The passive, long-lived

components in this system that are subject to an AMR are identified in LRA Table 2.3.1-2. The

components, aging effects, and AMPs are provided in LRA Tables 3.1-1 and 3.1-2.

The long-lived, passive reactor internals that are subject to an AMR are fabricated of Alloy 600

and Alloy 82/182 weld metal (welded and mechanical access hole covers, shroud support

structures); cast austenitic steel (jet pump assemblies, orificed fuel structural supports); Alloy

X750 (et pump holddown beams); and stainless steel (CRD tubes and housing, core plates and

bolts, core shrouds, core spray lines and spargers, incore instrumentation dry tubes and guide

tubes, jet pump assemblies, orificed fuel support pieces, orif iced fuel structural supports,

reactor internal modifications/repair hardware/structural support, top guides). The operating

environments are high-purity water at 288 0C (550 0F) and reactor coolant water up to 288 C-

(550 0F).

The description of the fuel assemblies and control blades can also be found in Sections 2.3.1.2

of this SER. The applicant stated that fuel assemblies and control blades do not require AMR

because they are short-lived.

Aging Effects

The LRA identified the following applicable aging effects for the reactor vessel internals:

* crack initiation and growth due to SCC, IGSCC, and IASCC

* cumulative fatigue damage

* loss of fracture toughness due to thermal aging and neutron irradiation embrittlement

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the reactor

vessel internals:

* ASME Section Xl Inservice Inspection Program

* Water Chemistry Program

* BWR Vessel Internals Program

* Thermal Aging and Neutron Irradiation Embrittlement Program

Staff Evaluation. This section provides the results'of the staff's evaluation of the applicant's

AMR for the aging effects and the AMPs credited for managing the aging effects in reactor

vessel internals. The staff also reviewed the applicable UFSAR Supplements for the AMPs to

ensure that the program descriptions adequately describe the AMPs.

The staff accepts the applicant's determination that the D/QCNPS fuel assemblies and control

blades do not require aging management because these components are short-lived.

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Aging Effects

The aging effects for the reactor vessel internals are as follows:

* crack initiation and growth due to SCC, IGSCC, and IASCC

* cumulative fatigue damage

a loss of fracture toughness due to thermal aging and neutron irradiation embrittlement

The applicant identified cracking due to SCC, IGSCC, and IASCC for all the vessel internals

except orificed fuel support pieces. This is consistent with Chapter IV.B1 of NUREG-1 801.

However, some additional information is needed. The applicant has identified core spray line

and spargers and jet pump assemblies as two of the vessel internals. The applicant needs to

confirm whether the following subcomponents, which are identified in Appendix C of BWRVIP18, are included as part of the core spray line and spargers for aging management-junction or

tee box connections at the vessel nozzle or shroud penetration, sparger spray nozzle, support

bracket, and thermal sleeve. Since the staff needed similar confirmation for the vessel

internals addressed by other BWRVIP documents that the applicant has referenced in the LRA,

the staff issued a generic request for information, RAI 4.2-BWRVIPS, requesting the applicant

to verify that D/QCNPS is bounded by the BWRVIP documents referenced in the LRA. The

applicant's response to Confirmatory Item 3.1.2.3.2-1 is evaluated in SER Section 3.1.2.3.2.

The staff finds the response acceptable because it is consistent with the BWRVIP reports

applicable to license renewal.

In RAI 2.3.1.2-5, the staff requested the applicant to identify all the components included in

component group, "Jet Pump Assemblies," and explain why jet pump sensing lines are not

within the scope of license renewal. In response to RAI 2.3.1.2-5, in a letter dated

December 22, 2003, the applicant identified the following components that are included in the

jet pump assemblies-thermal sleeve, inlet header, riser brace arm, hold-down beams, inlet

elbow, mixing assemblies, and diffuser. The staff compared the applicant's response to the list

of BWR jet pump assembly components that are within the scope of license renewal as

identified in Appendix A (Section A.2) of BWRVIP-41. The staff finds that the applicant has not

identified the transition piece, riser pipe, adapter, and restrainer bracket as within scope. The

applicant needs to provide an explanation for not including these four components in

component group, "Jet Pump Assemblies." In response to Supplemental RAI 2.3.1.2-5, the

applicant stated that the transition piece, riser pipe, adapter, and restrainer bracket are included

in the Component Group "Jet Pump Assemblies." The previous response considered the

transition piece and riser pipe to be part of the inlet header and the adapter as part of the part

of the diffuser. The restrainer bracket was not specifically identified, but is part of the

assembly. The staff finds the applicant's response acceptable because it identifies all of the

required components addressed in BWRVIP-41. The applicant's explanation for not including

jet pump sensing lines within the scope of license renewal is evaluated in Section 3.1.2.2.4(2)

of this SER and is found acceptable.

D/QCNPS have used extended power uprates to increase the power output of each of the four

units by about 17 to 18 percent (NRC Fact Sheet on Power Uprates for Nuclear Plants,

February 2002). Such increase in power may increase the fluence on vessel internals, and the

sites on some of the components that were not susceptible to IASCC may become susceptible.

The final license renewal SER for BWRVIP-26 states that the threshold fluence level for IASCC

is 5 x 1020 n/cm2 (E > 1 MeV). In RAI 3.1-7(a), the staff requested the applicant to explain

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whether this increase in power has been accounted for in performing AMR of vessel internals.

The staff also requested the applicant to identify the vessel internals whose fluence at the end

of the extended period of operation may exceed the threshold level and become susceptible to

cracking due to IASCC. In response to RAI 3.1-7(a), in a letter dated October 3, 2003, the

applicant stated that the fluence calculations prepared specifically for the Dresden and Quad

Cities LRA included the effects of extended power uprate. The top guide, shroud, and the

incore instrumentation guide tubes and dry tubes may exceed the threshold fluence value of 5 x

1020 n/cm2 (E > 1 MeV) by the end of the period of extended operation. As such, these

components will require aging management. The AMPs used to manage the IASCC aging

effect are LRA Appendices B.1.2, 'Water Chemistry," and B.1.9, "BWR Vessel Internals." The

staff finds the response acceptable because LRA Appendix B.1.9 indicates that the applicant

will follow the recommendations of the related BWRVIP documents, and the applicant's

inspection program considers the effects of IASCC as discussed in this section and Section

3.1.2.3.6.

The applicant identified cumulative fatigue damage as an applicable aging effect for core

plates; core spray line and spargers; jet pump assemblies; orificed fuel supports; top guides;

and incore instrumentation dry tubes and guide tubes. This identification of the aging effect is

consistent with Chapter IV.B1 of NUREG-1801.

The applicant identified loss of fracture toughness due to thermal aging and neutron irradiation

embrittlement as an applicable aging effect for castings in jet pump assemblies and CASS

orificed fuel supports. This identification of the aging effect is consistent with Items B1.4-c and

B1.5-b, Chapter IV.B1, of NUREG-1801.

The aging effects identified in the LRA for the reactor vessel internals are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant credited the following AMPs to manage the aging effects described above for the

reactor vessel internals. The staff reviewed these programs in the sections of the SER listed in

parentheses:

* ASME Section Xl Inservice Inspection Program (Section 3.0.3.1)

* Water Chemistry Program (Section 3.0.3.2)

* BWR Vessel Internals Program (Section 3.1.2.3.6).

* Thermal Aging and Neutron Irradiation Embrittlement Program (Section 3.1.2.3.7)

The first two AMPs (ASME Section XI Inservice Inspection and Water Chemistry) are credited

with managing the aging effects in several components in various different structures and

systems and are, therefore, considered common AMPs. The staff has evaluated these

common AMPs and found them acceptable for managing the aging effects identified for the

reactor vessel internals. The staff's evaluation of these AMPs is documented in Section 3.0 of

the SER. The remaining two AMPs are credited with managing aging effects only in the reactor

vessel internals and the staff's evaluation of those AMPs is documented in Section 3.1.2.3.6

and 3.1.2.3.7 of the SER.

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The reactor vessel internals that may receive neutron fluence greater than the threshold fluence

for IASCC (5 x 1020 n/cm2 [E > 1 MeV]) by the end of the extended period of operation are

susceptible to cracking due to IASCC. Per license renewal SER for BWRVIP-26, the

accumulated neutron fluence is a TLAA issue for these vessel internals. The SER for BWRVIP26 further states that the applicant must identify and evaluate this TLAA issue. In RAI 3.1-7b,

the staff requested the applicant to submit identification and evaluation of the accumulated

neutron fluence received by the D/QCNPS vessel internals at the end of license period as a

TLAA issue.

In response to RAI 3.1-7b, in a letter dated October 3, 2003, the applicant stated that as

mentioned in the response to RAI 3.1-7a above, fluence calculations were prepared for the

reactor vessel and internals, including the effects of extended power uprate. Three

components have been identified as being susceptible to IASCC for the period of extended

operation-(1) top guide, (2) shroud, and (3) incore instrumentation dry tubes and guide tubes.

As such, these components will require aging management as discussed above.

However, contrary to the direction contained in the SER for BWRVIP-26, this technical issue

does not qualify as a TLAA. Specifically, the analysis is not contained or incorporated by

reference in the CLB for either site. As such, it does not satisfy Criterion (6) of 10 CFR 54.3,

'Definitions, Time Limited Aging Analyses." Dresden and Quad Cities stations will implement

the BWRVIP recommendations and manage the effects of aging of IASCC through AMPs B.1.2

(Water Chemistry) and B.1.9 (BWR Vessel Internals). Therefore, the staff agrees that

10 CFR 54.21 (c)(1)(iii) allows the applicant to manage the effects of aging on the intended

functions for the period of extended operation in lieu of performing a TLAA evaluation. The

response to RAI 3.1.7b states that Dresden and Quad Cities will implement the BWRVIP

recommendations and manage the effects of aging of IASCC through AMPs B.1.2 (Water

Chemistry) and B.1.9 (BWR Vessel Internals). AMP B.1.9 is consistent with NUREG-1801

which references the use of BWRVIP-26 for the inspection of the reactor vessel internals,

including the top guide, and BWRVIP-76 for the inspection of the shroud. However, according

to Table 2-1 of BWRVIP-76, when fluences exceed 5 x 1020 n/cm2, a plant-specific analysis is

required to be submitted to the NRC. The staff identified this issue as Confirmatory

Item 3.1.2.4.2-1. In response to Confirmatory Item 3.1.2.4.2-1, in a letter dated April 9, 2004,

the applicant states that Table 2-1 of BWRVIP-76 provides inspection guidance for welds in

un-repaired core shrouds. Note 4 of Table 2-1 indicates that for plants where fluence at the

shroud exceeds 5x102° n/cm2, a plant-specific analysis is required to be submitted to the NRC.

However, this analysis is only for un-repaired core shrouds. Since the core shrouds at Dresden

and Quad Cities have been repaired and the repairs structurally replace the horizontal welds,

the plant-specific analysis suggested by Table 2-1 is not applicable to these shrouds. The

applicant further states that the inspection frequencies for the D/QCNPS shrouds are

determined using the guidance contained in Section 3 of BWRVIP-76. The applicant inspects

the vertical core shroud welds in accordance with BWRVIP-76, Section 3. The staff finds the

response consistent with BWRVIP-76. Since the applicant has committed to implement

BWRVIP-76 when the staff SER is issued, this completes our review of this issue. Therefore,

Confirmatory Item 3.1.2.4.2-1 is closed.

BWRVIP-47, which was approved by the staff in an SER dated December 7, 2000, does not

require inspections of the incore instrumentation dry tubes and guide tubes because of the

service history and minimal safety consequence of the tube failure. However, by letter dated

December 22, 2003, the applicant stated that the program is enhanced by inspecting the incore

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instrumentation dry tubes every outage in accordance with GE SIL-409, Revision 1, for this

specific GE dry tube model. SIL 409 recommends that dry tubes with detected cracks be'

replaced. Inspection of the source range monitor (SRM) and IRM dry tubes/guide tubes to

detect the aging effects of IASCC are-included in Exelon's AMP B.1.9, BWR Vessel Internals.

Inspection of the dry tubes that have not been replaced are performed in accordance with the

recommendations of SIL-409 during each refueling outage. Exelon has replaced incore dry

tubes during refueling outages. When a dry tube is replaced, the inspection interval for the

replacement dry tube is extended to 20 years as recommended by SIL-409. After the 20 year

inspection has been completed, additional inspections are performed once every 4 years. The

staff finds that the applicant exceeds the inspection requirements of NUREG-1801 for the ' ,

incore instrumentation dry tubes. Inspection of the top guide is discussed in Section 3.1.2.3.6.

Therefore, the staff finds that the applicant is managing the IASCC aging effect by inspection

programs, in lieu of performing a TLAA evaluation, in accordance with the requirements of 10

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

The applicant credited ASME Section Xi Inservice Inspection Program for managing cracking in

the welded access hole covers due to SCC. This program requires visual inspection for - -

detecting cracking. However, a crevice may be present near the weld and visual inspection is

not adequate for detecting cracking initiated in the crevice region. Therefore, in'RAI 3.1-8, the

staff requested the applicant to provide a justification for why an augmented inspection

technique that includes UT or another demonstrated acceptable inspection method for the

welded access hole cover is not required, or to provide augmented inspection as specified in

NUREG-1801, Item IV.B1.1.4. In response to RAI 3.1-8, in a letter dated October 3, 2003, the

applicant stated that the augmented inspection technique discussed in NUREG-1 801, Item

IV.B13.1.4, is applicable to welded access hole covers. Since Dresden Unit 2 and Quad Cities

Units 1 and 2 have replaced the welded access hole covers with mechanical covers, the '

augmented inspections are not required on these units. The Dresden Unit 3 welded access

hole covers are inspected visually and augmented by ultrasonic examination consistent with the

requirements of GE SIL 462, 'Shroud Access Cover Cracking and Radial Cracking," Revision 1,

as specified in NUREG-1801, Item IV.B1.1.4. This inspection is specified in LRA Table 3.1-1,

Reference No.3.1.1.18. This response is acceptable to the staff because the applicant is

inspecting the welded access hole covers with ultrasonic examination as recommended by GE

SIL 462, Revision 1, and NUREG-1801, Item IV.B13.1.4.

In RAI 4.2-Flaw Evaluation, the staff requested the applicant to confirm whether there have

been any flaws that were left in service based on'ASME Code Section Xl analysis techniques.

If so, the staff requested the applicant to confirm whether it considered such analyses as

potential TLAAs. In response to RAI 4.2-Flaw Evaluation, in a letter dated October 3, 2003, the

applicant confirmed that flaws have been left in service based on ASME Code Section Xi

analysis techniques. The applicant further confirmed that the analyses associated with 'such

flaws were reviewed and considered as potential TLAAs. However, none of these flaw

analyses were determined to be TLAAs because the analyses did not satisfy Criterion (3) of 10

CFR 54.3, "Definitions, Time Limited Aging Analyses"; that is, the analyses did not involve timelimited assumptions defined by the current operating term.

The staff agrees that this is not a TLAA issue because the VIP program allows flaws to be left

in service and defines an inspection interval based on the size and amount of flaws left in

service in lieu of a 40-year analysis. For example, BWRVIP-76 defines the inspection interval

by percent cracking and does not include an analysis for 40 years. Since there is no 40-year

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evaluation on the flaw, a TLAA evaluation is not required. The staff finds the response

acceptable because the applicant has submitted the requested information. The staff accepts

the applicant's determination that the analyses of the flaws left in service are not TLAAs

because those analyses do not satisfy the definition of TLAA and are managed by an AMP in

accordance with the requirements of 10 CFR 54.21 (c)(1)(iii).

On the basis of its review, the staff finds that the AMPs credited in the LRA for the reactor

vessel internals will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.1.2.4.3 Reactor Coolant System-Recirculation System

Summary of Technical Information in the Application. The description of the reactor

recirculation system, recirculation flow control, and motor/generator (M/G) sets can be found in

Section 2.3.1.3 of this SER. The passive, long-lived components in this system that are subject

to an AMR are identified in LRA Table 2.3.1-5 and are discussed in LRA Section 3.1, "Aging

Management of Reactor Vessel, Internals, and Reactor Coolant System." The components,

aging effects, and AMPs are provided in LRA Tables 3.1-1 and 3.1-2. LRA Table 2.3.1-5 also

identifies the intended functions for the components listed and provides aging management

reference links to LRA Tables 3.1-1 and 3.1-2. In a letter, dated February 7, 2003, from P.R.

Simpson, Exelon, to NRC, D/QCNPS sent corrections to LRA Table 2.3.1-5. The corrections

included deletion of aging management reference links that do not apply to certain component

groups of the reactor recirculation system and the addition of a few aging management

reference links that were found missing for some component groups.

Aging Effects

The system consists of all recirculation piping connected to the reactor vessel, along with

associated valves, branch lines, and instrumentation. Also included are the recirculation flow

control instrumentation and the recirculation MWG sets, fluid drive couplers, and the WG set

lubrication oil piping subsystem and oil coolers and their associated electrical controls. The

system does not include the jet pumps or associated piping and instrument sensing lines that

are inside the reactor vessel.

The long-lived, passive components in the recirculation system that are subject to an AMR are

fabricated of stainless steel, CASS, low-alloy steel, carbon steel, brass, bronze, or glass (for

sight glasses). The operating environments are reactor coolant water or steam at 288 0C

(550 OF), oxygenated or demineralized water at temperatures up to 288 0C (550 OF), treated

water, lubricating oil with contaminants, ambient air and humidity at metal temperatures up to

288 0C (550 0F), wet gas, saturated air, and containment nitrogen.

The applicant reviewed the industry experience (e.g., NRC information notices, generic letters,

and bulletins) and the D/QCNPS operating experience (e.g., plant maintenance history,

modifications, nonconformance reports, and licensee event reports) and identified the following

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aging effects in Tables 3.1-1 and 3.1-2 for the reactor recirculation system components subject

to an AMR:

* cumulative fatigue damage

* crack initiation and growth due to SCC, IGSCC, and thermal and mechanical loading

* loss of material due to wear

* loss of material due to general, galvanic, pitting, and crevice corrosion

* loss of fracture toughness due to thermal aging embrittlement

In LRA Tables 2.3.1-5 and 3.1-2, the applicant also listed the following reactor recirculation

system components for which no aging effect is identified:

* external surfaces of sight glasses exposed to air, moisture, and humidity (Table 3.1-2,

Reference No. 3.1.2.5)

* external surfaces of stainless steel piping and fittings, dampeners, tubing, and valves

exposed to air, moisture, and humidity (Table 3.1-2, Reference No. 3.1.2.7)

* external surfaces of stainless steel piping and fittings, flow element pumps, tanks, tubing,

restricting orifices, thermowells, and valves exposed to containment nitrogen (Table 3.1-2,

Reference No. 3.1.2.8)

sight glasses exposed to water (Table 3.1-2, Reference No. 3.1 .2.30)

* sight glasses exposed to lubricating oil (Table 3.1-2, Reference No. 3.1.2.31)

* sight glasses exposed to wet gas (Table 3.1-2, Reference No. 3.1.2.32)

Aging Management Programs

In LRA Tables 3.1-1 and 3.1-2, the applicant identified the following seven AMPs to manage the

aging effects associated with the reactor recirculation system components:

* ASME Section Xl Inservice Inspection Program

* Water Chemistry Program

* One-Time Inspection Program

* Bolting Integrity Program

* BWR Stress Corrosion Cracking Program

* Structures Monitoring Program

* Compressed Air Monitoring Program

Staff Evaluation. The applicant described its AMR for the reactor recirculation system in

Section 3.1 of the LRA. The staff reviewed this section to determine whether the applicant

identified all the applicable aging effects for components in these systems and demonstrated

that the effects of aging on the components will be adequately managed during the period of

extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the applicable

UFSAR supplements for the AMPs to ensure that the program descriptions adequately describe

the AMPs.

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Aging Effects

The applicant identified the following aging effects for the reactor recirculation system:

* cumulative fatigue damage (discussed below and in Section 4.3 of this SER)

* crack initiation and growth due to SCC, IGSCC, and thermal and mechanical loading

* loss of material due to wear

* loss of material due to general, galvanic, pitting, and crevice corrosion

* loss of fracture toughness due to thermal aging embrittlement

The applicant identified cumulative fatigue damage as an applicable aging effect for the

recirculation system closure bolting, piping and fittings, recirculation pumps, and valves. The

staff notes that this assessment is consistent with NUREG-1801. Cumulative fatigue damage is

further evaluated in Section 4.3, "Metal Fatigue," in Chapter 4 of this SER.

The applicant identified crack initiation and growth due to SCC and IGSCC as an applicable

aging effect for the recirculation system austenitic stainless steel components (piping and

fittings, tubing, valve bodies, flow elements, thermowells, restricting orifices, and dampeners)

and for the high-strength, low-alloy steel primary pressure closure bolting exposed to reactor

coolant water. The applicant also identified this aging effect for cast stainless steel components

exposed to reactor coolant water. The applicant identified crack initiation and growth due to

thermal and mechanical loading as an applicable aging effect for small-bore stainless steel

piping and fittings and low-alloy steel pressure boundary closure bolting in the reactor

recirculation system. The staff notes that this assessment is consistent with NUREG-1801.

In LRA Section 3.1.1.1.5, the applicant stated that an inspection of small-bore reactor coolant

piping is to be conducted in accordance with its One-Time Inspection Program to verify that

service-induced weld cracking is not occurring in the small-bore piping less than 4 inches,

including pipe, fittings, and branch connections. The applicant's One-Time Inspection Program

is described in LRA Section B.1.23, and the applicant stated that it is consistent with NUREG1801, Chapter XI.M32, "One-Time Inspection."

In Section 3.1.1.1.5 of the LRA, the applicant further stated that thermal stratification, thermal

cycling and thermal stripping, thermal transients, and flow-accelerated corrosion are potential

aging mechanisms for small-bore piping. The LRA also stated that a review of the Dresden and

Quad Cities RI-ISI evaluations on degradation mechanism assessment demonstrated that only

Dresden had a high failure potential on a small-bore pipe due to thermal fatigue. Therefore,

one-time inspection will consist of an ultrasonic exam on one of the 2-inch drain lines off the

Dresden main steam header. These lines are Class 1 and within the scope of license renewal.

The staff issued RAI 3.1-9(a) requesting the applicant to identify all Class 1 small-bore piping,

describe a sampling plan based on RI-ISI evaluations, and specify AMPs for managing cracking

in this piping due to SCC. This RAI and the staff's evaluation of the applicant's response are

presented in Section 3.1.2.2.4 of this SER. The staff found the applicant's response acceptable

because the applicant had identified all Class 1 small-bore piping, presented an adequate

sampling plan for inspection sites, and provided appropriate AMPs to manage cracking due to

SCC.

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The applicant identified loss of material due to wear as an aging effect for the reactor

recirculation system high-strength, low-alloy steel bolting exposed to air with metal

temperatures up to 288 0C (550 'F) and low-alloy steel bolting exposed to containment nitrogen.

The staff notes that this assessment is consistent with NUREG-1 801.

In LRA Table 3.1-2, the applicant identified loss of material due to various forms of corrosion as

an aging effect for several reactor recirculation system components. The AMR results for these

components are not presented in NUREG-1801, Chapter IV.C1, "Reactor Coolant Pressure

Boundary (BWR)." However, AMR results for components with similar materials and

environments can be found in other chapters of NUREG-1801 and are used here to evaluate

the AMR results presented in LRA Table 3.1-2.

The applicant identified loss of material due to general corrosion as an applicable aging effect

for the recirculation system carbon steel components exposed to moist air and humidity. The

staff finds that this identification is consistent with Item E.2-a, Chapter V.E, of NUREG-1 801.

The applicant identified loss of material due to general, crevice, pitting, and galvanic'corrosion

as an applicable aging effect for the recirculation system carbon steel components (piping,

fittings, valves, filters/strainers, and restricting orifices) exposed to lubricating oil with

contaminants and/or moisture. The staff finds that this identification is consistent with Item G.7-

a, Chapter VII.G, of NUREG-1801.

The applicant identified loss of material due to general (carbon steel only),'pitting, and crevice

corrosion as an applicable aging effect for carbon steel exposed to treated water. The staff

finds that this identification is consistent with Item C2.3-a, Chapter VII.C2, of NUREG-1801.

In LRA Table 3.1-2, the applicant identified loss of material due to general, pitting, and crevice

corrosion as an applicable aging effect for stainless steel valves and carbon steel piping, '

fittings, and valves exposed to wet gas. In RAI 3.1-12, the staff requested that the applicant

submit a description of the wet gas environment so that the staff can evaluate this aging effect.

In response to RAI 3.1-12, in a letter dated October 3, 2003, the applicant stated that the wet

gas environment is an air environment that contains moisture. The applicant referenced EPRI

1003056, "Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Revision

3," in identifying the role of moisture in promoting various forms of corrosive attack, including

loss of material due to general, pitting, and crevice corrosion. The staff finds the applicant's

response acceptable because it provides a description of the wet gas environment. The staff

also verified that the reference cited by the applicant identifies the role of moisture in promoting

loss of material due to general, pitting, and crevice corrosion.

The applicant identified loss of material due to pitting and crevice corrosion as an applicable

aging effect for carbon steel valves and stainless steel tanks, tubing, restricting orifices, and

piping and fittings exposed to reactor coolant water or oxygenated water with temperatures up

to 288 0C (550'F). The staff finds this identification of loss of material as an applicable aging

effect, acceptable because pitting and crevice corrosion of carbon steel and stainless steel is

possible due to a small amount of chloride generally present in the BWR water and saturated

air environments.

The applicant identified loss of material due to corrosion as an applicable aging effect for

stainless steel, bronze, and brass components exposed to air, moisture, humidity, and leaking

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fluid. The staff finds this identification of loss of material as an applicable aging effect,

acceptable because trace levels of corrosive species (e.g., chlorides) are generally present in

moist environments and leaking fluid.

The applicant identified the loss of fracture toughness due to thermal aging embrittlement as an

applicable aging effect for CASS pump casings and valve bodies. The staff notes that this

assessment is consistent with NUREG-1801. In LRA Table 3.1.1.10, Reference No. 3.1.1.10,

the applicant stated that CASS piping does not exist at Dresden or Quad Cities and, therefore,

the piping does not experience loss of fracture toughness due to thermal aging. However,

fittings (e.g., elbows and tees) in the austenitic stainless steel piping in the BWR recirculation

system are typically made of CASS. In NRC Aging Management Inspection Information

Request AMI-1 1, the staff requested the applicant to identify the material for the fittings in the

recirculation piping, and if it is CASS, to provide an AMP for managing loss of fracture

toughness in those fittings. In response to AMI-1 1, the applicant stated that as identified on the

Reactor Recirculation Piping Design Table (PDT) A of License Renewal Boundary Diagrams

LR-DRE-M-26-2 and LR-QDC-M35-2, the fittings in recirculation piping are made of wrought

and forged austenitic stainless steel, rather than of CASS. The staff finds the applicant's

response acceptable because its review of Piping Design Table A confirmed that none of the

fittings in Dresden and Quad Cities recirculation piping are made of CASS.

The applicant did not identify loss of preload as an aging effect for recirculation pump closure

bolting and valve closure bolting in the reactor recirculation system. In LRA Section 3.1.1.2.2,

the applicant referred to EPRI 1003056, Revision 3, which states that loss of preload

mechanisms is typically addressed during installation and subsequent maintenance of closure

bolting. In RAI 3.1-13, the staff requested the applicant to explain why periodic inspection of

the closure bolting for indication of loss of preload due to the aforementioned mechanisms is

not required. The staff further requested the applicant, if periodic inspection is required, to

reference the appropriate AMP and include the appropriate inspection in the AMP. The

response to RAI 3.1-13 is evaluated in Section 3.1.2.4.1 of this SER. The staff found the

response not completely acceptable for the following reason. LRA Section 3.1.1.2.1 does not

address loss of preload as an aging effect, and states that loss of preload mechanisms are

typically addressed during installation and subsequent maintenance of closure bolting.

However, the applicant's response to RAI 3.1-13 states that loss of preload will be managed

and that the enhanced Bolting Integrity Program will be comprised of periodic ISIs and piping

and components preventative maintenance inspections. In Supplemental RAI 3.1-13, the staff

requested the applicant to describe the maintenance program activities that are performed on

the bolts so that loss of preload is significantly reduced or eliminated, and identify whether

retorquing of the bolts to the design preload values is performed after the component is

reassembled. The applicant's response to Supplemental RAI 3.1-13 is evaluated in Section

3.1.2.4.1 of this SER. The staff has found the response acceptable.

The applicant identified no applicable aging effect for sight glasses exposed to air, moisture,

and humidity; water; lubricating oil; and wet gas. This is acceptable because sight glass is

resistant to loss of material, and the environments to which it is exposed are not aggressive.

The applicant identified no applicable aging effect for the external surfaces of stainless steel

components exposed to containment nitrogen or air, moisture, and humidity. The staff finds

this identification of no applicable aging effect acceptable because stainless steel is resistant to

loss of material and cracking at low temperatures when the environments it is exposed to are

not aggressive.

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* g w

The aging effects identified in the LRA for the reactor recirculation system are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant credited the following programs for managing aging in the reactor recirculation

system. These programs' all of which are common AMPs, are reviewed in the different

sections of this SER, as indicated in parentheses:

* ASME Section Xl Inservice Inspection Program (Section 3.0.3.1)

* Water Chemistry Program (Section 3.0.3.2)

* One-Time Inspection Program (Section 3.0.3.10)

* Bolting Integrity Program (Section 3.0.3.5)

* BWR Stress Corrosion Cracking Program (Section 3.0.3.3)

* Structures Monitoring Program (Section 3.0.3.14)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* Periodic Inspection of Components Subject to Moist Environments (3.0.3.18)

As part of RAI B.1.23.2-6, the staff questioned the use of the one-time inspections to manage

aging for components in a moist air environment. In its response dated March 25, 2004, the

applicant credited the Periodic Inspection of Components Subject to Moist Environments

program to manage aging effects for stainless steel, carbon steel, cast iron, aluminum, copper,

and brass and bronze components exposed to moist air environments and subject to wetting.

The staff's evaluation of the Periodic Inspection of Components Subject to Moist Environments

AMP is contained in SER section 3.0.3.18.

The applicant credited LRA Appendix B.1.1, ASME Section Xl Inservice Inspection,

Subsections IWB, IWC, and IWD, for managing loss of fracture toughness due to thermal aging

embrittlement in reactor recirculation and reactor water cleanup valve bodies and reactor

recirculation pump casings made of CASS. The Inservice Inspection Program-includes visual

inspection for detecting surface-breaking cracks in the CASS valve bodies and pump casings.

Inspection for cracking is acceptable for managing loss of fracture toughness in CASS valve

and pump bodies because loss of fracture toughness in CASS components becomes a concern

only if cracks are present. In RAI 3.1-14, the staff requested the applicant to explain how the

proposed visual inspection technique is qualified for detecting IGSCC cracks in the CASS valve

bodies and pump casings and to confirm whether Code Case N-481, "Alternative Examination

Requirements for Cast Austenitic Pump Casings," has been used to supplement the ISI

requirements of ASME Code Section Xl for these pump casings. The staff further requested

the applicant to confirm whether a flaw evaluation was performed for this aging effect while

implementing this code case, and if not, to present evaluation of this as a TLAA in accordance

with 10 CFR 54.3.

In response to RAI 3.1-14, in a letter dated October 3, 2003, the applicant stated that NUREG1801 was relied on as an approved topical report in the preparation of the LRA. As such, the

recommendations from NUREG-1801, Items IV.C1.2-c and IV.C1.3-b, were considered. These

NUREG-1801 items state, "For pump casings (and valve bodies), screening for susceptibility to

thermal aging is not required. The ASME Section Xl inspection requirements are sufficient for

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managing the effects of loss of fracture toughness due to thermal aging embrittlement of CASS

valve bodies." Therefore, no additional inspections are required. The applicant further stated

that Code Case N-481, "Alternative Examination Requirements for Cast Austenitic Pump

Casings." does not supplement the Dresden or Quad Cities ISI requirements. The staff finds

the applicant's response acceptable because it is consistent with the NUREG-1801 position that

the Section Xl inspection requirements are sufficient for managing the effects of loss of fracture

toughness due to thermal aging embrittlement of CASS.

The applicant credited LRA Appendix B. 1.7, "BWR Stress Corrosion Cracking Program," for

managing crack initiation and growth due to SCC in austenitic stainless steel recirculation

system piping and related reactor coolant pressure boundary components. The applicant

stated that the BWR Stress Corrosion Cracking Program is based on BWRVIP-75, "Technical

Basis for Revisions to Generic Letter 88-01 Inspection Schedules." In Inspection Question

3.1.2.4.3-6, the staff requested the NRC Inspection Team to verify that the resolutions to the

open items of NRC letter to Terry (BWRVIP), dated May 14, 2002, have been implemented in

the program. Inspection Reports 05000237/2003010 (DRS); 05000249/2003010 (DRS);

05000254/2003014 (DRS);and 05000265/2003014 (DRS), dated December 5, 2003, stated that

the ISI Program at Dresden and Quad Cities have incorporated BWRVIP-75, "Technical Basis

for Revisions to Generic Letter 88-01 Inspection Schedules," including the resolutions to the

open items of NRC letter to the industry BWRVIP group, dated May 14, 2002.

In RAI B.1.7-a, the staff requested the applicant to submit information about its plant-specific

experience related to IGSCC cracking of the reactor vessel safe ends and reactor coolant

pressure boundary piping, mitigative actions taken, and the revised inspection schedules

following the BWRVIP-75 guidelines. The staff also requested the applicant to submit

information about whether HWC and NMCA are implemented at D/QCNPS and how this

implementation has affected monitoring of water chemistry parameters. In RAI 3.1-24, the staff

requested the applicant to provide similar information for the reactor coolant pressure boundary

systems other than reactor vessel safe ends and reactor recirculation piping. However, in its

response to RAI 3.1-24, the applicant addressed reactor recirculation piping, including reactor

vessel safe ends. As a result, the applicant has submitted similar responses to RAls B.1.7-a

and RAI 3.1-24 in a letter dated October 3, 2003. Therefore, since the response to RAI 3.1-24

submitted in a letter dated October 3, 2003, provides all of the necessary information for the

applicable systems/components, the staff evaluated this response which is presented in four

parts as discussed below.

In RAI 3.1-24a, the staff requested that the applicant submit information about its plant-specific

experience related to IGSCC cracking of the stainless steel components in the following reactor

coolant pressure boundary systems-HPCI, core spray, RCIC, RHR, LPCI, SBLC, SDC,

RWCU, MS, and FW systems and the isolation condenser. In response to RAI 3.1-24a, in a

letter dated October 3, 2003, the applicant stated that it had reviewed the Dresden and Quad

Cities operating experience related to IGSCC of stainless steel components in the systems

specified, as well as in the reactor recirculation system. Reactor coolant pressure boundary

piping was identified to have flaw indications, such as indications on the reactor vessel safe

ends, and IGSCC on recirculation piping. However, there were no flaw indications (IGSCC)

identified that affected the component intended function for any components in the abovementioned systems. The applicant then listed representative examples of IGSCC operating

experience related to reactor coolant pressure boundary piping. These examples were

intended to demonstrate the effectiveness of the applicant's AMP. The applicant further noted

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that the evaluation of the effectiveness of IHSI treatment for susceptible welds resulted in an

adjustment of the inspection plan to change all Quad Cities Unit 1 28-in. IHSI treated Category

C (non-resistant material, stress improvement after 2 years of unit operation) welds to Category

D (non-resistant material, no stress improvermient). The staff finds the applicant's response

acceptable because the operating experience demonstrates that AMP B.1.7 has been

successful in identifying aging effects. The program has been successful in identifying cracking

so that the intended function of the components will be maintained consistent with the CLB

through the extended operation, as required by 10 CFR 54.21 (a)(3).

In RAI 3.1-24b, the staff requested that the applicant submit information about mitigation

actions taken at D/QCNPS with respect to selection of materials that are resistant to

sensitization, use of special processes that reduce residual tensile stress, and monitoring of

water chemistry as specified by NUREG-1801, Chapter XL.M7. In response to RAI 3.1-24b, in a

letter dated October 3, 2003, the applicant listed mitigation actions taken with respect to

material selection, use of special process, and monitoring of water chemistry. These included

the replacement of stainless steel piping with more resistant grades, the use of IHSI to minimize

tensile stresses in weldments, use of noble metal chemical injection systems, and

implementation of HWC. As noted in the response to RAI 3.1-24b, the IHSI treatment of the

susceptible welds was not effective in mitigating IGSCC. The applicant also stated that no

information is yet available on the effectiveness of noble metal chemical injections on IGSCC

mitigation, but the use of HWC appears to provide a beneficial effect. The staff finds the

applicant's response to be acceptable because it provides the requested information to

evaluate whether the inspections are consistent with the ASME Code and/or BWRVIP-75 with

the applicable water chemistry, as discussed below.

In RAI 3.1-24c, the staff requested that the applicant confirm whether HWC and NMCA are

implemented at D/QCNPS. If so, the staff requested the applicant to explain how this*

implementation has affected monitoring of water chemistry parameters. In response to RAI 3.1-

24c, in a letter dated October 3, 2003, the applicant stated that both Dresden and Quad Cities

have implemented HWC and NMCA. As part of the implementation of HWC and NMCA,

monitoring of electrochemical corrosion potential (ECP) was added. ECP data and HWC index

results are used to calculate crack growth rate factors of improvement. The applicant further

stated that the BWRVIP model for BWR crack growth indicates decreasing crack growth rate

with decreasing ECP. The staff finds the applicant's response to RAI 3.1-24c acceptable

because it is consistent with the recommendations of BWRVIP-62. UBWR Vessel and Internals

Project: Technical Basis for Inspection Relief for BWR Internal Components with Hydrogen

Injection," however, the meaning of the term "HWC index" is not clear. The applicant is

requested to clarify how the UHWC index" is used to determine factor of improvement, and

confirm whether this term means the availability of HWC at a certain ECP value.

In response to Supplemental RAI 3.1-24d(iv) in a letter dated December 22, 2003, the applicant

confirmed that the term is the availability (in percent) of HWC at a certain Electrochemical

Corrosion Potential (ECP) value. The availability is calculated as the percentage of time the

feedwater hydrogen concentration is sufficient to achieve an ECP value of less than or equal to

-230mV when the water temperature exceeds 200 'F. Factors of Improvement (FOI) can be

determined using this information. However, Dresden and Quad Cities do not use the FOI

approach identified in BWRVIP-75 to determine the effectiveness of HWC. The staff finds this

response acceptable, because the applicant is following the requirements of the NRC letter

dated May 14, 2002, such as monitoring the ECP, in lieu of using the FOI.

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In RAI 3.1-24d, the staff requested that the applicant submit information on the inspection

frequency (based on whether HWS and/or NMCA are used) and the corresponding number of

welds to be inspected following the BWRVIP-75 guidelines. The applicant submitted its

response to RAI 3.1-24d in a letter dated October 3, 2003. In its response, the applicant stated

that at Quad Cities, Category C through E welds (Quad Cities currently has no Category B

welds) are still being inspected at the frequency specified in BWRVIP-75, "BWR Vessel and

Internal Project Technical Basis for Revisions of Generic Letter 88-01 Inspection Schedules,"

guidelines for normal water chemistry. However, the NRC SER of EPRI Report TR-1 13932

(BWRVIP-75) dated May 14, 2002, expanded on the guidelines and inspection frequencies for

Category C welds to include plants that comply with BWRVIP-61, as well as those plants that

do not comply with BWRVIP-61. Therefore, the staff requested the applicant to confirm

whether or not the D/QCNPS plants are complying with BWRVIP-61 and that the appropriate

inspection frequencies based on the NRC SER are used. The staff also requested the

applicant to identify the number of welds in each category of weld that are credited for the use

of IHSI, HWC, NMCA, or a combination of these methods, and corresponding inspection

frequency. The staff further requested the applicant to provide the number of Category C

through E welds and the frequency of their inspections for Quad Cities 1 and 2. In response to

Supplemental RAI 3.1-24d(i) in a letter dated December 22, 2003, the applicant confirmed that

D/QCNPS do not use IHSI, and therefore BWRVIP-61, "BWR Vessel and Internals Induction

Heating Stress Improvement (IHSI) Effectiveness on Crack Growth in Operating Plants" does

not apply to D/QCNPS. However, D/QCNPS does meet the conditions of BWRVIP-75 that

permit reductions in the frequencies for inspection of Category C welds (non-resistant material

with stress improvement after 2 years of operation). The NRC SER of EPRI Report TR-1 13932

(BWRVIP-75) dated May 14, 2002, imposed restrictions on reduction in inspection frequencies

for plants with Category C welds that had been treated with IHSI, but did not fully comply with

BWRVIP-61. However, the category C welds at Dresden and Quad Cities were stress

improved by the Mechanical Stress Improvement method (MSIP). This process was accepted

by the SER on BWRVIP-75 without restrictions. Dresden and Quad Cities are in compliance

with the requirements of BWRVIP-75, and therefore apply the reduced inspection frequencies

for the Category C welds. The applicant also provided the number of welds in each category of

weld that are credited for the use of MSIP, HWC, NMCA or a combination of these methods,

and corresponding inspection frequency as requested. The staff confirmed that the inspection

frequencies for both Dresden and Quad Cities are in compliance with the requirements of

BWRVIP-75 and therefore finds the applicant's response acceptable.

In further response to RAI 3.1-24d, the applicant stated that HWC/NMCA inspection

frequencies for Categories C through E welds were reduced for Dresden Unit 2 and only

applied to those weld locations where the improved water chemistry is effective. The staff

requested the applicant to explain how these locations were identified. The staff further

requested the applicant to explain the two different categories for C, D, and E that are identified

in the response, and why two different inspection frequencies are listed in the response for

each Category C, D, and E welds at Dresden Unit 2. In addition, the staff asked the applicant

to confirm whether the information provided meets the requirements of BWRVIP-75, as

approved by the NRC SER of EPRI Report TR-1 13932 (BWRVIP-75), dated May 14, 2002 (i.e.,

the RAI response states that Category D-HWC welds with a population of 24 received 10

percent inspection every 6 years, whereas BWRVIP-75 requires 100 percent inspection every

10 years for HWC). In response to Supplemental RAI 3.1-24d(ii) in a letter dated December 22,

2003, the applicant stated that there were a number of typographical errors in the Dresden, Unit

2 weld information provided in the original response to RAI 3.1.24-d. These errors resulted in a

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perception that different frequencies were provided for each weld category and/or that

inappropriate frequencies were used. The applicant provided revised information, which are in

compliance with the requirements of BWRVIP-75, as approved by NRC SER of EPRI Report

TR-113932 (BWRVIP-75), dated May 14, 2002. The locations for which Dresden, Unit 2

Category C through E weld inspection frequencies were reduced are those areas in the reactor

coolant flowpath. These portions of piping are continually exposed to circulating reactor coolant

and receive the benefits of IGSCC mitigation due to HWC/NMCA. The staff finds the

applicant's response acceptable because the inspection frequencies for Category C through E

welds meet the requirements of BWRVIP-75, and that reduced weld inspection for Dresden,

Unit 2 is consistent with BWRVIP-75 for the locations in the reactor coolant flowpath, that are

continually exposed to circulating reactor coolant with HWC/NMCA.

In response to RAI 3.1-24d, the applicant further stated that Category A welds at D/QCNPS are

inspected per the RI-ISI guidelines. The staff requested the applicant to confirm that Category

A welds at D/QCNPS are inspected to BWRVIP-75 as modified and approved by the NRC SER

of EPRI Report TR-1 13932 (BWRVIP-75) dated May 14, 2002. In response to Supplemental

RAI 3.1-24d(iii) in a letter dated December 22, 2003, the applicant stated that IGSCC Category

A welds are subsumed under the EPRI Risk-Informed Inservice Inspection (RI-ISI) program.

This is consistent with the methodology of EPRI Report TR-1 12657, Revision B-A, RiskInformed Inservice Inspection Evaluation Procedure. The staff finds the applicant's response

acceptable because it is consistent with the methodology of EPRI Report TR-1 12657, Revision

B-A, as approved by NRC SERs for RI-ISI dated September 5, 2001, and February 5, 2002 for

Dresden and Quad Cities, respectively.

The applicant credited LRA Appendix B.1.23, "One-Time Inspection," for managing loss of

material due to corrosion in recirculation system carbon steel and stainless steel components.

The applicant stated that the One-time Inspection Program is consistent with Chapter XL.M32,

"One-Time Inspection," specified in NUREG-1801. The staff finds the use of the One-Time

Inspection Program appropriate for managing loss of material in these components because it

will identify any loss of material at the inner surface of the component inspected.

However, the applicant credited only LRA Appendix B.1.2, "Water Chemistry," for managing

cracking in recirculation system stainless steel components. The AMR for these components is

presented in Table 3.1-2, Reference Nos. 3.1.2.23, 3.1.2.24, 3.1.2.26, 3.1.2.29, 3.1.2.40,

3.1.2.49, and 3.1.2.52. In RAI 3.1-15, the staff requested the applicant to explain why it credits

the One-Time Inspection Program for managing loss of material, but not cracking. In response

to RAI 3.1-15, in a letter dated October 3, 2003, the applicant stated that these piping

components do not require a one-time inspection because they are small-bore (2" and under),

socket welded components, downstream of the excess flow check valves and located outside

primary containment. The normal operating temperature is less than 600C (140 OF), the

minimum temperature needed to initiate IGSCC. Therefore, the aging management references

should have reported an environment of "Reactor.Coolant Water (less than 60 0C or 140 OF);"

Aging Effect/Mechanism as "None," and the AMP as uNone."

The applicant also noted that this environment is neither part of the original LRA, nor is it

contained in the response provided to RAI 3.0-1 submitted to the NRC on June 11, 2003. This

piping was originally considered to be in the 288 °C (550 °F) reactor water coolant environment,

similar to the piping to which it is attached. However, the actual normal operating environment

is less than 60 °C (140 OF). The applicant additionally noted that LRA Table 2.3.1-5,

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"Components Requiring Aging Management Review -Reactor Recirculation System,"

component group,"NSR Vents and Drains, Piping and Valves (attached support)," should not

have indicated Dresden only. The staff finds the applicant's response to be acceptable

because SCC is not anticipated in stainless steel components operating at temperatures below

60 0C (140 0

F).

All of the AMPs listed above are credited for managing the aging effects of several components

in various different structures and systems and are, therefore, considered common AMPs. The

staff has evaluated these common AMPs and found them to be acceptable for managing the

aging effects identified for this system. The staff's evaluation of these AMPs is documented in

Section 3.0 of this SER. On the basis of its review, the staff finds that the AMPs credited in the

LRA for the reactor recirculation system components will effectively manage or monitor the

aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR 54.2(a)(3).

3.1.2.4.4 Reactor Vessel Head Vent System

Summary of Technical Information in the Application. The description of the reactor vessel

head vent system can be found in Section 2.3.1 of this SER. The passive, long-lived

components in this system that are subject to an AMR are discussed in LRA Section 3.1, "Aging

Management of Reactor Vessel, Internals, and Reactor Coolant System," and are identified in

LRA Table 2.3.1-6. The components, aging effects, and AMPs are provided in LRA Tables 3.1-

1 and 3.1-2. In a letter, dated February 7, 2003, from P R. Simpson, Exelon, to NRC,

D/QCNPS sent a correction to LRA Table 2.3.1-6. The correction included a deletion of an

aging management reference link that does not apply to certain component groups of the

reactor vessel head vent system.

Aging Effects

The applicant reviewed the industry experience (e.g., NRC information notices, generic letters,

and bulletins) and the Dresden and Quad Cities operating experience (e.g., plant maintenance

history, modifications, nonconformance reports, and licensee event reports) and identified the

components, aging effects, and AMPs in LRA Tables 3.1-1 and 3.1-2.

The long-lived, passive components in the reactor vessel head vent system that are subject to

an AMR are fabricated of stainless steel (tubing and valve components), CASS (valve bodies),

low-alloy steel (closure bolting), carbon steel (vents, drains, and piping), brass or bronze

(vents/drains), and glass (sight glasses). The operating environments are reactor coolant water

or steam at 288 0C (550 CF), ambient air and humidity at metal temperatures up to 288 0C

(550 'F), wet gas, saturated air, and containment nitrogen.

In Tables 3.1-1 and 3.1-2, the applicant identified the following aging effects for the reactor

vessel head vent system components subject to an AMR:

* cumulative fatigue damage

* crack initiation and growth due to SCC, IGSCC, and thermal and mechanical loading

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* crack initiation and growth due to cyclic loading

* loss of material due to wear

* loss of material due to general, galvanic, pitting, and crevice corrosion

* wall thinning due to flow-accelerated corrosion

In LRA Tables 2.3.1-6 and 3.1-2, the applicant also listed the following reactor vessel head vent

system components for which no aging effect is identified:

* external surfaces of carbon steel piping, fittings, and valves exposed to containment

nitrogen (Table 3.1-2, Reference No. 3.1.2.4)

* external surfaces of stainless steel tubing and valves exposed to containment nitrogen

(Table 3.1-2, Reference No. 3.1.2.8)

* sight glasses exposed to wet gas (Table 3.1-2, Reference No. 3.1.2.32)

Aging Management Programs

In LRA Tables 3.1-1 and 3.1-2, the applicant identified the following eight AMPs to manage the

aging effects associated with the reactor vessel head vent system components:

* ASME Section Xl Inservice Inspection Program'

* Water Chemistry Program

* One-Time Inspection Program

* Bolting Integrity Program

* BWR Stress Corrosion Cracking Program

* Flow-Accelerated Corrosion Program

* Compressed Air Monitoring Program

Staff Evaluation. The-applicant described its AMR for the reactor vessel head vent system in

Section 3.1 of the LRA. The staff reviewed this section to determine whether the applicant

identified all the applicable aging effects for components in these systems and demonstrated

that the effects of aging on the components will be adequately managed during the period of

extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the applicable

UFSAR Supplements for the AMPs to ensure that the program descriptions adequately

describe the AMPs.

Aging Effects

The aging effects identified by the applicant for the reactor vessel head vent system are as

follows:

* cumulative fatigue damage (discussed below and in Section 4.3 of this SER)

* crack initiation and growth due to SCC, IGSCC, and thermal and mechanical loading

* crack initiation and growth due to cyclic loading

* loss of material due to wear

* loss of material due to general, galvanic, pitting, and crevice corrosion

* wall thinning due to flow-accelerated corrosion

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The applicant identified cumulative fatigue damage as an applicable aging effect only for the

reactor head vent system valves. The staff notes that this assessment is consistent with

NUREG-1801, Item C1.3-d, Chapter IV.C1) However, in RAI 3.1-16, the staff requested the

applicant to explain why cumulative fatigue damage was not identified as an applicable aging

effect for the piping and fittings of the reactor vessel head vents. Cumulative fatigue damage is

further discussed in Section 4.3 of this SER. In response to RAI 3.1-16 ,in a letter dated

October 3, 2003, the applicant stated that cumulative fatigue damage is an applicable aging

effect for the reactor head vent piping and fittings. The applicant stated that LRA Table 2.3.1-6

should have included Aging Management Reference 3.1.1.1 for the component group, "Piping

and Fittings." The staff finds the applicant's response to be acceptable because it is consistent

with the GALL position on the applicability of cumulative fatigue damage as an aging effect for

the reactor pressure boundary piping and fittings, including those associated with the reactor

vessel head vents.

According to the Aging Management Review Aid for the reactor vessel head vent system (Table

2.3.1-6), the applicant identified crack initiation and growth due to SCC and IGSCC as an

applicable aging effect for the reactor head vent system austenitic stainless steel valve bodies

exposed to reactor coolant water. However, the staff notes that the applicant does not identify

crack initiation and growth as an applicable aging effect for the reactor head vent system CASS

valve bodies exposed to reactor coolant water. In RAI 3.1-17, the staff requested the applicant

to explain why cracking is not an applicable aging effect for CASS valve bodies in the reactor

vessel head vent system. In response to RAI 3.1-17, in a letter dated October 3, 2003, the

applicant states that neither Dresden nor Quad Cities have CASS valves installed in the reactor

vessel head vent system. The applicant further stated that the material for the line in Table

2.3.1-6 of the Aging Management Review Aid that shows valves with material of "Carbon Steel,

Cast Austenitic Stainless Steel, Stainless Steel" should have read 'Carbon Steel, Stainless

Steel." Cast austenitic stainless steel should have been removed from the list of materials.

The staff finds the applicant's response to be acceptable because the embrittlement aging

effect is applicable only to CASS components.

The applicant does not identify the loss of fracture toughness due to thermal aging

embrittlement as an applicable aging effect for CASS valve bodies in the reactor vessel head

vent system. In RAI 3.1-19. the staff requested that the applicant explain why loss of fracture

toughness due to thermal aging embrittlement is not an applicable aging effect for the CASS

valve bodies. If loss of fracture toughness is identified as an applicable aging effect, then the

applicant needs to provide a program for managing that effect. In response to RAI 3.1-19, in a

letter dated October 3, 2003, the applicant stated that as explained in the response to RAI 3.1-

17, Dresden and Quad Cities do not have CASS valves installed in the reactor vessel head vent

system. The staff finds the applicant's response to be acceptable because the embrittlement

aging effect of concern here is applicable only to CASS components.

The applicant identified crack initiation and.growth due to thermal and mechanical loading as an

applicable aging effect for small-bore carbon steel piping and fittings. These AMR results are

evaluated in Section 3.1.2.2.4 of this SER and are consistent with NUREG-1801.

The applicant identified crack initiation and growth due to cyclic loading as an applicable aging

effect for the low-alloy steel reactor vessel head vent system pressure boundary low-alloy steel

closure bolting exposed to containment nitrogen. This AMR result is consistent with Item 1.2-b,

Chapter VII.1, in NUREG-1801.

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The applicant identified loss of material due to wear as an aging effect for the reactor vessel

head vent system low-alloy'and high-strength, low-alloy steel closure bolting exposed to an air

or containment nitrogen environment with metal temperatures up to 288 'C (550 'F). The staff

notes that this assessment is consistent with NUREG-1 801.

In LRA Table 3.1-2, the applicant identified loss of material due to various forms of corrosion as

an aging effect for the reactor vessel head vent system stainless steel tubing exposed to

saturated air; for carbon steel, stainless steel, brass or bronze vents/drains, piping, and valves

exposed to moist air and leaking fluid; and for stainless steel valve components exposed to

saturated air. The AMR results for these components are not presented in NUREG-1 801,

Chapter IV.C1, "Reactor Coolant Pressure Boundary (BWR)." However, AMR results for

components with similar materials and environments can be found in other chapters of NUREG1801 and are used here to evaluate the AMR results presented in LRA Table 3.1-2. '

The applicant identified loss of material due to general corrosion as an aging effect for carbon

steel, stainless steel, brass or bronze vents or drains, piping, and valves exposed to air,

moisture, humidity, and leaking fluid. The staff finds that the identification of the carbon steel

components is consistent with Item E.2-a, Chapter V.E, of NUREG-1801. For the stainless

steel, brass, or bronze components, the staff agrees that these components are subject to this

aging effect in these environments, since trace levels of corrosive species are generally present

in moist environments.

The applicant identified loss of material due to pitting and crevice corrosion as an applicable

aging effect for stainless steel tubing and valve components exposed to a saturated air

environment. The staff agrees that these components are subject to this aging effect in this

environment, since trace levels of corrosive species (e.g., chlorides) commonly present on the

component surfaces can interact with moisture and condensation from saturated air. The aging

management results for managing flow-accelerated corrosion of the carbon steel components

in the reactor vessel head vent system are provided in LRA Table 3.1-1, Aging Management'

Reference 3.1.1.11, which refers to LRA Section 3.1.1.2.2 for exceptions to flow-accelerated

corrosion.

The applicant identified wall thinning due to flow-accelerated corrosion as an applicable aging

effect for carbon steel piping and fittings in the reactor vessel head vent system exposed to

flowing reactor coolant water at temperatures up to 225 CC (437 0F). However, in LRA Section

3.1.1.2.2, the applicant stated that the carbon steel components in the reactor vessel head vent

system are not susceptible to flow-accelerated corrosion and do not require 'aging management

for this effect. This determination is based on the fact that these components operate'less than

2 percent of the plant operating time or at flow rates less than 1.8 m/s (6 ft/s). The applicant

referenced the EPRI reports NSAC-202L-R2 and TR-1 14882 as the bases for these criteria.

However, Chapter Xl.M17, "Flow-Accelerated Corrosion," of NUREG-1801 only relies on EPRI

report NSAC-202L-R2 for an effective flow-accelerated corrosion program. In RAI 3.1-18, the

staff asked the applicant whether EPRI report NSAC-202L-R2 states that carbon steel

components are not susceptible to flow-accelerated corrosion, and do rot require aging

management when these components are operated at flow rates less than 1.8mts (6ftWs). If

not, the applicant needs to specify the applicable AMP, as required by NUREG-1801.

In response to RAI 3.1-18, in a letter dated October 3, 2003, the applicant stated that it has

reevaluated the use of EPRI TR-1 14882 and NSAC-202L-R2 and has decided not to take an

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exception to NUREG-1801 for aging management of the reactor vessel head vent system. As

a result, the applicant stated that the reactor vessel head vent system will be included in the

Dresden and Quad Cities Flow Accelerated Corrosion Program, and LRA Section 3.1.1.2.2

should not have included the reactor vessel head vent system in the exception described in

Section 3.1.1.2.2 of the LRA.

The applicant stated that LRA Section 3.1.1.2.2 should have read as follows:

Flow-accelerated corrosion is an applicable aging mechanism for the main steam lines, feedwater

lines, reactor vessel head vent lines, and reactor vessel bottom head drain lines (evaluated with

the nuclear boiler instrumentation system). However, carbon steel components in the core spray, shutdown cooling (Dresden only), HPCI, RCIC (Quad Cities only), and nuclear boiler

instrumentation (except for the reactor vessel bottom head drain lines) are not susceptible to flowaccelerated corrosion and do not require aging management. This exception is based on the

following:

* EPRI NSAC-202L-R2, 'Recommendations for an Effective Flow-Accelerated Corrosion

Program," allows an exclusion from flow-accelerated corrosion for systems with no flow or

those that operate less than 2 percent of plant operating time.

* NUREG-1557, "Summary of Technical Information and Agreements from Nuclear

Management and Resources Council Industry Reports Addressing License Renewal.", states

that erosion/corrosion in HPCI and RCIC turbine steam supply piping is nonsignificant due to

the low flow range.

* Dresden and Quad Cities operate these systems less than 2 percent of plant operating time.

Additionally, plant experience has not revealed flow-accelerated corrosion in these lines.

The staff finds the applicant's response to be acceptable because the applicant's AMP for

managing wall thinning due to flow-accelerated corrosion for carbon steel piping and fittings in

the reactor vessel head vent system exposed to flowing reactor coolant water at temperatures

up to 225 'C (437 'F) is now consistent with GALL.

The applicant does not identify loss of preload as an aging effect for high-strength, low-alloy

steel closure bolting in reactor vessel head vent system. In LRA Section 3.1.1.2.2, the

applicant refers to EPRI 1003056, Revision 3, which states that loss of preload mechanisms are

typically addressed during installation and subsequent maintenance of closure bolting. In RAI

3.1-13, the staff requested the applicant to explain why periodic inspection of the closure bolting

for indication of loss of preload due to the aforementioned mechanisms is not required. The

staff further requested the applicant, if periodic inspection is required, to reference the

appropriate AMP and include the appropriate inspection in the AMP. The response to RAI 3.1-

13 is evaluated in Section 3.1.2.4.1 of this SER.

The staff finds the response not completely acceptable for the following reason. LRA Section

3.1.1.2.1 does not address loss of preload as an aging effect, and states that loss of preload

mechanisms are typically addressed during installation and subsequent maintenance of closure

bolting. However, the applicant's response to RAI 3.1-13 stated that loss of preload will be

managed, and that the enhanced Bolting Integrity Program will be comprised of periodic ISIs

and piping and components preventative maintenance inspections. In Supplemental RAI 3.1-

13, the staff requested the applicant to describe the maintenance program activities that are

performed on the bolts so that loss of preload is significantly reduced or eliminated, and to

identify whether retorquing of the bolts to the design preload values is performed after the

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component is reassembled. The applicant's response to Supplemental RAI 3.1-13 is evaluated

in Section 3.1.2.4.1 of this SER. The staff has found the response acceptable.

The applicant identified no applicable aging effect for external surfaces of carbon steel piping,

fittings, and valves exposed to a containment nitrogen environment. This identification of no

aging effect is not acceptable because the environment in BWR containment is likely to have

high humidity, which can cause corrosion of the external surface of carbon steel components.

In RAI 3.1-5, the staff requested the applicant to explain why loss of material is not identified as

an aging effect for these components, or provide a program for managing that aging effect.

The staff evaluates the response to this RAI in Section 3.1.2.4.1.2 of this SER and finds it

acceptable. The staff agrees with the applicant that there are no applicable aging effects for

external surfaces of carbon components exposed to a containment nitrogen environment

because the low oxygen level present in the primary containment atmosphere precludes loss of

material due to corrosion as a credible aging effect for the external surface of carbon steel

components exposed to containment environment.

The applicant identified no applicable aging effect for external surfaces of stainless steel tubing

and valves exposed to containment nitrogen and sight glasses exposed to wet gas. This

identification of no aging effect is acceptable because these environments are not aggressive.

The aging effects identified in the LRA for the reactor vessel head vent system are consistent

with industry operating experience for the materials and environments listed. The staff finds

that all the plausible aging effects were identified and that the aging effects listed are

appropriate for the combination of materials and environments specified.

Aging Management Programs

The AMPs for the reactor vessel head vent system are identified in Section 3.1.2.4.4 of this

SER. These programs are common AMPs, and are reviewed in different sections of this SER,

as indicated in parentheses.

* ASME Section Xl Inservice Inspection Program (Section 3.0.3.1)

* Water Chemistry Program (Section 3.0.3.2)

* One-Time Inspection Program (Section 3.0.3.10)

* Bolting Integrity Program (Section 3.0.3.5)

* BWR Stress Corrosion Cracking Program (Section 3.0.3.3)

* Structures Monitoring Program (Section 3.0.3.14)

* Compressed Air Monitoring (Section 3.0.3.8)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

All of the AMPs listed above are credited for managing the aging effects of several components

in various structures and systems and are, therefore, considered common AMPs. The staff has

evaluated these common AMPs and found them to be acceptable for managing the aging

effects identified for this system. The staff's evaluation of these AMPs is documented in

Section 3.0 of this SER. On the basis of its review, the staff finds that the AMPs credited in the

LRA for the reactor vessel head vent system components will effectively manage or monitor the

aging effects identified in the LRA.

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Conclusions. On the basis of its review, the staff finds that the applicant has demonstrated that

the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.1.2.4.5 Nuclear Boiler Instrumentation System

Summary of Technical Information in the Application. The description of the nuclear boiler

instrumentation system can be found in Section 2.3.1 of this SER. The passive, long-lived

components in this system that are subject to an AMR are discussed in LRA Section 3.1, "Aging

Management of Reactor Vessel, Internals, and Reactor Coolant System," and are identified in

LRA Table 2.3.1-7. The components, aging effects, and AMPs are provided in LRA Tables 3.1-

1 and 3.1-2. In a letter, dated February 7, 2003, from Mr. P.R. Simpson, Exelon, to the NRC,

D/QCNPS sent corrections to LRA Table 2.3.1-7. The corrections included deletion of aging

management reference links that do not apply to certain component groups of the nuclear boiler

instrumentation system and addition of an aging management reference link that was missing

for a component group.

Aging Effects

The applicant reviewed the industry experience (e.g., NRC information notices, generic letters,

and bulletins) and the D/QCNPS operating experience (e.g., plant maintenance history,

modifications, nonconformance reports, and licensee event reports) and identified the

components, aging effects, and AMPs in LRA Tables 3.1-1 and 3.1-2.

The nuclear boiler instrumentation system monitors the reactor vessel temperature, reactor

vessel pressure, reactor vessel water level, reactor internal differential pressure, and reactor

vessel flange leakage. The long-lived, passive components in the system that are subject to an

AMR consist of piping and fittings, tubing, valves, tanks, thermowells, vents, drains,

filters/strainers, dampeners (Quad Cities only), and closure bolting. These components are

fabricated of stainless steel, CASS, low-alloy steel, carbon steel, brass, or bronze. The

operating environments are reactor coolant water or steam at 2880C (550 OF); oxygenated or

demineralized water at temperatures up to 288 0C; ambient air at metal temperatures up to

288 0C (550 OF); air, moisture, humidity, and leaking fluid; and containment nitrogen.

In Tables 3.1-1 and 3.1-2, the applicant identified the following aging effects for the nuclear

boiler instrumentation system components subject to an AMR:

* crack initiation and growth due to SCC, IGSCC, thermal and mechanical loading, and cyclic

loading

* wall thinning due to flow-accelerated corrosion

* loss of material due to wear

* loss of material due to general, galvanic, pitting, and crevice corrosion

In LRA Tables 2.3.1-7 and 3.1-2, the applicant also listed the following nuclear boiler

instrumentation system components for which no aging effect is identified:

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* external surfaces of carbon steel piping, fittings, tubing, and valves exposed to containment

air (Table 3.1-2, Reference No. 3.1.2.4)

* external surfaces of stainless steel piping and fittings, dampeners, filters and strainers,

valves and tubing exposed to air, moisture, and humidity (Table 3.1-2, Reference No.

3.1.2.7)

* external surfaces of stainless steel piping and fittings, tubing, tanks, thermowells, and

valves exposed to containment nitrogen (Table 3.1-2, Reference No. 3.1.2.8)

Aging Management Programs

In LRA Tables 3.1-1 and 3.1-2, the applicant identified the following six AMPs to manage the

aging effects associated with the nuclear boiler instrumentation system components:

* ASME Section Xl Inservice Inspection Program

* Water Chemistry Program

* One-Time Inspection Program

* Bolting Integrity Program

* BWR Stress Corrosion Cracking Program

* Flow-Accelerated Corrosion Program

Staff Evaluation. The applicant described its AMR for the nuclear boiler instrumentation system

in Section 3.1 of the LRA. The staff reviewed this section to determine whether the applicant

identified all the applicable aging effects for components in these systems and demonstrated

that the effects of aging on the components will be adequately managed during the period of

extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the applicable

UFSAR Supplements for the AMPs to ensure that the program descriptions adequately

describe the AMPs.

Aging Effects

The aging effects identified by the applicant for the nuclear boiler instrumentation system are as

follows:

* crack initiation and growth due to SCC, IGSCC, thermal and mechanical loading, and cyclic

loading

* wall thinning due to flow-accelerated corrosion

* loss of material due to wear

* loss of material due to general, galvanic, pitting, and crevice corrosion

The applicant identified crack initiation and growth due to SCC and IGSCC as an applicable

aging effect for nuclear instrumentation system stainless steel dampeners, vessel flange leak

detection line, piping and fittings (Quad Cities only), thermowells, tanks, tubing, and valves

exposed to reactor coolant water or steam at 288 0C (550 'F) or containment nitrogen. This

identification is consistent with Chapter IV.C1 of NUREG-1801. In addition, the applicant

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identified crack initiation and growth due to SCC and IGSCC and mechanical loading as an

applicable aging effect for nuclear instrumentation system carbon and stainless steel small-bore

piping and fittings exposed to reactor coolant water at 288 0C (550 OF). The staff notes that the

identification of this aging effect for these components is consistent with Item C1.1-I of NUREG1801.

The applicant also identified crack initiation and growth due to SCC and IGSCC as an

applicable aging effect for non-safety-related nuclear instrumentation system stainless steel

filters and strainers exposed to reactor coolant water or steam at 288 0C (550 OF), stainless

steel piping and fittings exposed to oxygenated water at temperatures up to 288 0C (550 0F),

and stainless steel tubing exposed to demineralized water at temperatures up to 288 0C

(550 0F). The staff notes that the AMR of these non-safety-related components is not

presented in NUREG-1801, but similar combinations of materials and environments are

evaluated in NUREG-1801. The applicant's identification of cracking as an aging effect for nonsafety-related stainless steel components is consistent with Item D2.1-c, Chapter V.D2, and

Item C1.1-f, Chapter IV.C1, of NUREG-1801.

Reference No. 3.1.2.7, LRA Table 3.1-2, states that there is no applicable aging effect for

nuclear boiler instrumentation system stainless steel component external surfaces exposed to

air, moisture, and humidity at temperatures less thanl00 0C (212 0F) or containment nitrogen.

The staff accepts this identification of no aging effect because stainless steel is not susceptible

to crack initiation and growth due to SCC and IGSCC at these low temperatures or to loss of

material due to different corrosion mechanisms because the environment is not aggressive and

stainless steel is resistant to corrosion.

Finally, the applicant identified crack initiation and growth due to thermal and mechanical

loading as an applicable aging effect for small-bore carbon steel piping and fittings in the

nuclear boiler instrumentation system. The staff notes that this assessment is consistent with

Item C.1.1-i, Chapter IV.C1, of NUREG-1801.

The applicant identified crack initiation and growth due to cyclic loading as an applicable aging

effect for the low-alloy steel nuclear boiler instrumentation system pressure boundary closure

bolting. This identification of cracking as an applicable aging effect is consistent with Item 1.2-b,

Chapter VII.I, of NUREG-1801.

In LRA Section 3.1.1.2.2, the applicant identified wall thinning due to flow-accelerated corrosion

as an aging effect for the carbon steel nuclear boiler instrumentation system piping and fittings

exposed to 2880C (550 0F) steam. However, the applicant stated that the carbon steel

components in the nuclear boiler instrumentation system are not susceptible to flow-accelerated

corrosion and do not require aging management for this effect. This determination is based on

the fact that these components operate less than 2 percent of the plant operating time or at flow

rates less than 1.8 m/s (6 fts). The applicant references EPRI reports NSAC-202L-R2 and TR114882, "Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools," as the

bases for these criteria. In RAI 3.1-18, the staff notes that Section XI.M17, "Flow-Accelerated

Corrosion," of NUREG-1 801 only relies on EPRI report NSAC-202L-R2 for an effective flowaccelerated corrosion program. The staff requested the applicant to confirm whether EPRI

report NSAC-202L-R2 states that carbon steel components are not susceptible to flowaccelerated corrosion when subject to flow rates less than 1.8 m/s (6 ftWs) when these

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components are operated, and, therefore, do not require aging management. If not, the

applicant must specify the applicable AMP as required by NUREG-1801.

In response to RAI 3.1-18, in a letter dated October 3, 2003, the applicant stated that the

reactor vessel bottom head drain lines are included in the Dresden and Quad Cities Flow

Accelerated Corrosion Program. Except for the reactor vessel bottom head drain lines, all

components in the nuclear boiler instrumentation system are made of stainless steel,

experience no flow, or operate less than 2 percent of plant operating time. Therefore, the

reactor vessel bottom head drain lines are the only components in the nuclear boiler

instrumentation system that are susceptible to flow-accelerated corrosion. I In addition, the

applicant stated that in LRA Table 2.3.1-7. "Component Groups Requiring Aging Management

Review Nuclear Boiler Instrumentation," "Quad Cities only" should have been removed from the

Piping and Fittings line. The staff finds the applicant's response to be acceptable because the

applicant does not use a flow velocity less than 1.8 m/s as one of the criteria for determining

whether a component is susceptible to flow-accelerated corrosion.

The applicant identified loss of material due to wear as an aging effect for the nuclear boiler.

instrumentation system low-alloy and high-strength, low-alloy steel closure bolting exposed to

air with metal temperatures up to 288 0

C (550 'F). The staff notes that this assessment is

consistent with NUREG-1801. The applicant also identified this aging mechanism for these

components in a containment nitrogen environment. The staff agrees that these components

are subject to loss of material due to wear.

In LRA Table 3.1-2, the applicant identified loss of material due to various forms of corrosion as

an aging effect for the nuclear boiler instrumentation system stainless steel tubing exposed to

saturated air; and for carbon and stainless steel piping, fittings, and valve bodies in contact

with reactor coolant and oxygenated water at temperatures up to 288 0C (550 'F). This aging

effect is also identified for stainless steel tubing in contact with warm, moist air. The AMR

results for these components are not presented in Chapter IV.C1, "Reactor Coolant Pressure

Boundary (BWR)," of NUREG-1801. However, AMR results for components with similar

materials and environments can be found in other chapters of NUREG-1801 and are used here

to evaluate the AMR results presented in LRA Table 3.1-2.

The applicant identified loss of material due to general corrosion as an aging effect for carbon

steel, stainless steel, and brass or bronze vents or drains, piping, and valves exposed to air,

moisture, humidity, and leaking fluid. The staff finds that the identification of loss of material as

an applicable aging effect for the carbon steel components is consistent with Item E.2-a,

Chapter V.E, of NUREG-1 801. For the stainless steel, brass, or bronze components, the staff

agrees that these components are subject to this aging effect in these environments, since

trace levels of corrosive species are generally present in moist environments.

The applicant identified loss of material due to pitting and crevice corrosion as an aging effect

for carbon and stainless steel piping and fittings, stainless steel tubing, and carbon and

stainless steel valve components operating in contact with leaking reactor coolant water,

oxygenated water, steam, or warm moist air at temperatures up to 2880C (550 'F). The staff

finds that, for the carbon and stainless steel components in oxygenated water, this identification

is consistent with Items A4.1 -a and A4.3-a, Chapter VII.A, of NUREG-1 801. For the remaining

environments, the staff agrees that these components are subject to loss of material, since

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trace levels of corrosive species commonly present in the reactor coolant, oxygenated water, or

on the component surfaces can interact with moisture and condensation from moist air.

The applicant did not identify loss of material due to corrosion as an aging effect for closure

bolting in the nuclear boiler instrumentation system. This is acceptable because closure bolting

is made of low-alloy steel which is resistant to corrosion.

In LRA Section 3.1.1.1, the applicant did not identify the loss of fracture toughness due to

thermal aging embrittlement as an applicable aging effect for CASS CRD valve bodies located

around CRD housings in the nuclear boiler instrumentation system. In RAI 3.1-20a, the staff

requested the applicant to explain why loss of fracture toughness is not an applicable aging

effect for these valve bodies. If loss of fracture toughness is identified as an applicable aging

effect, then the applicant needs to provide a program for managing that effect. In response to

RAI 3.1-20a, in a letter dated October 3, 2003, the applicant stated that in GALL AMP XI.M12,

"Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS)," the "Scope of

Program" element states, "The screening criteria are applicable to all primary pressure

boundary and reactor vessel internal components constructed from SA-351 Grades CF3, CF3A,

CF8, CF8A, CF3M, CF3MA, CF8M, with service conditions above 250 0C (482 OF)".

The valves associated with the nuclear boiler instrumentation system are located outside the

drywell and are not insulated. The reactor coolant temperature through these valves is below

250 0C (482 OF). Additionally, the material for these valves is ASTM 182, not ASTM A351. The

valves associated with the CRD hydraulic system are continuously supplied with cooling water

less than 38 0C (100 OF) from the cooling water header of the control rod drive hydraulic

system. This maintains the control rod drives and all associated valve temperatures to less

than 121 TC (250 OF). For these reasons, the applicant concluded that loss of fracture

toughness is not an applicable aging effect. The staff finds the applicant's response to be

acceptable because the use of forged stainless steel (ASTM 182) as the material of

construction and the operating temperatures less than 121 CC (250 OF) preclude thermal

embrittlement as an applicable aging effect for the components in question.

In LRA Section 3.1.1.1, the applicant identified no applicable aging effect for external surfaces

of carbon steel piping, fittings, tubing, and valves exposed to a containment nitrogen

environment. In RAI 3.1-5, the staff states that this identification of no aging effect is not

acceptable because the air in BWR containment is likely to have high humidity, and this humid

environment can cause corrosion of the external surface of carbon steel components. The staff

requested the applicant to provide technical justification for not identifying loss of material as an

applicable aging effect for the external surface of carbon steel components exposed to a

containment environment. The staff evaluated the response to this RAI in Section 3.1.2.4.1 of

this SER and found it acceptable. The staff agreed with the applicant that there are no

applicable aging effects for external surfaces of carbon components exposed to a containment

nitrogen environment because the low oxygen level present in the primary containment

atmosphere precludes loss of material due to corrosion as a credible aging effect for the

external surface of carbon steel components exposed to the containment environment.

The applicant identified no applicable aging effect for stainless steel components externally

exposed to air, moisture, humidity, and containment nitrogen. This is acceptable because the

environments to which the stainless steel components are exposed are not aggressive.

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The aging effects identified in the LRA for the nuclear boiler instrumentation system

components are consistent with industry operating experience for the materials and

environments listed. The staff finds that all the plausible aging effects were identified and that

the aging effects listed are appropriate for the combination of materials and environments

specified.

Aging Management Programs

The AMPs for the nuclear boiler instrumentation system are identified in Section 3.1.2.4.5.1 of

this SER. These programs, all of which are common AMPs, are reviewed in the following

sections of this SER:

* ASME Section Xl Inservice Inspection Program (Section 3.0.3.1)

* Water Chemistry Program (Section 3.0.3.2)

* One-Time Inspection Program (Section 3.0.3.10)

* Bolting Integrity Program (Section 3.0.3.5)

* BWR Stress Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Periodic Inspection of Components Subject to Moist Environments (Section 3.0.3.18)

As part of RAI B.1.23.2-6, the staff questioned the use of the one-time inspections to manage

aging for components in a moist air environment. In its response dated March 25, 2004, the

applicant credited the Periodic Inspection of Components Subject to Moist Environments

program to manage aging effects for stainless steel, carbon steel, cast iron, aluminum, copper,

and brass and bronze components exposed to moist air environments and subject to wetting.

The staff's evaluation of the Periodic Inspection of Components Subject to Moist Environments

AMP is contained in SER section 3.0.3.18.

The applicant credited LRA Appendices B.1.2, "Water Chemistry," and B.1.23, "One-Time

Inspection," for managing loss of material due to corrosion in nuclear boiler instrumentation

system carbon steel and stainless steel components. The applicant stated that the One-Time

Inspection Program is consistent with Chapter XL.M32, "One-Time Inspection," specified in

NUREG-1 801. The staff finds the use of the One-Time Inspection Program appropriate for

managing loss of material in these components because it will identify the presence of any loss

of material at the inner surface of the component inspected and verify the effectiveness of

water chemistry.

However, in RAI 3.1-15, the staff noted that the applicant credited only LRA Appendix B.1.2,

"Water Chemistry," for managing cracking in the nuclear boiler instrumentation system stainless

steel components. The AMR for these components is presented in Table 3.1-2, Reference

Nos. 3.1.2.13,3.1.2.23,3.1.2.24, 3.1.2.26, 3.1.2.38,3.1.2.49, and 3.1.2.52. In RAI 3.1-15, the

staff requested that the applicant explain why it credited the One-Time Inspection Program for

managing loss of material, but not cracking. The applicant needs to credit the One-Time

Inspection Program to assess whether cracking is taking place in these stainless steel

components. In response to RAI 3.1-15, in a letter dated October 3, 2003, the applicant stated

that these piping components do not require a one-time inspection because they are small-bore

(2 in. and under) socket welded components, downstream of the excess flow check valves and

located outside primary containment. The normal operating temperature is less than 60 0C

(140TF), the minimum temperature needed to initiate IGSCC. Therefore, the aging

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management references should have reported an environment of "Reactor Coolant Water (less

than 60 'C or 140 'F)"; aging Effect/mechanism as "None," and the AMP as "None."

The applicant also noted that this environment is neither part of the original LRA, nor is it

contained in the response provided to RAI 3.0-1, submitted to the NRC on June 11. 2003. This

piping was originally considered to be in the 288 CC (550 OF) reactor water coolant environment,

similar to the piping to which it is attached. However, the actual normal operating environment

is less than 60 CC (140 OF). The applicant additionally noted that LRA Table 2.3.1-5,

"Components Requiring Aging Management Review -Reactor Recirculation System,"

component group,"NSR Vents and Drains, Piping and Valves (attached support)," should not

have indicated Dresden only. The staff finds the applicant's response to be acceptable

because SCC is not anticipated in stainless steel components operating at temperatures below

600C (1400F).

All of the AMPs listed above are credited for managing the aging effects of several components

in various different structures and systems and are, therefore, considered common AMPs. The

staff has evaluated these common AMPs and found them to be acceptable for managing the

aging effects identified for this system. The staff's evaluation of these AMPs is documented in

Section 3.0 of this SER. On the basis of its review, the staff finds that the AMPs credited in the

LRA for the nuclear boiler instrumentation system components will effectively manage or

monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.1.2.4.6 Head Spray System

Summary of Technical Information in the Application. The description of the head spray system

(Dresden only) can be found in Section 2.3.1 of this SER. The passive, long-lived components

in this system that are subject to an AMR are discussed in LRA Section 3.1, "Aging

Management of Reactor Vessel, Internals, and Reactor Coolant System." and are identified in

LRA Table 2.3.1-8. The components, aging effects, and AMPs are provided in LRA Tables 3.1-

1 and 3.1-2.

Aging Effects

The applicant reviewed the industry experience (e.g., NRC information notices, generic letters,

and bulletins) and the Dresden operating experience (e.g., plant maintenance history,

modifications, nonconformance reports, and licensee event reports) and identified the

components, aging effects, and AMPs in LRA Tables 3.1-1 and 3.1-2.

The head spray system is found only in Dresden Units 2 and 3 and is used to collapse the

steam bubble during vessel flooding, to cool the reactor vessel head, and to collapse the steam

in the vessel while the reactor is in the shutdown mode of operation. The head spray system

consists of the head spray line, which interfaces with the CRD hydraulic piping, and the

associated valves. The long-lived, passive components in the system that are subject to an

AMR consist of piping and fittings, valves, vents, drains, flow elements, and closure bolting.

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These components are fabricated of stainless steel, low-alloy steel, carbon steel, brass, or

bronze. The operating environments are reactor coolant water or steam at 288 0C (550 OF),

demineralized water at temperatures up to 288 0C (550 OF), ambient air at metal temperatures

up to 288 0C (550 OF), and containment nitrogen.

In Tables 3.1-1 and 3.1-2, the applicant identified the following aging effects for the head spray

system components subject to an AMR:

* crack initiation and growth due to SCC, IGSCC, thermal and mechanical loading, and cyclic

loading

* loss of material due to wear

* loss of material due to general, galvanic, pitting, and crevice corrosion

In LRA Tables 2.3.1-8 and 3.1-2, the applicant also listed the following reactor vessel head

spray system components for which no aging effect is identified:

* external surfaces of stainless steel filters/strainers, piping and fittings, dampeners, tubing,

and valves exposed to air, moisture, and humidity,(Table 3.1-2, Reference No.:3.1.2.7)

* external surfaces of stainless steel tubing and valves exposed to containment nitrogen

(Table 3.1-2, Reference No. 3.1.2.8)

Aging Management Programs

In LRA Tables 3.1-1 and 3.1-2, the applicant identified the following five AMPs to manage the

aging effects associated with the head spray system components:

* ASME Section XI Inservice Inspection Program

* Water Chemistry Program

* One-Time Inspection Program

* Bolting Integrity Program

* BWR Stress Corrosion Cracking ProgramStaff Evaluation.. The applicant described its AMR for the head spray system in Section 3.1 of

the LRA. The staff reviewed this section to determine whether the applicant identified all the

applicable aging effects for components in the system and demonstrated that the effects'of

aging on the components will be adequately managed during the period of extended operation,

as required by 10 CFR 54.21 (a)(3). The staff also reviewed the applicable UFSAR

supplements for the AMPs to ensure that the program descriptions adequately describe the

AMPs.

Aging Effects

The aging effects identified by the applicant for the head spray system are as follows:

* crack initiation and growth due to SCC, IGSCC, thermal and mechanical loading, and cyclic

loading

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l loss of material due to wear

* loss of material due to general, galvanic, pitting, and crevice corrosion

The applicant identified crack initiation and growth due to SCC and IGSCC as an applicable

aging effect for the head spray system austenitic stainless steel components (piping, fittings,

and valve bodies) exposed to reactor coolant water and steam and demineralized water at

temperatures up to 288 0C (550'F). The applicant also identified crack initiation and growth

due to SCC, IGSCC, and thermal and mechanical loading as an applicable aging effect for

small-bore stainless steel piping and fittings in the head spray system. The staff notes that

these assessments are consistent with Chapter IV.C1 of NUREG-1 801.

The applicant identified crack initiation and growth due to cyclic loading as an applicable aging

effect for the low-alloy steel head spray system pressure boundary closure bolting. This

identification of crack initiation and growth as an applicable aging effect is similar to Item 1.2-b,

Chapter VII.l, of NUREG-1801.

The applicant identified loss of material due to wear as an aging effect for the head spray

system low-alloy and high-strength, low-alloy steel closure bolting exposed to air and

containment nitrogen environment with metal temperatures up to 2880C (550'F). The staff

notes that this assessment is consistent with Item C1.2-d, Chapter IV.C1, of NUREG-1801.

The applicant identified loss of material due to general, pitting, and crevice corrosion as an

aging effect for the carbon steel piping, fittings, flow elements, and valve bodies in contact with

demineralized water at temperatures up to 288 CC (550 CF) and for stainless steel, carbon steel,

and bronze or brass vents, drains, piping, and valves in contact with air, moisture, humidity, and

leaking fluid. The AMR results for these components are not presented in Chapter IV.C1,

'Reactor Coolant Pressure Boundary (BWR)," of NUREG-1801. However, AMR results for

components with similar materials and environments can be found in other chapters of NUREG1801 and are used here to evaluate the AMR results presented in LRA Table 3.1-2.

The applicant identified loss of material due to general corrosion as an aging effect for stainless

steel, carbon steel, and bronze or brass vents, drains, piping, and valves in contact with air,

moisture, humidity, and leaking fluid. The staff finds that the identification of the carbon steel

components is consistent with Item E.2-a, Chapter V.E, of NUREG-1801. For the stainless

steel, brass, or bronze components, the staff agrees that these components are subject to this

aging effect in these environments, since trace levels of corrosive species are generally present

in moist environments.

The applicant identified loss of material due to general, pitting, and crevice corrosion as an

applicable aging effect for the carbon steel piping, fittings, flow elements, and valve bodies in

contact with demineralized water at temperatures up to 288'CC (550 CF). The staff finds that this

identification is consistent with Item D2.1-a, Chapter V.D2, of NUREG-1801.

The applicant did not identify loss of material due to corrosion as an aging effect for closure.

bolting in the head spray system. This is acceptable because closure bolting is made of lowalloy steel.

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The applicant identified no applicable aging effect for stainless steel components externally

exposed to air, moisture, and humidity and containment nitrogen. This is acceptable because

the environments to which the stainless steel components are exposed are not aggressive.

The aging effects identified in the LRA for the head spray system components are consistent

with industry operating experience for the materials and environments listed. The staff finds

that all the plausible aging effects were identified and that the aging effects listed are

appropriate for the combination of materials and environments specified.

Aging Management Programs

The AMPs for the head spray system are identified in Section 3.1.2.4.6 of this SER. These

programs, all of which are common AMPs, are reviewed in the following sections of this SER:

* -ASME Section XI Inservice Inspection Program (Section 3.0.3.1)

* Water Chemistry Program (Section 3.0.3.2)

* One-Time Inspection Program (Section 3.0.3.10)

* Bolting Integrity Program (Section 3.0.3.5)

* BWR Stress Corrosion Cracking Program (Section 3.0.3.3)

All of the AMPs listed above are credited for managing the aging effects of several components

in various different structures and systems and are, therefore, considered common AMPs. The

staff has evaluated these common AMPs and found them to be acceptable for managing the

aging effects identified for this system. The staff's evaluation of these AMPs is documented in

Section 3.0 of this SER. On the basis of its review, the staff finds that the AMPs credited in the

LRA for the head spray system components will effectively manage or monitor the aging effects

identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.1.2.4.7 Reactor Coolant Pressure Boundary Components in Other Systems

Summary of Technical Information in the Application. The description of all reactor coolant

pressure boundary components in other systems can be found in Section 2.3.2, 2.3.3, and

2.3.4 of this SER. The components, aging effects, and AMPs are provided in LRA Tables 3.1-1

and 3.1-2. The passive, long-lived components subject to AMR are identified within the

following 12 systems. The appropriate LRA system tables are identified in parentheses

* High Pressure Coolant Injection (HPCI) System (LRA Table 2.3.2.1)

* Core Spray System (LRA Table 2.3.2.2)

* Reactor Core Isolation Cooling (RCIC) System (Quad Cities only) (LRA Table 2.3.2.4)

* Isolation Condenser (Dresden only) (LRA Table 2.3.2.5)

* Residual Heat Removal (RHR) System (Quad Cities only) (LRA Table 2.3.2.6)

* Low Pressure Coolant Injection (LPCI) System (Dresden only) (LRA Table 2.3.2.7)

* Standby Liquid Control (SBLC) System (LRA Table 2.3.2.8)

* Shutdown Cooling System (SDC) (Dresden only) (LRA Table 2.3.3.2)

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* Control Rod Drive (CRD) Hydraulic System (LRA Table 2.3.3.3)

* Reactor Water Cleanup (RWCU) System (LRA Table 2.3.3.4)

* Main Steam (MS) System (LRA Table 2.3.4.1)

* Feedwater (FW) System (LRA Table 2.3.4.2)

Aging Effects

The applicant reviewed the industry experience (e.g., NRC information notices, generic letters,

and bulletins) and the Dresden and Quad Cities operating experience (e.g., plant maintenance

history, modifications, nonconformance reports, and licensee event reports) and identified the

aging effects, component intended functions, environment, and materials for each group of

reactor coolant pressure boundary components in the above 12 systems in Tables 3.1-1 and

Table 3.1-2 of the LRA.

The long-lived, passive pressure boundary components in these 12 systems that are subject to

an AMR are fabricated of stainless steel (piping and fittings, tubing, valves, dampeners, flow

elements, tubesheet, channel head), CASS (piping and fittings, filters/strainers, and valves),

low-alloy steel (closure bolting), and carbon steel (piping and fittings, valves, filters/strainers,

flow elements, tubesheet, channel head, shell). The operating environments are reactor

coolant water or steam at 288 0C (550 0F), oxygenated water up to 288 0C (550 OF), reactor

coolant water up to 225 0

C (437 OF), ambient air and humidity at metal temperatures up to

288 0C (550 'F), warm moist air, steam on the tube side and demineralized water on the shell

side of isolation condensers, and containment nitrogen.

The applicant identified the following general aging effects for the reactor coolant pressure

boundary components in the ESF and the auxiliary and steam and power conversion (SPC)

systems:

* build up of deposit/fouling

* crack initiation and growth due to SCC, IGSCC, thermal and mechanical loading, and cyclic

loading

* cumulative fatigue damage

* loss of fracture toughness due to thermal aging embrittlement

* loss of material due to general, pitting, and crevice corrosion

* loss of material due to wear

* wall thinning due to flow-accelerated corrosion

Aging Management Programs

In LRA Tables 3.1-1 and 3.1-2, the applicant identified the following seven AMPs for the reactor

coolant pressure boundary components in the ESF and the auxiliary and SPC systems:

* Bolting Integrity Program

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* BWR Stress Corrosion Cracking Program

* Flow-Accelerated Corrosion Program

* Heat Exchanger Test and Inspection Activities Program

* ASME Section Xl Inservice Inspection Program

* One-Time Inspection Program

* Water Chemistry Program

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects and the AMPs credited for managing the aging effects in the reactor

coolant pressure boundary components in the ESF and the auxiliary and SPC systems. The

staff also reviewed the applicable UFSAR supplements for the AMPs to ensure that the

program descriptions adequately describe the AMPs.

Aging Effects

The applicant identified the following aging effects for the reactor coolant pressure boundary

components in the ESF and the auxiliary and SPC systems.

* build up of deposit/fouling

* crack initiation and growth due to SCC, IGSCC, thermal and mechanical loading, and cyclic

loading

* cumulative fatigue damage

* loss of fracture toughness due to thermal aging embrittlement

* loss of material due to general, pitting, and crevice corrosion

* loss of material due to wear

* wall thinning due to flow-accelerated corrosion

In LRA Table 3.1-2, the applicant identified build up of deposit due to fouling as an applicable

aging effect for the stainless steel tubes in the isolation condenser heat exchangers (Dresden

only) exposed to steam on the tube side and demineralized water on the shell side. The

applicant refers to an "EPRI/SANDIA" report that identifies fouling as an applicable effect due to

construction and operating conditions. In the LRA Table 3.1-2, Reference No. 3.1.2.15, the

applicant pointed out that NUREG-1801 does not identify fouling as an applicable aging effect.

In RAI B.2.6-e, the staff requested that the applicant provide a full reference to the

EPRI/SANDIA report referred to in the LRA and summarize the industry and plant-specific

experience related to fouling of the isolation condenser heat exchangers in demineralized

water. In response to RAI B.2.6-e, in a letter dated October 3, 2003, the applicant stated that

the EPRI/SANDIA reports identified in Aging Management Reference 3.1.2.15 of LRA Table

3.1-2 are EPRI 1003056, "Non-Class 1 Mechanical Implementation Guideline and Mechanical

Tools, Appendix G, Heat Exchangers," and Sandia National Laboratory Report SAND93-7070

UC-523, "Aging Management Guideline for Commercial Nuclear Power Plants-Heat

Exchangers." The applicant further stated that no Dresden-specific operating experience

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: !

involving fouling of the isolation condenser tubing in the demineralized water environment was

identified. However, EPRI TR-1003056 identifies fouling as an applicable aging effect for

stainless steel tubing in treated water and primary water environments. The staff finds the

applicant's response to be acceptable because the staff verified that the EPRI and Sandia

reports referenced by the applicant discuss fouling of heat exchangers in nuclear plants and

provide credible evidence that fouling of the isolation condenser heat exchangers can occur in

primary and secondary water environments.

The applicant identified crack initiation and growth due to cyclic loading as an applicable aging

effect for the low-alloy steel standby liquid control system pressure boundary closure bolting

exposed to containment nitrogen. The applicant pointed out (LRA Table 3.1-2, Reference No.

3.1.2.1) that NUREG-1801 does not address closure bolting in a containment nitrogen

environment. However, it is the cyclic loading, and not the nitrogen environment, that is

causing crack initiation and growth. The staff concludes that this identification of crack initiation

and growth as an applicable effect for low-alloy steel bolting is acceptable because it is

consistent with Item 1.2-b in Chapter VII.l of NUREG-1 801.

In LRA Table 3.1-2 (Reference Nos. 3.1.2.11, 3.1.2.26, 3.1.2.35, and 3.1.2.52), the applicant

identified crack initiation and growth due to SCC as an applicable aging effect for "stainless

steel casting" filters/strainers and valves, and stainless steel tanks, and piping and fittings in the

control rod drive hydraulic system exposed to oxygenated water up to 288 0C (550 'F). These

components serve as a reactor coolant pressure boundary, are located around CRD housing,

and are exposed to condensate storage tank (CST) water. Therefore, the staff concludes that

this identification of crack initiation and growth due to SCC is acceptable. However, the staff

noted in RAI 3.1-21a that NUREG-1801 does not address aging management of these CRD

components. The staff requested that the applicant submit industry experience and plantspecific experience related to aging degradation of these CRD components. Based on this

experience, the applicant was requested to provide justification for not requiring inspection

(Item 3.1.2.11 requires water chemistry).

In response to RAI 3.1-21 a, in a letter dated October 3, 2003, the applicant stated that no

incidents of crack initiation and growth due to SCC in the control rod drive system were

identified at Dresden or Quad Cities. A review of industry experience, including Dresden and

Quad Cities, noted problems with degradation of the surface plating on CRD hydraulic

accumulator interior surfaces resulting in some corrosion and pitting of the plated carbon steel.

However, this degradation is not associated with SCC. In addition, the applicant stated that

cracking was discovered in the control rod drive hydraulic control system return line near its

connection to the reactor. The CRD return line to the reactor has been removed for both

Dresden and Quad Cities, thereby eliminating this concern for SCC in the CRD system. Except

for the return line to the reactor, the review of operating experience did not produce any

indications of SCC in the control rod drive system. SCC has not occurred in the control rod

drive system at Dresden or Quad Cities, and the Dresden and Quad Cities CRD systems have

been modified to remove the components where SCC has occurred at other BWRs. The

Dresden and Quad Cities experience base, together with the control rod drive systems'

modification, supports a conclusion that properly controlled water chemistry is adequate to

eliminate the potential for SCC, and inspection for occurrence of SCC in the control rod drive

system is not required.

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The staff does not find the applicant's response to RAI 3.1-21 a to be completely satisfactory

since the applicant relies upon the Water Chemistry Program alone to manage possible SCC in

the control rod drive system. The applicant should perform a one-time inspection of the system

components to verify that the Water Chemistry Program is providing adequate protection

against SCC. The applicant needs to provide documentation for a one-time inspection. In

response to Supplemental RAI 3.1-21 a in a letter dated December 22, 2003, the applicant

stated that the process fluid temperature in the CRD hydraulic system is less than 100 OF, and

the typical flow conditions are either low flow'(in the cooling water line) or stagnant flow (in the

charging water and drive water lines). With process temperatures below 140 OF, EPRI

TR 1003056, "Mechanical Tools Appendix AX states that cracking due to SSC is very unlikely to

occur. In addition,'the applicant believes that water chemistry controls sufficient to prevent loss

of material due to pitting and crevice corrosion' in the CRD hydraulic system are also sufficient

to prevent stress corrosion cracking in that system. Nonetheless, the applicant will include

inspection for stress corrosion cracking as part of its one-time inspection to validate the

effectiveness of the Water Chemistry Program (LRA Appendix B.1.2) in managing the aging of

stainless steel components in the CRD hydraulic system. The staff finds the applicant's

response acceptable because the one-time inspection to validate the effectiveness of the water

chemistry is adequate for managing possible SCC in the CRD system. This is part of

Commitment #23 of Appendix A of this SER.

The applicant identified crack initiation and growth due to SCC and IGSCC as an applicable

aging effect for stainless steel reactor coolant pressure boundary components in the HPCI, core

spray, RCIC, RHR, LPCI, SBLC, SDC, RWCU, MS, and FW systems and the isolation

condenser exposed to 288 'C (550 0

F) reactor'coolant water or steam. Although some of

these components are not evaluated in NUREG-1 801, similar combinations of materials and

environments are evaluated. The identification of crack initiation and growth in the stainless

steel components exposed to 288 CC (550 OF) reactor coolant water or steam is consistent with

Item C1.1-f, Chapter IV.C1, of NUREG-1801.

The applicant identified crack initiation and growth due to SCC and IGSCC as an applicable

aging effect for the CASS reactor water cleanup system valves. This is acceptable because

CASS components are susceptible to cracking due to SCC and IGSCC if the CASS ferrite

content is less than 7.5 percent by volume and carbon is greater than 0.03 percent by weight.

The applicant identified crack initiation and growth due to SCC, IGSCC, and thermal and

mechanical loading as an applicable aging effect for stainless steel small-bore piping and

fittings in the reactor coolant pressure boundary components for the HPCI, core spray, RCIC,

and RWCU systems and the isolation condenser.-7The applicant also identified crack initiation

and growth due to thermal and mechanical loading as an applicable aging effect for carbon

steel small-bore piping and fittings in the main'steam and feedwater systems exposed to 288 OC

(550'F) reactor coolant water or steam. This identification of the aging effect is consistent with

Item C1.1-i, Chapter IV.C1, of NUREG-1801.

The applicant identified crack initiation and growth due to SCC or cyclic loading as an

applicable aging effect for the reactor coolant pressure boundary components in the isolation

condenser (stainless steel tubes, carbon steel or stainless steel tubesheet and channel head,

and carbon steel shell) exposed to steam on the tube side and demineralized water on the shell

side. This identification of the aging effect is consistent with Item C1.4-a, Chapter IV.C1, of

NUREG-1801.

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The applicant identified cumulative fatigue damage as an applicable aging effect for the highstrength, low-alloy steel closure bolting in the HPCI, core spray, RCIC, RHR, LPCI, SBLC,

RWCU, main steam, and feedwater systems and the isolation condenser externally exposed to

air with metal temperatures up to 288 0C (550 OF). This identification is consistent with Item

C1.3-g, Chapter IV.C1, in NUREG-1801.

In LRA Table 3.1-2, Reference Nos. 3.1.2.1 and 3.1.2.2, the applicant identified crack initiation

and growth due to cyclic loading and loss of material due to wear as applicable aging effects for

closure bolting in the reactor coolant pressure boundary portion of all the other systems and

credited LRA Appendix B.1.12, "Bolting Integrity," for managing these aging effects. This

identification of aging effects is consistent with NUREG-1 801 as mentioned earlier. However,

the applicant did not identify loss of preload as an aging effect for this closure bolting. In LRA

Appendix B.1.12, the applicant stated that loss of preload in a mechanical joint is a design

driven process and, therefore, is not an aging effect. The staff noted that loss of preload,

however, might take place during operation when closure bolting is subject to high

temperatures, cyclic loads, differential thermal expansion, and vibrations. In RAI 3.1-13, the

staff requested the applicant to explain why periodic inspection of the closure bolting for

indication of loss of preload due to the aforementioned mechanisms is not required. The staff

further requested the applicant, if periodic inspection is required, to reference the appropriate

AMP and include the appropriate inspection in the AMP.

The applicant's response to this RAI is evaluated in Section 3.1.2.4.1.2 of this SER. The staff

did not find the response completely acceptable for the following reason. LRA Section 3.1.1.2.1

does not address loss of preload as an aging effect, and states that loss of preload

mechanisms are typically addressed during installation and subsequent maintenance of closure

bolting. However, the applicant's response to RAI 3.1-13 stated that loss of preload will be

managed, and that the enhanced Bolting Integrity Program will be comprised of periodic ISIs

and piping and components preventive maintenance inspections. In Supplemental RAI 3.1-13,

the staff requested the applicant to describe the maintenance program activities that are

performed on the bolts so that loss of preload is significantly reduced or eliminated, and to

identify whether retorquing of the bolts to the design preload values is performed after the

component is reassembled. The applicant's response to Supplemental RAI 3.1-13 is evaluated

in Section 3.1.2.4.1 of this SER. The staff finds the response acceptable.

The applicant identified cumulative fatigue damage as an applicable aging effect for reactor

coolant pressure boundary components (carbon steel, stainless steel, and CASS piping, fittings,

and valve bodies) in the HPCI, core spray, RCIC, RHR, LPCI, SBLC, RWCU, MS, and FW

systems, and the isolation condenser internally exposed to 288 0C (550 OF) reactor coolant

water or steam. The identification of cumulative fatigue damage as an applicable aging effect

is consistent with Items C1.1-h and C1.3-d, Chapter IV.C1, of NUREG-1801.

The applicant identified loss of fracture toughness due to thermal aging embrittlement as an

applicable aging effect for CASS valve bodies in the reactor water cleanup system, but not in

the control rod drive hydraulic systems. Both of these systems are internally exposed to 288 0C

(550 °F) reactor coolant water. In RAI 3.1-20b, the staff requested that the applicant explain

why loss of fracture toughness is not an applicable aging effect for CASS valve bodies in the

control rod drive hydraulic system. In addition, the staff requested that the applicant confirm

whether there are any other reactor coolant pressure boundary components in the other

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systems that are made of CASS. if there are, then the applicant needs to submit AMR results

for these components.

In response to RAI 3.1-20b, in a letter dated October 3, 2003, the applicant stated, as explained

in its response to RAI 3.2-20a, that valves in the control rod drive hydraulic system are not

exposed to temperatures of 250 0C (482 OF) or greater. Only the reactor water cleanup system

and the reactor recirculation system include stainless steel valves in this category. All other

stainless steel valves, with an operating temperature of less then 250 0C (482 OF), are assigned

material types of stainless steel casting or stainless steel with the only aging effect being crack

initiation and growth. The aging management results for CASS valves in the reactor water

cleanup system and in the reactor recirculation system are provided in LRA Table 3.1-1, Aging

Management References 3.1.1.9 and 3.1.1.15. The staff finds the applicant's response to be

acceptable because the embrittlement aging effect of concern here is applicable only to CASS

components exposed for extended periods of time to temperatures of 2500C (482 0F) or

greater.

The applicant identified loss of material due to general (carbon steel only), pitting, and crevice

corrosion as an applicable aging effect for reactor coolant pressure boundary components in

the isolation condenser (stainless steel tubes, carbon steel or stainless steel tubesheet and

channel head, carbon steel shell) exposed to steam on the tube side and demineralized water

on the shell side. This identification of the aging effect is consistent with Item C1.4-b, Chapter

IV.C1, of NUREG-1801.

The applicant identified loss of material due to pitting and crevice corrosion as an applicable

aging effect for the "stainless steel casting" filter/strainers and valves, and stainless steel piping

and fittings, and tanks in the control rod drive hydraulic system exposed to oxygenated water up

to 288 0C (550 OF). NUREG-1 801 does not include AMR results for these control rod drive

hydraulic system components. However, the applicant's identification of loss of material due to

pitting and crevice corrosion as an aging effect for stainless steel components exposed to

oxygenated water up to 288 0C (550 0F) is consistent with the NUREG-1 801 evaluation for a

similar combination of material and environment (see Item D2.1-e, Chapter V.D2, in NUREG1801). The identification of loss of material in 'stainless steel casting" components in the

control rod drive hydraulic system is acceptable because the oxygenated water may contain

some low levels of contaminants such as chlorides.

The applicant also identified loss of material due to pitting and crevice corrosion as an

applicable aging effect for stainless steel tubing support in the main steam system externally

exposed to warm, moist air. This identification of loss of material due to pitting and crevice

corrosion of stainless steel supports exposed to warm, moist air is acceptable because the

BWR moist environment is likely to carry corrosive contaminants, such as chlorides, which can,

under certain circumstances, corrode stainless steel components.

The applicant identified loss of material due to wear as an applicable aging effect for closure

bolting in the SBLC system, but not in the HPCI, core spray, RCIC, RHR, LPCI, RWCU, MS,

and FW systems, and the isolation condenser externally exposed to air with metal temperatures

up to 288 0C (550 0F). The staff requested in RAI 3.1-22 that the applicant provide the

technical basis for not identifying loss of material due to wear as an applicable aging effect for

all the closure bolting in the reactor coolant pressure boundary portion of all the other systems.

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In response to RAI 3.1-22, in a letter dated October 3, 2003, the applicant stated that the LRA

does, in fact, identify loss of material due to wear as an applicable aging effect for closure

bolting in the HPCI, core spray, RCIC, RHR, and LPCI systems and in the isolation condenser.

Loss of material due to wear is identified for closure bolting in several LRA Chapter 2.3 tables

and is managed by the Bolting Integrity Program. The applicant further stated that loss of

material due to wear and crack initiation and growth due to cyclic loading should have been

identified for closure bolting in systems RWCU, MS, and FW and will also be managed with the

Bolting Integrity Program . The environment for closure bolting Aging Management References

3.1.2.1, 3.1.2.2, 3.2.2.1, and 3.2.2.4 should have read, "Air with metal temperature up to 288 0C

(550 OF). This environment description is consistent with the environment used in NUREG1801, Chapter IV, Items C1.3-e and C1.3-f.

The applicant also stated that LRA Tables 2.3.3-4, 2.3.4-1, and 2.3.4-2 for RWCU, MS, and FW

should have included closure bolting. In addition, the applicant described changes to LRA

Tables 3.1-2 and 3.2-2 that specifically include closure bolting as a component subject to aging

effects and the applicant's Bolting Integrity Program as the applicable AMP. The staff finds the

applicant's response to be acceptable because the applicant identified loss of material due to

wear as an applicable aging effect for closure bolting in all of the systems in question. The

applicant further provided an AMP for dealing with this aging effect that is consistent with GALL.

In LRA Section 3.1.1.2.2, the applicant identified wall thinning due to flow-accelerated corrosion

as an applicable aging effect for reactor coolant pressure boundary carbon steel components

(valves, piping and fittings, and flow elements) in the feedwater and main steam systems

exposed to 288 0C (550 OF) reactor coolant water or steam. This identification of wall thinning

due to flow-accelerated corrosion as an applicable aging effect is consistent with Items C1.1-a

and C1.1-c, Chapter IV.C1, of NUREG-1801. The applicant stated that wall thinning due to

flow-accelerated corrosion is not an applicable aging effect for carbon steel components in the

HPCI, core spray, RCIC, or SDC systems because D/QCNPS operates these systems for less

than 2 percent of plant operating time or at flow rates less than 6 ft/sec. Under these operating

conditions, according to EPRI NSAC-202L-R2 and EPRI TR-1 14882, the carbon steel

components are not susceptible to wall thinning due to flow-accelerated corrosion.

The staff noted in RAI 3.1-23 that DC/QCNPS has now implemented extended power uprates

to increase the power output of each of the four units. Such uprates are often accompanied by

increases in, for example, main steam and feedwater flows in BWRs. The staff, therefore,

requested the applicant to explain how the effects of extended power uprates are taken into

account in identifying components susceptible to wall thinning due to flow-accelerated

corrosion.

In response to RAI 3.1-23, in a letter dated October 3, 2003, the applicant listed the steam flow

and the feedwater flow at Dresden and Quad Cities both before and after the power uprates

and noted that both flow rates increased by about 20 percent as a result of the uprates. The

applicant further stated that these increases in steam flow and feedwater have been considered

and appropriately incorporated into the Flow-Accelerated Corrosion programs at Dresden and

at Quad Cities. The predictive analysis, CHECWORKS, has been updated to reflect uprate

design conditions such as mass flow, temperature, and steam quality. Where appropriate,

inspection intervals have been moved forward to address increased wear rates. The staff finds

the applicant's response to be acceptable because the CHECWORKS code provides an

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acceptable approach for managing possible flow-accelerated corrosion in reactor coolant

pressure boundary carbon steel components.

The aging effects identified in the LRA for the reactor coolant pressure boundary components in

other systems are consistent with industry operating experience for the materials and

environments listed. The staff finds that all the plausible aging effects were identified and that

the aging effects listed are appropriate for the combination of materials and environments

specified.

Aging Management Programs

The applicant credited the following seven common AMPs for managing aging in the reactor

coolant pressure boundary components in the ESF, auxiliary, and SPC systems. These

programs are reviewed by the staff in the SER sections listed below in parentheses:

* Bolting Integrity Program (Section 3.0.3.5)

* BWR Stress Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Heat Exchanger Test and Inspection Activities Program (Section 3.0.3.16)

* ASME Section Xl Inservice Inspection Program (Section 3.0.3.1)

* One-Time Inspection Program (Section 3.0.3.10)

* Water Chemistry Program (Section 3.0.3.2)

The applicant credited the BWR Stress Corrosion Cracking (LRA Appendix B.1.7) and Water

Chemistry (LRA Appendix B.1.2) Programs for managing crack initiation and growth due to

SCC and IGSCC in stainless steel components in the HPIC, core spray, RCIC, RHR, LPCI,

SBLC, SDC, RWCU, MS, and FW systems and the isolation condenser. The applicant also

stated that the BWR Stress Corrosion Cracking Program is based on BWRVIP-75, "Technical

Basis for Revisions to Generic Letter 88-01 Inspection Schedules (NUREG-0313)."

In RAI 3.1-24, the staff made the following four requests to the applicant:

(1) Submit information about D/QCNPS plant-specific experience related to IGSCC cracking of

the stainless steel components in the HPIC, core spray, RCIC, RHR, LPCI, SBLC, SDC,

RWCU, MS, and FW systems and the isolation condenser.

(2) Submit information about mitigation actions taken at D/QCNPS with respect to selection of

materials that are resistant to sensitization, use of special processes that reduce residual

tensile stress, and monitoring of water chemistry as specified by NUREG-1 801, Section

XL.M7.

(3) Confirm whether HWC and NMCA are implemented at D/QCNPS, and If so, explain how

this implementation has affected monitoring of water chemistry parameters.

(4) Submit information on the inspection frequency (based on whether HWC and/or NMCA are

used) and the corresponding number of welds to be inspected following the BWRVIP-75

guidelines.

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The staff's evaluation of RAI 3.1-24 is presented in Section 3.1.2.4.3 of this SER. In that

evaluation, the staff concludes that the responses to RAls 3.1-24(a) through (d) are acceptable.

The applicant credited LRA Appendix B.1.1, "ASME Section Xi Inservice Inspection,

Subsections IWB, IWC, and IWD," for managing loss of fracture toughness due to thermal

aging embrittlement in reactor water cleanup valve bodies made of CASS. The Inservice

Inspection Program includes visual inspection for detecting surface-breaking cracks in the

CASS valve bodies. Inspection for cracking is acceptable for managing loss of fracture

toughness in CASS valve bodies because loss of fracture toughness in CASS components

becomes a concern only if cracks are present. The use of visual inspection is acceptable

because the cracks are likely to be surface cracks caused by SCC or IGSCC. However, the

staff noted in RAI 3.1-14 that the applicant needs to provide the technical basis showing how

the proposed visual inspection technique is qualified for detecting IGSCC cracks in the CASS

valve bodies. In addition, ASME Code, Section Xl, Subsection IWB, provides little guidance as

to how flaws detected in CASS components should be evaluated to determine acceptability for

continued service. Therefore, the applicant should submit a procedure describing how the

detected flaws in D/QCNPS CASS valve bodies will be evaluated.

The applicant's response to this RAI is evaluated in Section 3.1.2.4.3.2 of this SER. The staff

finds the applicant's response acceptable because it is consistent with the GALL position that

the Section XI inspection requirements are sufficient for managing the effects of loss of fracture

toughness due to thermal aging embrittlement of CASS.

The applicant credited LRA Appendix B13.2, Water Chemistry Program," alone, for managing

crack initiation and growth due to SCC for "stainless steel casting" valves, filters/strainers, and

stainless steel tanks and piping and fittings in the control rod drive hydraulic system exposed to

oxygenated water up to 288 0C (550 OF). The applicant pointed out in the LRA that NUREG1801 does not address this environment for these CRD components located around CRD

housing containing CST water and that this also serves as a reactor coolant pressure boundary.

However, the staff notes in RAI 3.1-21b that Appendix B1.2 is just a mitigation program and not

a condition monitoring program, and therefore, requested the applicant to submit a program to

verify the effectiveness of the Water Chemistry Program and to assure that degradation is not

occurring. In response to RAI 3.1-21b, in a letter dated October 3, 2003, the applicant stated

that SCC occurs through the combination of high stress (both applied and residual tensile

stresses), a corrosive environment, and a susceptible material. Elimination or reduction in any

of these three factors will decrease the likelihood of SCC occurring. The control rod drive

system water is supplied by the CST. The water in the CST is monitored and controlled to keep

known detrimental contaminants below the system-specific limits indicated in the EPRI water

chemistry guidelines (TR-1 03515) to mitigate corrosion.

The applicant asserted that the Water Chemistry Program is generally effective in removing

impurities from intermediate and high flow areas. NUREG-1801 identifies circumstances in

which the water chemistry program is to be augmented to manage the effects of aging for

license renewal. For example, control of CST chemistry in accordance with EPRI guidelines

does not preclude loss of material of stainless steel at locations of stagnant flow conditions.

Accordingly, in those cases, verification of the effectiveness of the CST Chemistry Control

Program is undertaken to ensure that significant degradation is not occurring and the

component intended function will be maintained during the period of extended operation. As

discussed in NUREG-1801, an acceptable verification program is a one-time inspection of

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selected components at susceptible locations in the system. The GALL AMP B.1.23, "OneTime Inspection," requires an inspection of components exposed to CST water. An inspection

is to be conducted of stainless steel CRD components exposed to CST water to verify the

effectiveness of CST chemistry and confirm the absence of loss of material in stagnant flow

areas, as required by NUREG 1801. The references for these inspections are in LRA Table

3.1-2, Aging Management References 3.1.2.10, 3.1.2.25, 3.1.2.34, and 3.1.2.53. The applicant

asserted that the water chemistry controls that are sufficiently effective to prevent loss of

material at stagnant flow locations are also expected to be effective at preventing SCC.

The staff does not agree with the applicant that a one-time inspection for loss of material would

cover the need for a one-time inspection for cracking due to SCC because the locations

susceptible to loss of material are generally different than the locations susceptible to cracking

due'to SCC. Therefore, in Supplemental RAI 3.1-21 (b), the staff requested the applicant to

provide a one-time inspection for cracking due to SCC at the susceptible locations.

In response to Supplemental RAI 3.1-21(b),lin a letter dated November 21, 2003, the applicant

stated that the process fluid temperature in the control rod drive hydraulic system is less than

100 0F, and the typical flow conditions are either low flow (in the cooling water line) or stagnant

flow (in the charging water and drive water lines). Under these conditions, it is expected that

the stagnant flow locations that are susceptible to loss of material due' to pitting and crevice

corrosion are also the locations that may be susceptible to cracking due to SCC. In the piping

system for the control rod drive hydraulic system, where the same water chemistry applies to all

parts of the system, Exelon believes that water chemistry controls sufficient to prevent loss of

material due to pitting and crevice corrosion are also sufficient to prevent SCC. In addition, with

process temperatures below 140 0F, EPRI TR-1 003056, "Mechanical Tools, Appendix A," states

that cracking due to SSC is very unlikely to occur in the control rod drive hydraulic system.

Nonetheless, the applicant will include inspection for SCC as part of its one-time inspection to

validate the effectiveness of the Water Chemistry Program (LRA Appendix B.1.2) in managing

the aging of stainless steel components in the control rod drive hydraulic system. This is part of

Commitment #23 of Appendix A of this SER. The staff finds the response acceptable because

the control rod drive hydraulic system piping is not susceptible to cracking due to SCC because

it is exposed to a fluid temperature of 100 0F, which is less than the temperature 140 OF at

which stainless steel becomes susceptible to SCC. In addition, the applicant has committed to

perform a one-time inspection to validate the effectiveness of the Water Chemistry Program.

This is part of Commitment #23 of Appendix A of this SER.

The staff reviewed the UFSAR Supplement in Appendix A of the LRA for each of the above

seven AMPs to ensure that the program descriptions adequately describe the AMPs. No

inconsistencies were found on the basis of the above analyses as related to the pressure

boundary components in the ESF and the auxiliary and SPC systems.

All of the AMPs listed above are credited for managing the aging effects of several components

in various different structures and systems and are, therefore, considered common AMPs. The

staff has evaluated these common AMPs and found them to be acceptable for managing the

aging effects identified for this system. The staff's evaluation of these AMPs is documented in

Section 3.0 of this SER. On the basis of its review, the staff finds that the AMPs credited in the'

LRA for the reactor coolant pressure boundary components in other systems will effectively

manage or monitor the aging effects identified in the LRA.

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Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.2 Engineered Safety Features Systems

This section addresses the aging management of the components of the engineered safety

features (ESF) systems. The systems are described in the following SER sections:

* high pressure coolant injection system (Section 2.3.2.1)

* core spray system (Section 2.3.2.2)

* containment isolation components and primary containment piping system (Section 2.3.2.3)

* reactor core isolation cooling system (Quad Cities only) (Section 2.3.2.4)

* isolation condenser (Dresden only) (Section 2.3.2.5)

* residual heat removal system (Quad Cities only) (Section 2.3.2.6)

* low pressure coolant injection system (Dresden only) (Section 2.3.2.7)

* standby liquid control system (Section 2.3.2.8)

* standby gas treatment system (Section 2.3.2.9)

* automatic depressurization system (Section 2.3.2.10)

* anticipated transient without scram system (Section 2.3.2.11)

The applicant noted in LRA Section 2.3.2 that the ATWS system is not classified in the Dresden

or Quad Cities UFSARs as an ESF. However, the ATWS system is evaluated in this section

because of its similarity to other systems that are characterized as ESF systems.

As discussed in Section 3.0.1 of this SER, the components in each of these ESF systems are

rolled up into one of two LRA tables. LRA Table 3.2-1 consists of ESF system components that

are evaluated in the GALL Report, and LRA Table 3.2-2 consists of ESF system components

that are not evaluated in the GALL Report.

3.2.1 Summary of Technical Information in the Application

In LRA Section 3.2, the applicant described its AMRs for the ESF systems.

The description of the systems that comprise the ESF systems can be found in Section 2.3.2 of

the LRA.

The passive, long-lived components in these systems that are subject to an AMR are identified

in LRA Tables 2.3.2-1 through 2.3.2-11.

The applicant's AMRs included an evaluation of plant-specific and industry operating

experience. The plant-specific evaluation included reviews of condition reports and discussions

with appropriate site personnel to identify aging effects that require management. These

reviews concluded that the aging effects requiring management based on plant-specific

operating experience were consistent with aging effects identified in GALL.

The applicant's review of industry operating experience included a review of operating

experience through 2002. The results of this review concluded that aging effects requiring

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management based on industry operating experience were consistent with aging effects

identified in GALL.

The applicant's on-going review of plant-specific and industry-wide operating experience is

conducted in accordance with the Exelon's Operating Experience Program.

3.2.2 Staff Evaluation

In Section 3.2 of the LRA, the applicant described its AMR for the ESF systems. The staff

reviewed LRA Section 3.2 to determine whether the applicant has provided sufficient

information to demonstrate that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB throughout the period of

extended operation, in accordance with the requirements of 10 CFR 54.21 (a)(3), for the ESF

system components that are determined to be within the scope of license renewal and subject

toanAMR.

The applicant referenced the GALL Report in its AMR. The staff has previously evaluated the

adequacy of the aging management of ESF system components for license renewal as

documented in the GALL Report. Thus, the staff did not repeat its review of the matters

described in the GALL Report, except to ensure that the material presented in the LRA was

applicable, and to verify that the applicant had identified the appropriate programs as described

and evaluated in the GALL Report. The staff evaluated those aging management issues

recommended for further evaluation in the GALL Report. The staff also reviewed aging

management information submitted by the applicant that was different from that in the GALL

Report or was not addressed in the GALL Report. Finally, the staff reviewed the UFSAR

Supplement to ensure that it provided an adequate description of the programs credited with

managing aging for the ESF system components.

In LRA Section 3.2, the applicant provided brief descriptions of the ESF systems and

summarized the results of its AMR of the ESF systems.

Table 3.2-1 below provides a summary of the staff's evaluation of components, aging effects/

mechanisms, and AMPs listed in LRA Section 3.2 that are addressed in the GALL Report.

Table 3.2-1 Staff Evaluation for Dresden and Quad Cities Engineered Safety Features

System Components in the GALL Report

Component Group Aging AMP In GALL AMP in LRA Staff Evaluation

Effect/Mechanism Report

Piping, fittings, and Cumulative fatigue TLAA, evaluated TLAA Consistent with

valves in emergency damage in accordance with GALL GALL

core cooling system 10 CFR 54.21 (c) . . recommends further

evaluation. (See

Section 3.2.2.2.1 ._ below.)

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Component Group Aging AMP in GALL AMP in LRA Staff Evaluation

EffectlMechanism Report

Piping, fittings, Loss of material due to Water Chemistry Water Chemistry and Consistent with

pumps, and valves general corrosion and One-Time One-Time Inspection GALL, with

in emergency core Inspection Programs exception. GALL

cooling system recommends further

evaluation. (See

Sections 3.0.3.2 and

3.2.2.2.2.)

Components in Loss of material due to Plant specific Water Chemistry, Consistent with

containment spray general corrosion One-Time GALL, with

(PWR only), Inspection, Bolting exception. GALL

standby gas Integrity, and recommends further

treatment (BWR Structural Monitoring evaluation. (See

only), containment Programs Sections 3.0.3.2,

isolation, and 3.0.3.5, and

emergency core 3.2.2.2.2.)

cooling systems

Piping, fittings, Loss of material due to Water Chemistry Water Chemistry, Consistent with

pumps, and valves pitting and crevice and One-Time One-Time GALL, with

in emergency core corrosion Inspection Inspection, exception. GALL

cooling system Compressed Air recommends further

Monitoring, Bolting evaluation. (See Integrity, and Sections 3.0.3.2,

Structural Monitoring 3.0.3.5, and

_ Programs 3.2.2.2.3.)

Components in Loss of material due to Plant specific Water Chemistry, Consistent with

containment spray pitting and crevice One-Time GALL, with

(PWR only), corrosion Inspection, exception. GALL

standby gas Compressed Air recommends further

treatment (BWR Monitoring, Bolting evaluation. (See

only), containment Integrity, and Sections 3.0.3.2,

isolation, and Structural Monitoring 3.0.3.5, and

emergency core Programs 3.2.2.2.3.)

cooling systems

Containment Loss of material due to Plant specific Heat Exchanger Test Consistent with

isolation valves and microbiologically and Inspection GALL, with

associated piping influenced corrosion Activities, Water exception. GALL

Chemistry, Selective recommends further

Leaching of evaluation. (See

Materials, and Lube Sections 3.0.3.2 and

Oil Monitoring 3.2.2.2.4.)

Activities Programs

Seals in standby Changes in properties Plant specific Periodic Inspection Consistent with

gas treatment due to elastomer of Ventilation System GALL GALL

system degradation Elastomers recommends further

Programs evaluation. (See

Section 3.2.2.2.5.)

Drywell and Plugging of nozzles and Plant specific Periodic Testing of Materials used are

suppression flow orifices due to Drywell and Torus inconsistent with

chamber spray general corrosion Spray Nozzles GALL GALL

system nozzles and Programs recommends further

flow orifices evaluation. (See

Section 3.2.2.2.6.)

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Component Group Aging AMP In GALL AMP in LRA Staff Evaluation

Effect/Mechanism Report _-

Piping and fittings of Loss of fracture Thermal Aging N/A CASS material does

CASS in emergency toughness due to Embrittlement not exist at Dresden

core cooling system thermal aging CASS and Quad Cities.

embrittlement

Components Local loss of material Open-Cycle Open-Cycle Cooling Materials used are

serviced by open- due to corrosion and/or Cooling Water Water System inconsistent with

cycle cooling buildup of deposit due to System Program GALL

system biofouling

Components Loss of material due to Closed-Cycle Closed-Cycle Materials used are

serviced by closed- general, pitting, and Cooling Water Cooling Water inconsistent with

cycle cooling crevice corrosion System System Program GALL

system _

Emergency core Wall thinning due to Flow-Accelerated Flow-Accelerated Consistent with

cooling system flow-accelerated Corrosion Corrosion Program GALL, with

valves and lines to corrosion exception. (See

and from HPCI and Section 3.2.2.2.7.)

RCIC pump turbines *

Pumps, valves, Crack initiation and Water Chemistry Water Chemistry and Consistent with

piping, and fittings growth due to SCC and and BWR Stress BWR Stress GALL, with

in emergency core IGSCC Corrosion Corrosion Cracking exception. (See

cooling systems Cracking Programs Sections 3.0.3.2,

3.2.2.1, and

3.2.2.2.8.)

Closure bolting in Loss of material due to Bolting Integrity Bolting Integrity Consistent with

high pressure or general corrosion, loss programs GALL, with

high temperature of preload due to stress exception. (See

systems relaxation, and crack Sections 3.0.3.5 and

initiation and growth due 3.2.2.1.)

to cyclic loading or SCC

3.2.2.1 Aging Management Evaluations in the GALL Report That Are Relied on for License

Renewal, Which Do Not Require Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL does not recommend further evaluation, the staff sampled

components in these groups to determine whether the plant-specific components contained in

these GALL component groups were bounded by the GALL evaluation. The staff also sampled

component groups to determine whether the applicant had properly identified those component

groups in GALL that were not applicable to its plants. The staff also identified several areas

where additional information or clarification was needed.

On the basis of its review, the staff verified the applicant's claim of consistency with the GALL

report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.2.2.2 Aging Management Evaluations in the GALL Report That Are Relied on for License

Renewal, for Which GALL Recommends Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL recommends further evaluation, the staff reviewed the applicant's

evaluation to determine whether it adequately addressed the issues for which GALL

recommended further evaluation. In addition, the staff sampled components in these groups to

determine whether the plant-specific components contained in these GALL component groups

were bounded by the GALL evaluation.

The GALL Report indicates that further evaluation should be performed for the aging effects

discussed in the following sections.

3.2.2.2.1 Cumulative Fatigue Damage

Fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in

accordance with 10 CFR 54.21 (c)(1). The staff reviewed the evaluation of this TLAA in Section

4.3 of this SER, following the guidance in Section 4.3 of the SRP-LR.

The applicant indicated that all TLAAs, including those for the Class 1 components of the ESF

systems, were evaluated in the RCS section of the LRA. The ESF systems involved in the

TLAA are high pressure coolant injection, core spray, reactor core isolation cooling, isolation

condenser, residual heat removal, low pressure coolant injection, standby liquid control, and

automatic depressurization systems. The applicant discussed the TLAA in Section 4.3 of the

LRA, "Metal Fatigue of the Reactor Vessel, Internals, and Reactor Coolant Pressure Boundary

Piping and Components." This TLAA is evaluated in Section 4.3 of this SER.

3.2.2.2.2 Loss of Material Due to General Corrosion

Loss of material due to general corrosion could occur in the pumps, valves, piping, and fittings

associated with the BWR emergency core cooling systems (ECCS) and with lines to the

suppression chamber and to the drywell and suppression chamber spray system. Since control

of primary water chemistry does not preclude loss of material due to general corrosion at

locations of stagnant flow conditions, the GALL Report recommends further evaluation of

programs to manage loss of material due to general corrosion to verify the effectiveness of the

Chemistry Control Program. A one-time inspection of select components at susceptible

locations is considered an acceptable method to determine whether an aging effect is not

occurring or an aging effect is progressing very slowly. The staff reviewed the applicant's

proposed programs to ensure that an adequate program will be in place for the management of

general corrosion of these components.

The applicant stated in LRA Section 3.2.1.1.2 that an inspection of selected components

exposed to a stagnant flow water environment will be conducted in accordance with the OneTime Inspection Program (B.1.23.). The inspection of selected components will verify the

effectiveness of the Chemistry Control Program to manage loss of material due to general

corrosion in low flow or stagnant flow areas by ensuring that significant degradation is not

occurring and the component intended function will be maintained during the extended period of

operation. The applicant stated that representative HPCI components, such as carbon steel

HPCI torus suction check valves and the HPCI booster pumps, were selected to provide typical

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samples of the aging effects seen in the ESF systems. Each will undergo a visual examination.

The staff finds the applicant's One-Time Inspection Program fulfills its purpose of verifying the

effectiveness of the Chemistry Control Program, and is acceptable. The staff's evaluation of

the Water Chemistry Program (B.1.2), including its exception to the GALL program, and OneTime Inspection Program is provided in Sections 3.0.3.2 and 3.0.3.10, respectively, of this SER.

Loss of material due to general corrosion could also occur in the drywell and suppression

chamber spray systems header and spray nozzle components, standby gas treatment system

components, containment isolation valves and associated piping, the automatic

depressurization system piping and fittings, ECCS header piping and fittings and spray nozzles,

and the external surfaces of BWR carbon steel components. The GALL Report recommends

further evaluation on a plant-specific basis to ensure that the aging effect is adequately

managed. The staff reviewed the applicant's proposed programs to ensure that an adequate

program will be in place for the management of general corrosion of these components.

The applicant stated in LRA Section 3.2.1.1.3 that an inspection in accordance with the OneTime Inspection Program (B.1.23) of SGTS ducts and components will be performed. This

One-Time Inspection Program will provide assurance that penetrating corrosion of SGTS

components is not occurring at an unacceptable rate. The inspection will consist of VT-3 visual

inspections for the presence of general corrosion in selected standby gas treatment

components.

The applicant stated that a one-time inspection will be performed for carbon steel piping most

likely to experience a loss of material in the Dresden and Quad Cities safety relief discharge

piping, Dresden and Quad Cities HPCI systems, Dresden LPCI (spray piping) system, Quad

Cities RHR (spray piping), and the Quad Cities RCIC system. The examination will consist of

four ultrasonic tests for the safety relief discharge piping and HPCI piping at the water-line area

where general, pitting, and crevice corrosion are more susceptible because of repeated wetting

and drying. An evaluation of the inspection results will be performed to determine that there is

no unacceptable loss of material for the above ECCS piping exposed to a containment

atmosphere environment (wet gas). The applicant also stated that containment isolation

barriers (penetration piping and isolation valves) will be inspected per the requirements of AMP

10 CFR Part 50, Appendix J Inspection Program (B.1.28), to verify the pressure retaining

integrity of individual penetrations.

Carbon steel components are generally susceptible to aging effects in a moisture environment,

and may thus require an AMP that requires periodic monitoring, rather than a one-time

inspection. In RAI 3.2-1 (a), the staff requested the applicant to justify the use of the One-Time

Inspection Program alone to manage the aging effects for the components covered in LRA

Table 3.2-1, Items 3.2.1.3 and 3.2.1.5. In RAI 3.2-1 (b), the staff also requested the applicant to

provide the basis for the determination of the sample size and location for inspection, and to

explain why the proposed one-time inspection of the HPCI and SR discharge piping will be

adequate to ensure that the effects of aging to the RCIC piping will be adequately managed

during the period of extended operation.

By letter dated October 3, 2003, the applicant responded to RAI 3.2-1 (a) by stating the

following.

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The one-time inspection ten-element programs associated with LRA Table 3.2-1, Items 3.2.1.3 and

3.2.1.5, contain allowances for implementing further condition monitoring contingent upon the

results of the initial inspections. For the HPCI turbine exhaust piping inspection, engineering will

determine the thickness measurement acceptance criteria prior to conducting the examinations.

Results of the examinations will be evaluated by engineering to determine a) if loss of material

aging is occurring and, if so, b) the rate at which the material is being lost. Engineering

evaluations of the test results will also c) determine the need for follow-up examinations to monitor

the progression of aging degradation, and (d) identify appropriate corrective actions to mitigate any

excessive rates of loss of material discovered. Corrective actions, if necessary, would expand to

include other components.

For the safety relief valve discharge piping inspection, any ultrasonic examinations that reveal

material loss will be documented and evaluated. The inspection results will determine the amount

and rate of corrosion at the waterline. Given the corrosion rate, the remaining life of the piping will

be calculated to determine if it is adequate for the extended period of operation. If the projected

life of the piping is insufficient for the extended period of operation, engineering will determine if

there is a need for altering the water chemistry, replacing the piping, or whether an aging

management activity is required to be put in place to manage loss of material in piping during the

license renewal period.

The inspection of the ventilation system ductwork and components will determine if penetrating

corrosion indicating a loss of material aging degradation is occurring. Results of the examinations

will be evaluated by engineering to determine a) if penetrating corrosion indicating a loss of

material aging is occurring and, if so, b) the rate at which the material is being lost. Engineering

evaluations of the examination results will also c) determine the need for follow-up examinations to

monitor the progression of aging degradation, and d) to identify appropriate corrective actions to

mitigate any excessive rates of loss of material discovered. Corrective actions, if necessary, would

expand to include other components.

Evaluations are performed for test or inspection results that do not satisfy established criteria and

a condition report is initiated to document the concern in accordance with the corrective actions

program. 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 recurrence.

The staff has reviewed the applicant's response dated October 3, 2003, and finds that the

applicant has adequately clarified all the issues raised in RAI 3.2-1 (a) regarding the use of the

One-Time Inspection Program for the carbon steel components covered by LRA Table 3.2-1,

Items 3.2.1.3 and 3.2.1.5. Based on the fact that the One-Time Inspection Program is pertinent

to the components and environments addressed in LRA Table 3.2-1, Items 3.2.1.3 and 3.2.1.5,

and that sufficient inspections will be conducted, as needed, based on initial component test

and evaluation, the staff considers the applicant's response to be acceptable.

To respond to RAI 3.2-1 (b), the applicant stated the following.

An ultrasonic examination will be conducted on the steel safety relief valve discharge piping

around the torus waterline. .. . The water level in the torus fluctuates approximately four inches

between high and low water level, subjecting the section of steel safety relief valve discharge

piping at the waterline to repeated wetting and drying. That action makes the piping more

susceptible to general pitting and crevice corrosion. The number of pipes within the total sample

population for each unit is small (five pipes per unit). Each line contains a carbon steel thermowell

and two carbon steel vacuum breakers. The sample locations chosen is representative of the

material and environmental conditions that this piping and components experience.

Dresden and Quad Cities will perform an inspection of selected components in the Dresden and

Quad Cities HPCI piping systems, Quad Cities RCIC piping systems, LPCI system (Dresden only)

(drywell and torus spray piping and components subject to a containment atmosphere

environment), and RHR system (Quad Cities only) (drywell and torus spray piping and components

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subject to a containment atmosphere environment). The inspection will consist of an examination

of a representative sample of carbon steel piping system components, including piping and fittings,

within the scope of License Renewal that are exposed to a wet gas or air environment to verify that

there is no unacceptable loss of material.

The population to be sampled includes: 1) carbon steel piping in the drywell and suppression

chamber spray headers from the closed motor-operated spray valves, up to but not including the

spray nozzles.. . , 2) HPCI and RCIC (Quad Cities only) turbine exhaust piping, 3) suppression

chamber level gauge upper stop valve. Note that there should have been references in

Table 2.3.2-1, HPCI system, and Table 2.3.2-4, RCIC system, in the Piping and Fittings

Component Group, to Aging Management References 3.2.1.3 and 3.2.1.5.

The suppression chamber level normally fluctuates approximately four inches. Within the sample

population, the HPCI and RCIC turbine exhaust piping are most likely to experience a loss of

material aging effect within this zone of fluctuation due to differential aeration. Therefore, the

inspection shall be conducted on a HPCI turbine exhaust line as a representative sample that is

the bounding loss of material condition for all piping within the systems. The containment piping

and components that are located above the waterline are subjected to a humid wetted air

environment that is less corrosive than the selected sample location. The number of pipes within

this total bounding sample population is small and the sample location chosen is representative of

the material and environmental conditions that all remaining pipes experience. The applicant

stated that the approach to this one-time inspection is similar to the approach approved in

NUREG-1769, OPeach Bottom SER, Related to the License Renewal of Peach Bottom Atomic

Power Station, Units 2 and 3," Section 3.0.3.21.1.

The staff has reviewed the applicant's responses in the above letter and finds that the applicant

has adequately addressed all the issues raised in RAI 3.2-1 (b). Specifically, the staff finds the

sample location determination methodology, as described in the applicant's response, to

adequately bound the systems and components to which Items 3.2.1.3 and 3.2.1.5 pertain.

Industry experience has indicated that environmental conditions existing at the defined sample

test locations, should result in higher rates of material loss than less severe piping

environments. The question of piping samples on the HPCI piping adequately reflecting

material loss in the RCIC system has been addressed by the applicant's response which states

that the RCIC system piping at Quad Cities will be included within the population to be sampled.

This additional information clarifies the staff's concerns over the applicant's basis for the

determination of the sample size and location for inspection and justifies why the proposed onetime inspection of the HPCI and safety relief valve discharge piping will be adequate to ensure

that the effects of aging to the RCIC piping will be adequately managed during the extended

period of operation.

As part of RAI B.1.23.2-6, the staff questioned the use of the one-time inspections to manage

aging for components in a moist air environment. In its response dated March 25, 2004, the

applicant credited the Periodic Inspection of Components Subject to Moist Environments

program to manage aging effects for selected stainless steel, carbon -steel, cast iron, aluminum,

copper, and brass and bronze components exposed to moist air environments and subject to

wetting. The staff's evaluation of the Periodic Inspection of Components Subject to Moist

Environments AMP is contained in SER section 3.0.3.18.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of loss of material due to general corrosion, as recommended in the

GALL report. Since the applicant's AMR results are otherwise consistent with the GALL report,

the staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21(a)(3).

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3.2.2.2.3 Local Loss of Material Due to Pitting and Crevice Corrosion

Local loss of material due to pitting and crevice corrosion could occur in pumps, valves, piping,

and fittings associated with BWR ECCS piping and fittings and with lines to the suppression

chamber and to the drywell and suppression chamber spray system. Since control of primary

water chemistry does not preclude loss of material due to crevice and pitting corrosion at

locations of stagnant flow conditions, the GALL Report recommends further evaluation of

programs to manage loss of material due to crevice and pitting corrosion to verify the

effectiveness of the Chemistry Control Program. A one-time inspection of select components at

susceptible locations is considered an acceptable method to determine whether an aging effect

is not occurring or an aging effect is progressing very slowly. The staff reviewed the applicant's

proposed programs to ensure that an adequate program will be in place for the management of

general corrosion of these components.

The applicant stated in LRA Section 3.2.1.1.4 that an inspection of selected components

exposed to a stagnant flow water environment will be conducted in accordance with the OneTime Inspection Program (B.1.23.). The inspection of selected components will verify the

effectiveness of the Chemistry Control Program in low flow or stagnant flow areas. The

inspections ensure that significant degradation due to pitting and crevice corrosion is not

occurring and the component intended function will be maintained during the extended period of

operation. Examinations will be conducted on components in areas where typically stagnant

flow is present but occasionally there is flow, which will cause replenishment of the oxygen

supply. Inspections will be conducted on the HPCI torus suction check valves, the HPCI

booster pumps, and the control rod drive (CRD) scram valves, which were selected to provide

typical samples of the aging effects seen in the ESF systems. The HPCI torus suction check

valves are exposed to torus water, while the carbon steel HPCI booster pumps and the'

stainless steel CRD scram valves are exposed to condensate storage tank water. Each will

undergo a visual examination. The staff finds the applicant's One-Time Inspection Program

fulfills its purpose of verifying the effectiveness of the Chemistry Control Program, and is

acceptable. The staff's evaluation of the Water Chemistry Program (B.1.2), including its

exception to the GALL program, and the One-Time Inspection Program is provided in Section

3.0.3.2 and Section 3.0.3.10, respectively, of this SER.

Local loss of material from pitting and crevice corrosion could also occur in the containment

isolation valves and associated piping, and automatic depressurization system piping and

fittings. The GALL Report recommends further evaluation to ensure that the aging effect is

adequately managed. The staff reviewed the applicant's proposed programs to ensure that an

adequate program will be in place for the management of local loss of material due to pitting

and crevice corrosion of these components.

The applicant stated in LRA Section 3.2.1.1.5 that an inspection, in accordance with the OneTime Inspection Program (B.1.23), will be performed for carbon steel piping most likely to

experience a loss of material in the Dresden and Quad Cities safety relief discharge piping,

Dresden and Quad Cities HPCI systems, Dresden LPCI (spray piping) system, Quad Cities

RHR (spray piping), and the Quad Cities RCIC system that are exposed to a containment

atmosphere environment (wet gas). The safety relief discharge piping at Dresden and Quad

Cities is carbon steel. The water level in the suppression chamber fluctuates, subjecting the

section of safety relief discharge piping, HPCI piping, and RCIC piping at the water line to

repeated wetting and drying, and therefore making it more susceptible to general, pitting, and

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crevice corrosion in that area. The examination will consist of four ultrasonic tests to detect

reduction in wall thickness due to loss of material on the inside of the safety relief discharge

and HPCI piping at the water line. An evaluation of the inspection results will be performed to

determine that there is no unacceptable loss of material for the selected piping in the above

ECCS piping and components exposed to a containment atmosphere environment (wet gas).

In addition, containment isolation barriers (penetration piping and isolation valves) will be

inspected per the requirements of AMP 10 CFR Part 50, Appendix J (B.1.28), to verify the

pressure retaining integrity of individual penetrations.

Carbon steel components are generally susceptible to aging effects in a moist environment,

and may thus require an AMP that requires periodic monitoring, rather than a one-time

inspection. The staff's request for additional information was provided in RAI 3.2-1 (a) for the

applicant to justify the use of the One-Time Inspection Program alone to manage the aging

effects for the components covered in LRA Table 3.2-1, Items 3.2.1.3 and 3.2.1.5. The staff's

request for additional information was also provided in RAI 3.2-1 (b) for the applicant to provide

the basis for the determination of the sample size and location for inspection, and to explain

why the proposed one-time inspection of the HPCI and safety relief valve discharge piping will

be adequate to ensure that the effects of aging to the RCIC piping will be adequately managed

during the extended operation. The staff's discussion of these RAls and their resolution by the

applicant are provided in Section 3.2.2.2.2 of this SER.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of loss of material due to pitting and crevice corrosion, as recommended

in the GALL report. Since the applicant's AMR results are otherwise consistent with the GALL

report, the staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.2.2.2.4 Local Loss of Material Due to Microbiologically Influenced Corrosion

Local loss of material due to microbiologically influenced corrosion (MIC) could occur in BWR

containment isolation valves and associated piping in systems that are not addressed in other

chapters of the GALL Report. The GALL Report recommends further evaluation to ensure that

the aging effect is adequately managed. The staff reviewed the applicant's proposed programs

to ensure that an adequate program will be in place for the management of local loss of

material due to MIC of the containment isolation barriers.

The applicant stated in LRA Section 3.2.1.1.6 that management of aging due to local loss of

material resulting from MIC in the drywell equipment drain sump and drywell floor drain sump

containment isolation barriers is performed in accordance with AMP 10 CFR Part 50, Appendix

J (B.1.28). No other containment isolation barriers are subject to loss of material due to MIC or

biofouling. The staff's evaluation of this AMP is provided in Section 3.0.3.13 of this SER.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of local loss of material due to MIC, as recommended in the GALL

report. Since the applicant's AMR results are otherwise consistent with the GALL report, the

staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.2.2.2.5 Changes in Properties Due to Elastomer Degradation

Changes in properties due to elastomer degradation could occur in seals associated with the

SGTS ductwork and filters. The GALL Report recommends further evaluation to ensure that

the aging effect is adequately managed. The staff reviewed the applicant's proposed program

to ensure that an adequate program will be in place for the management of changes in

properties due to elastomer degradation.

The applicant stated in LRA Section 3.2.1.1.7 that aging management of SGTS elastomers will

be performed by the periodic inspection of ventilation system elastomers in accordance with the

plant-specific AMP, Periodic Inspection of Ventilation System Elastomers Program (B.2.3). The

staff's evaluation of this AMP is provided in Section 3.0.3.17 of this SER.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of changes in properties due to elastomer degradation, as

recommended in the GALL report. Since the applicant's AMR results are otherwise consistent

with the GALL report, the staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.2.2.2.6 Buildup of Deposits Due to Corrosion

The plugging of components due to general corrosion could occur in the spray nozzles and flow

orifices of the drywell and suppression chamber spray system. This aging mechanism and

effect will apply since the spray nozzles and flow orifices are occasionally wetted, even though

the majority of the time this system is on standby. The wetting and drying of these components

can aid in the acceleration of this particular corrosion. The GALL Report recommends further

evaluation to ensure that the aging effect is adequately managed. The staff reviewed the

applicant's proposed programs to ensure that an adequate program will be in place to manage

this aging effect.

The GALL Report specifies carbon steel material for the drywell and suppression chamber

spray system nozzles and flow orifices. In LRA Table 3.2-1, Item 3.2.1.8, the applicant stated

that Dresden and Quad Cities have brass/bronze spray nozzles, without providing the plantspecific AMR results for the components. In RAI 3.2-4, the staff requested the applicant to

identify the requested AMR links for the components. By letter dated October 3, 2003, the

applicant stated that neither drywell nor suppression chamber spray loops contain flow orifices.

As such, the material and environment combination specified in Item 3.2.1.8 could not be

credited. The applicant also stated that non-NUREG-1801 AMR links in LRA Table 3.2-2, Items

3.2.2.12 and 3.2.2.78, were created for the external and internal environments of the Dresden

and Quad Cities brass/bronze spray nozzles.

The applicant further stated that the spray nozzles are included in LRA Table 2.3.2-6, for the

RHR system, under the component group "spray nozzles (Quad Cities only)," and in Table

2.3.2-7, for LPCI system, under component group "spray nozzles (Dresden only)." Both tables

provide AMR links, Items 3.2.2.12 and 3.2.2.78, for the line items with a 'pressure boundary"

component intended function, and an AMR link of 3.2.2.78 for line items with a "spray"

component intended function. Based on the additional information provided above in the letter

of October 3, 2003, the staff found that no aging effect was identified for the external

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environment of the spray nozzles because the containment nitrogen environment is not

conducive to promoting aging degradation. For the internal environment, the applicant will use

the plant-specific Periodic Testing of Drywell and Torus Spray Nozzles Program (B.2.4) to

manage the plugging general corrosion of spray nozzles. The staff finds the applicant's

response adequately addresses the staff's concerns on the AMR of the Dresden/Quad Cities

spray nozzles, and is acceptable. The staff evaluation of the plant-specific Periodic Testing of

Drywell and Torus Spray Nozzles Program is provided in Section 3.2.2.3.1 of this SER.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of buildup of deposits due tobcorrosion, as recommended in the GALL

report. Since the applicant's AMR results are otherwisebconsistent with the GALL report, the

staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.2.2.2.7 Exception to GALL for Wall Thinning Due to Flow-Accelerated Corrosion

The applicant stated in LRA Section 3.2.1.2.1 that flow-accelerated corrosion is an applicable

aging mechanism for the Quad Cities HPCI steam line drains. However, carbon steel

components in the ATWS, isolation condenser, core spray, LPCI (Dresden only), RHR (Quad

Cities only), primary containment and suppression pool piping, HPCI (except as previously

noted), and RCIC (Quad Cities only) systems are not susceptible to flow-accelerated corrosion

and do not require aging management. This exception is based on the following.

* EPRI NSAC-202L-R2, "Recommendations for an Effective Flow-Accelerated Corrosion

Program," allows an exclusion from flow-accelerated corrosion for systems that operate less

than 2 percent of plant operating time.

* EPRI TR-1 14882, "Non-Class 1 Mechanical Implementation Guideline and Mechanical

Tools," states that flow rates less than 6 ft/sec do not need to be considered for flow

accelerated corrosion.

* NUREG-1557, "Summary of Technical Information and Agreements from Nuclear

Management and Resources Council Industry Reports Addressing License Renewal," states

that erosion/corrosion in HPCI and the RCIC turbine steam supply piping is nonsignificant

due to the low flow range.

* Dresden and Quad Cities operate these systems less than 2 percent of plant operating time

or at flow rates of less than 6 ft/sec. Additionally, plant experience has not revealed flowaccelerated corrosion in these lines.

On the basis of its review, the staff finds that the applicant has presented adequate bases for

excluding consideration of flow-accelerated corrosion, as an aging mechanism, for the abovementioned ESF carbon steel components. This conclusion is based on the industry guidance

on the material erosion/corrosion for piping under the conditions of infrequent and slow rates of

flow. It is also based on the fact that Dresden and Quad Cities operate these systems at less

than 2 percent of plant operating time or at flow rates of less than 6 ft/sec, both bounded by the

industry guidelines. In addition, plant-specific operating experience has not revealed flow3-187
accelerated corrosion in these lines. Based on the above, the exception to GALL flowaccelerated corrosion for the identified ESF lines is acceptable.

3.2.2.2.8 Exception to GALL for Crack Initiation and Growth Due to Stress Corrosion Cracking

and Intergranular Stress Corrosion Cracking

In LRA Section 3.2.1.2.2, the applicant stated that GALL AMP XI.M7, "BWR Stress Corrosion

Cracking," does not apply to the segments of ECCS systems which are stainless steel and

contain torus water. EPRI TR-1003056, 'Mechanical Tools," Appendix A, states that cracking

due to SCC and IGSCC is not likely in a high purity environment below 200 "F. NUREG-1 801

Program XL.M7 applies to piping that contains reactor coolant at a temperature above 200 "F.

The ECCS piping that contains torus water does not reach this level of temperature. Therefore,

XI.M7 does not apply. The applicant stated that the Water Chemistry Program alone will

manage aging due to cracking by controlling chloride and sulfate contaminants. The staff finds

the applicant's basis of taking exception to the GALL program to be acceptable for the above

ECCS piping since it is in accordance with the general industry practice.

On the basis of its review, the staff finds that the applicant has presented adequate bases for

excluding consideration of crack initiation and growth due to SCC and ISCC, as an aging

mechanism, for the above-mentioned ECCS stainless steel components. This conclusion is

based on the industry guidance on the material cracking for piping under the conditions of a

high purity environment below 200 'F. Based on the above, the exception to GALL crack

initiation and growth for the identified ECCS system segments is acceptable.

3.2.2.3 Aging Management Programs for ESF System Components

In SER Section 3.2.2.1, the staff evaluated the applicant's conformance with the aging

management recommended by GALL for ESF system components. In SER Section 3.2.2.2,

the staff reviewed the applicant's evaluation of the issues for which GALL recommends further

evaluation. In this SER section, the staff presents its evaluation of the programs used by the

applicant to manage the aging of the component groups within the ESF systems.

The applicant credits 17 AMPs to manage the aging effects associated with components in the

ESF systems. All but one AMP are credited to manage aging for components in other system

groups (common AMPs). The staff's evaluation of the common AMPs credited with managing

aging effects in ESF system components are provided in Section 3.0.3 of this SER. The

common AMPs are listed as follows:

* Inservice Inspection Program (Section 3.0.3.1)

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* Open-Cycle Cooling Water System Program (Section 3.0.3.6)

* Closed-Cycle Cooling Water System Program (Section 3.0.3.7)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* Selective Leaching of Materials Program (Section 3.0.3.11)

* Buried Piping and Tanks Inspection Program (Section 3.0.3.12)

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* 10 CFR Part 50, Appendix J Inspection Program (Section 3.0.3.13)

* Structures Monitoring Program (Section 3.0.3.14)

* Heat Exchanger Test and Inspection Activities (Section 3.0.3.15)

* Lubricating Oil Monitoring Activities (Section 3.0.3.16)

* Periodic Inspection of Ventilation Elastomers Program (Section 3.0.3.17)

The staff's evaluation of the ESF system-specific AMP, the Periodic Testing of Drywell and

Torus Spray Nozzles Program, is provided below.

3.2.2.3.1 Periodic Testing of Drywell and Torus Spray Nozzles Program

Summary of Technical Information in the Application. The applicant described its Periodic

Testing of Drywell and Torus Spray Nozzles program in Section B.2.4 of Appendix B to the

Application. The applicant stated that the program is not consistent with a GALL report

program; therefore, the applicant summarized the program in terms of the 10-element program

as described in Branch Technical Position, Appendix A of the SRP-LR.

The applicant stated that the program addresses a NUREG-1 801 Section V.D2.5 concern that

flow orifices and spray nozzles in the drywell and torus spray subsystems are subject to

plugging by rust from carbon steel piping components. The Dresden and Quad Cities drywell

and torus spray nozzles are made of bronze. .There are no carbon steel flow orifices in the

system piping, within the scope of license renewal. However, upstream carbon steel piping is

subject to possible general corrosion. These periodic tests use approved plant procedures to

verify that the drywell and torus spray nozzles are free from plugging that could result from

corrosion product buildup from upstream sources.

The applicant concluded that the periodic drywell and torus spray nozzle flow tests effectively

manage drywell and torus spray header and spray nozzle plugging by corrosion products and

that the program provides reasonable assurance that intended functions are maintained

consistent with the current licensing basis during the period of extended operation.

Staff Evaluation. In LRA Section B.2.4, "Periodic Testing of Drywell and Torus Spray Nozzles,"

the applicant described its AMP to verify that the drywell and torus spray nozzles are free from

plugging that could result from corrosion product buildup from upstream sources. The staff

reviewed this program using the guidance in Branch Technical Position RLSB-1 in Appendix A

of the SRP-LR and focused on how the program manages aging effects through the effective

incorporation of the following 10 elements: program scope, preventive actions, parameters

monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria,

corrective actions, confirmation process, administrative controls, and operating experience.

The applicant indicated that the corrective actions, confirmation process, and administrative

controls are part of the site-controlled Quality Assurance Program. The staff's evaluation of the

Quality Assurance Program is provided separately in Section 3.0.4 of this SER. The remaining

seven elements are discussed below. The staff also reviewed the UFSAR supplement to

determine whether it provides an adequate description of the program.

[Program Scope] The applicant stated that the scope of testing include the drywell and torus

spray nozzles. Although there are no carbon steel-flow orifices in the system piping which are

within the scope of license renewal, upstream carbon steel piping is subject to possible general

corrosion. These periodic tests, therefore, use approved plant procedures to verify that the

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drywell and torus spray nozzles are free from plugging that could result from corrosion product

buildup from upstream sources. The staff considers the scope of the AMR activity covered by

the program to be clearly defined, and therefore, acceptable.

[Preventive Actions] The applicant stated that the spray nozzle tests do not provide any

preventive actions. The spray nozzle tests provide condition monitoring to detect the

degradation prior to a loss of function.

[Parameters Monitored/inspected] The applicant stated that the flow tests demonstrate that the

drywell and torus spray nozzles are not blocked by debris or corrosion products, and thereby

demonstrate that the nozzles are available to provide the drywell and torus steam quenching

functions. Drywell nozzles are tested with compressed air; torus nozzles are tested with water.

Test procedures require that flow be demonstrated through each individual nozzle. The staff

finds the parameters used to potentially detect material degradation of the nozzles are

consistent with general industry experience, and are acceptable.

[Detection of Aging Effects] The applicant stated that the periodic drywell and torus spray

nozzle flow tests detect plugging by corrosion products from the degradation of carbon steel

piping and fittings. In LRA Section 8.2.4, the applicant stated that drywell nozzles are tested

with compressed air, and torus nozzles are tested with water to verify that the drywell and torus

spray nozzles are free from plugging that could result from corrosion product buildup from

upstream carbon steel piping. In RAI B.2.4(c), the staff requested the applicant to explain how

the flow tests will reveal the degree of component degradation due to general corrosion, and

how general corrosion for the upstream carbon steel piping will be adequately managed. By

letter dated October 3, 2003, the applicant stated that the flow tests will not reveal the degree of

spray nozzle degradation due to general corrosion of the nozzles since the nozzle material is

not related to the aging effect of plugging. Repeated wetting and drying of carbon steel spray

header piping upstream can, however, result in corrosion buildup (crud) that may break free

from the pipe wall and lodge in a nozzle. The applicant stated that the AMR link, Item 3.2.2.78,

is used as the AMR reference for the spray nozzles, and that Item 3.2.2.78 should have listed

an aging effect/mechanism of "Plugging of Spray Nozzles/Crud." The applicant also stated that

the aging effect of loss of material due to general corrosion for the upstream carbon steel piping

is addressed in LRA Table 3.2-1, Item 3.2.1.3. The staff finds that the applicant's responses

address the staff's concerns regarding detection of material degradation by the proposed flow

tests, and the management of upstream carbon steel piping. These are acceptable to the staff.

[Monitoring and Trending] The applicant stated that the results of the spray nozzle tests are

monitored but are not trended. If flow to a nozzle is blocked or restricted, the degraded

condition is evaluated and corrective actions are taken to restore normal flow. The applicant

did not specify in LRA Section B.2.4 the frequency of the testing and/or monitoring. In RAI

B.2.4(a), the staff requested that the applicant provide this additional information. By letter

dated October 3, 2003, the applicant stated that both the Quad Cities and Dresden Technical

Specification Surveillance Requirement SR 3.6.2.4.2 requires that the suppression pool spray

nozzles be verified as unobstructed every 10 years. Both the Quad Cities and Dresden

Technical Requirements Manual Surveillance Requirement TSR 3.6.a.2 requires that each

drywell spray nozzle be verified as unobstructed every 10 years. The staff considers the abovestated frequency of testing to be acceptable in detecting degradation in performance due to the

passive nozzle design and due to the fact that it has been shown to be acceptable through

operating experience.

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[Acceptance Criteria] The applicant stated that the test procedures contain acceptance criteria

that require that flow be observed from and through each individual drywell and torus spray

nozzle. This test procedure is to provide assurance that flow to the drywell and torus spray

headers and spray nozzles is not blocked or restricted. The applicant did not provide sufficient

details for the acceptance criteria in LRA Section B.2.4. In RAI B.2.4(b), the staff requested the

applicant to elaborate on the acceptance criteria, including the definition of an acceptable flow.

By letter dated October 3, 2003, the applicant stated its acceptance criteria as described in

Dresden procedure DOS 1500-14, "LPCI Torus Spray Test," such that "water flow is detectable

from each individual suppression pool spray nozzle." QCTS 0320-02, "Suppression Chamber

Spray Header and Nozzle Water Spray Test," acceptance criteria is that "adequate flow is

observed from all spray nozzles in RHR A and RHR B loops." The Quad Cities and Dresden

technical specification surveillance requirement will also be used to verify that each suppression

pool spray nozzle is unobstructed.

For the drywell spray nozzles, the applicant stated that Dresden procedure DTS 1500-3, "LPCI

Containment Spray Test," acceptance criteria is that "air flow is detectable from each individual

drywell spray nozzle." QCTS 0320-03, "Drywell Spray Header and Nozzle Air Test,"

acceptance criteria is that there is "sufficient flow through all spray header nozzles." The Quad

Cities and Dresden technical requirements manual surveillance requirement will also be used to

verify that each drywell spray nozzle is unobstructed by performance of an air or smoke flow

test of the drywell spray nozzles. The applicant further stated that both DTS 1500-03 and

QCTS 0320-03 specify the use of a remote sensing device, such as a smoke tube, to verify air

flow from all spray nozzles.

The staff finds that the applicant has a documented description of the acceptance criteria in

place, which are found to be sufficient in defining what constitutes an acceptable nozzle test.

This is acceptable to the staff.

[Operating Experience] The applicant stated that Dresden has not detected any degradation of

the drywell and torus spray headers or spray nozzles. Quad Cities has experienced two events

in which foreign material was found in the spray nozzles. In 1998, small amounts of rust were

found in some nozzles after a flow test. However, the small amounts of rust found did not pose

a blockage problem. In 2000, a 1" x 3" block of wood was found lodged in a spray nozzle

subsequent to a spray test, but this was a foreign material exclusion problem unrelated to

aging. No rust was found in the spray nozzles during the 2000 test. In RAI B.2.4(d), the staff

requested the applicant to discuss corrective actions that have been taken (i.e., procedural

controls) to avoid the recurrence of the above event. By letter dated October 3, 2003, the

applicant stated that in Condition Report Q2000-00355, the cause was determined to be

improper past foreign material exclusion (FME) controls. The applicant stated that this event,

along with several others, was reviewed at a Mechanical Maintenance Department weekly

meeting. In addition, an evaluation of past operability was performed that concluded that

operability was not impacted by the material that was discovered in the nozzle.

Based on the actions taken by the applicant to prevent recurrence of the event, the staff finds

the Dresden and Quad Cities operating experience demonstrates that the periodic flow tests

effectively manage drywell and torus spray header and spray nozzle plugging by corrosion

products, so that the intended function of providing a quenching spray will be maintained during

the period of extended operation.

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The applicant provided its UFSAR Supplement for the Periodic Testing of Drywell and Torus

Spray Nozzles Program in Section A.2.4 ofthe LRA. The staff reviewed the UFSAR

Supplement and finds that the summary description contains a sufficient level of information to

satisfy 10 CFR 54.21 (d), and is acceptable.

Conclusions. On the basis of its review of the applicant's program, the staff finds that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.2.2.4 Aging Management Review of Plant-Specific Engineered Safety Features Systems

Components

In this section of the SER, the staff presents its review of the applicant's AMR for the specific

components within the ESF systems. To perform its evaluation, the staff reviewed the

components listed in LRA Tables 2.3.2-1 through 2.3.2-11 to determine whether the applicant

had properly identified the applicable aging effects and the AMPs needed to adequately

manage these aging effects. This portion of the staff's review involved identification of the

aging effects for each ESF component, ensuring that each aging effect was evaluated in the

appropriate LRA AMR table in Section 3, and that management of the aging effect was

captured in the appropriate AMP. The results of the staff's review are provided below.

3.2.2.4.1 High-Pressure Coolant Injection System

Summary of Technical Information in the Application. The description of the HPCI system can

be found in Section 2.3.2.1 of this SER. The passive, long-lived components in this system that

are subject to an AMR are identified in LRA Table 2.3.2-1. The components, aging effects, and

AMPs are provided in LRA Tables 3.2-1 and 3.2-2.

Aging Effects

Components of the HPCI system are described in LRA Section 2.3.2.1 as being within the

scope of license renewal and subject to an AMR. Table 2.3.2-1 of the LRA lists individual

components of the system including closure bolting, dampeners, filters/strainers, NSR vents or

drains, piping and fittings, pumps, restricting orifices, sight glasses, thermowells, tubing, valves,

diffusers, flexible hoses, flow orifices, heat exchangers, rupture disc, tanks, traps, and turbine

casings.

Low-alloy steel components exposed to containment nitrogen are identified as being subject to

crack initiation and growth from cyclic loading and loss of material due to wear. Low-alloy steel

components exposed to air, moisture, humidity, and leaking fluid are identified as being subject

to loss of material due to general corrosion, as well as crack initiation and growth due to cyclic

loading stress-corrosion cracking. Low-alloy steel components exposed to outdoor ambient

conditions are identified as being subject to loss of material due to general corrosion and wear.

Stainless steel, carbon steel, brass, bronze exposed to air, moisture, humidity, and leaking fluid

are identified as being subject to loss of material due to corrosion.

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Carbon steel components exposed to 25-288 0C (77-550 0F) demineralized water, air or

288 0C (550 OF) steam, or air and steam up to 320 0C (608 OF) (primarily steam) are identified

as being subject to loss of material due to general, pitting, and crevice corrosion. Carbon steel

components exposed to 288 'C (550 'F) reactor coolant water, or 320 0C (608 OF) steam are

identified as being subject to wall thinning due to flow-accelerated corrosion. Carbon steel

components exposed to lubricating oil (with contaminants and/or moisture) or air are identified

as being subject to loss of material due to general, galvanic, pitting, and crevice corrosion.

Carbon steel casting exposed to 25-288 0C (77-550 OF) demineralized water is identified as

being subject to wall thinning due to flow-accelerated corrosion. Carbon steel casting and

carbon steel forging exposed to 25-288 0C (77-550 OF) demineralized water are identified as

being subject to loss of material due to general, pitting, and crevice corrosion.

Stainless steel components exposed to 25-288 0C (77-550 0F) demineralized water, 288 0C

(550 OF) reactor coolant water, or air and steam up to 320 0C (608 OF) (primarily steam) are

identified as being subject to crack initiation and growth due to stress corrosion cracking and

intergranular stress-corrosion cracking. Stainless steel components exposed to air and

saturated air, air and steam up to 320 0C (608 'F) (primarily air), or lubricating oil (with

contaminants and/or moisture) are identified as being subject to loss of material due to pitting

and crevice corrosion. Stainless steel components exposed to air and steam up to 320 0C

(608 0F) are identified as being subject to loss of material due to pitting and crevice corrosion.

Stainless steel casting and stainless steel forging exposed to 25-288 0C (77-550 0F)

demineralized water are identified as being subject to crack initiation and growth due to stresscorrosion cracking.

Aluminum exposed to 25-288 0C (77-550 OF) demineralized water is identified as being subject

to loss of material due to pitting and crevice corrosion.

Steel chrome moly exposed to 25-288 0C (77-550 °F) demineralized water is identified as

being subject to loss of material due to pitting.

Alloy steel casting exposed to air and steam up to 320 0C (608 OF) is identified as being subject

to loss of material due to general, pitting, and crevice corrosion.

Brass, bronze, and cast iron exposed to lubricating oil (with contaminants and/or moisture) are

identified as being subject to loss of material due to general, galvanic, pitting, and crevice

corrosion.

Elastomers, neoprene, and similar material exposed to lubricating oil (with contaminants and/or

moisture) or moist air are identified as being subject to hardening and loss of strength due to

elastomer degradation.

Admiralty brass tubes, brass tube sheets, carbon steel channel heads, and carbon steel shells

exposed to condensate (demineralized water) on the tube side and lubricating oil on the shell

side are identified as being subject to loss of material due to general corrosion, galvanic

corrosion, MIC, erosion or FAC, wear, and selective leaching, as well as cracking due to

mechanical fatigue and SCC. Admiralty brass tubes, carbon steel tube sheets, carbon steel

channel heads, and carbon steel shells exposed to condensate (demineralized water) on the

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tube side and reactor coolant water and warm moist air on the shell side are identified as being

subject to loss of material due to general corrosion, galvanic corrosion, MIC, erosion or FAC,

wear, selective leaching, pitting corrosion, and crevice corrosion, as well as cracking due to

mechanical fatigue and SCC. Admiralty brass exposed to condensate (demineralized water) on

the tube side and lubricating oil on the shell side, or condensate (demineralized water) on the

tube side and reactor coolant water and warm moist air on the shell side, are identified as being

subject to buildup of deposit due to fouling.

No aging effects are identified for glass exposed to 25-288 0C (77-550 0F) demineralized

water, or air and steam up to 320 0C (608 OF).

Aging Management Programs

The following AMPs are utilized to manage aging effects in the HPCI system:

* Inservice Inspection Program (Section 3.0.3.1)

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* Selective Leaching of Materials Program (Section 3.0.3.11)

* Buried Piping and Tanks Inspection Program (Section 3.0.3.12)

* Structures Monitoring Program (Section 3.0.3.14)

* Heat Exchanger Test and Inspection Activities (Section 3.0.3.15)

* Lube Oil Monitoring Program (Section 3.0.3.16)

A description of these AMPs is provided in Appendix B of the LRA. The applicant stated that

the effects of aging associated with the components of the HPCI system will be adequately

managed by these AMPs during the period of extended operation.

Staff Evaluation. Aging Effects: The staff reviewed the information in LRA Tables 2.3.2-1, 3.2-

1, and 3.2-2 for the HPCI system. During its review, the staff determined that additional

information was needed to complete its review.

The applicant identified in LRA Table 3.2-1, Items 3.2.1.3 and 3.2.1.5, loss of material due to

general corrosion and pitting/crevice corrosion, respectively, for components in standby gas

treatment, containment isolation, and emergency core cooling systems. LRA Table 2.3.2-1, for

HPCI system, and Table 2.3.2-4, for RCIC system (Quad Cities only), however, does not

provide Items 3.2.1.3 and 3.2.1.5 as the AMR links for components in the two systems. In RAI

3.2-2, the staff requested the applicant to explain why Items 3.2.1.3 and 3.2.1.5 are not

included in Tables 2.3.2-1 and 2.3.2-4 as the AMR links.

By letter dated October 3, 2003, the applicant stated the following.

LRA Table 3.2-1, Aging Management References 3.2.1.3 and 3.2.1.5, are not included in LRA

Tables 2.3.2-1 and 2.3.2-4 as aging management references because NUREG-1801, Chapter V,

does not address HPCI and RCIC carbon steel piping and fittings with an "air and steam up to 320

OC (608 OF) (primarily air)" environment and with a loss of material aging effect due to general,

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pitting, and crevice corrosion. As such, a non-NUREG-1801 aging management reference was

utilized. Table 2.3.2-1 (component group of 'Piping and Fittings (includes thermowells)") and

Table 2.3.2-4 (component group of 'Piping and Fittings (Quad Cities only) (includes rupture

discs)") refer to Aging Management Reference 3.2.2.126 for a loss of material due to pitting and

crevice corrosion. Aging Management Reference 3.2.2.126 should also have included the aging

mechanism of general corrosion.

The staff noted a contradiction in the above applicant's response. It pertains to the exclusion of

AMR links, Items 3.2.1.3 and 3.2.1.5, from LRA Tables 2.3.2-1 and 2.3.2-4, respectively, for

HPCI and RCIC carbon steel components. LRA Sections 3.2.1.1.3 and 3.2.1.1.5, which are

referenced by Items 3.2.1.3 and 3.2.1.5, respectively, provide direct references to HPCI

(covered in Table 2.3.2-1) and RCIC (covered in Table 2.3.2-4) piping and components

addressed in NUREG-1 801. In addition, the applicant's response also contradicts the response

to RAI 3.2-1(b), which specifically stated that AMR links, Items 3.2.1.3 and 3.2.1.5, should have

been provided in Tables 2.3.2-1 and 2.3.2.4, under the piping and fittings component group.

The staff requested the applicant to clarify the above inconsistencies found in its responses to

RAls 3.2-1(b) and 3.2-2. By letter dated December 12, 2003, the applicant stated that it

acknowledged the inconsistency found in its response to RAI 3.2-2, and the inconsistency

between responses to RAls 3.2-1 (b) and 3.2-2. The applicant stated that these deficiencies will

be resolved by revising LRA Tables 2.3.2-1 and 2.3.2-4 to include AMR links, Items 3.2.1.3 and

3.2.1.5, for HPCI and RCIC piping and fittings. The staff finds the applicant's response to be

acceptable and concludes that RAI 3.2-2 is closed.

The aging effects identified in the LRA for the HPCI system are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified..

Aging Management Programs

The applicant credited-the following AMPs for managing the aging effects in the HPCI system:

* Inservice Inspection Program (Section 3.0.3.1)

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* Selective Leaching of Materials Program (Section 3.0.3.11)

* Buried Piping and Tanks Inspection Program (Section 3.0.3.12)

* Structures Monitoring Program (Section 3.0.3.14)

* Heat Exchanger Test and Inspection Activities (Section 3.0.3.15)

* Lube Oil Monitoring Program (Section 3.0.3.16)

* Periodic Inspection of Components Subject to Moist Environments (Section 3.0.3.18)

As part of RAI B.1.23.2-6, the staff questioned the use of the one-time inspections to manage

aging for components in a moist air environment. In its response dated March 25, 2004, the

applicant credited the Periodic Inspection of Components Subject to Moist Environments

program to manage aging effects for stainless steel, carbon steel, cast iron, aluminum, copper,

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and brass and bronze components exposed to moist air environments and subject to wetting.

The staff's evaluation of the Periodic Inspection of Components Subject to Moist Environments

AMP is contained in SER section 3.0.3.18.

These AMPs are credited for managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. The staff has evaluated these

common AMPs and has found them to be acceptable for managing the aging effects identified

for this system.

After evaluating the applicant's AMR for each of the components in the HPCI system, the staff

evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects. For those components identified in LRA Table 3.2-1, the staff verified

that the applicant credited the AMPs recommended by the GALL Report. For the components

identified in LRA Table 3.2-2, the staff verified that the applicant credited an AMP that is

appropriate for the identified aging effect. During its review of Table 3.2-2, the staff determined

that additional information was needed to complete its review.

In LRA Table 3.2-2, Items 3.2.2.40 and 3.2.2.42, the applicant identified loss of material from

galvanic corrosion as an aging effect/mechanism for heat exchangers. The Water Chemistry

Program (B.1.2) and Heat Exchanger Test and Inspection Activities (B.2.6) were credited to

manage this component grouping, in lieu of an AMP specifically developed for the galvanic

corrosion. In RAI 3.2-3, the staff requested the applicant to provide the basis for concluding the

adequacy of the specified AMPs to manage aging effects for the HPCI heat exchangers due to

galvanic corrosion.

By letter dated October 3, 2003, the applicant stated the following.

The two Dresden and Quad Cities HPCI heat exchangers that are in scope of license renewal are

the HPCI Turbine Gland Seal Condensers and the HPCI Lubrication Oil Coolers. Aging Management Reference 3.2.2.40 addresses the HPCI Lubrication Oil Coolers, and Aging Management Reference 3.2.2.42 addresses the HPCI Turbine Gland Seal Condensers. LRA

Appendix B, B.1.2, 'Water Chemistry' and B.2.6, 'Heat Exchanger Test and Inspection Activities,"

are credited with managing the loss of material aging effect due to galvanic corrosion.

Sandia National Laboratory Report SAND93-7070 UC-523, 'Aging Management Guideline for

Commercial Nuclear Power Plants - Heat Exchangers," identifies that galvanic corrosion is not a

significant aging mechanism for the primary water (shell) side of the HPCI Turbine Gland Seal

Condensers and for the oil (shell) side of the HPCI Lubrication Oil Coolers. SAND93-7070 states

that galvanic corrosion can be significant for the tube side of both heat exchangers, which are

cooled by treated (demineralized) water. EPRI 1003056, 'Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools," Revision 3, Section 3.1.3, states that control of galvanic corrosion in treated water systems is possible by following the EPRI Chemistry Guidelines for

treated water systems. LRA Appendix B, B.1.2, "Water Chemistry," is based on EPRI Report TR103515, 'BWR Water Chemistry Guidelines."

SAND93-7070 identifies such activities as inspection, eddy current testing, and performance

testing as being effective for the detection and mitigation of galvanic corrosion. LRA Appendix B,

B.2.6, 'Heat Exchanger Test and Inspection Activities," provides for performance monitoring of the

HPCI system and visual inspection and eddy current testing of the HPCI Turbine Gland Seal

Condensers and the HPCI Lubrication Oil Coolers.

SAND93-7070 identifies that only about 1% of the total number of aging failures of heat

exchangers was attributed to galvanic corrosion, because heat exchanger design specifications

require that materials of construction be compatible and that galvanic couples between adjacent

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materials be minimized. Th6 Dresden and Quad Cities HPCI Turbine Gland Seal Condensers and the

HPCI Lubrication Oil Coolers have been previously visually inspected and eddy current tested. No failures

due to galvanic corrosion were detected.

The staff has reviewed the applicant's responses provided in the letter of October 3, 2003, and

finds that the applicant has adequately addressed all the issues raised in RAI 3.2-3. This is

based on the fact that (1) necessary techniques and evaluations are inclusive of the AMPs

utilized, (2) stringent design specifications have been required of the heat exchangers, and (3)

the plant-specific operating history has shown no failure on the heat exchangers. Therefore,

the staff finds the two accredited AMPs, Water Chemistry Program and Heat Exchanger Test

and Inspection Activities, to be adequate in managing galvanic corrosion for the heat

exchangers.

The staff's request for additional information was provided in RAI B.1.23-2 for the applicant to

justify the use of the One-Time Inspection Program alone to manage the age-related

degradation associated with components in the core spray system, or to provide an

accompanying program to monitor and/or prevent aging. The staff's discussion of this RAI and

its resolution by the applicant are provided in Section 3.0.3.10 of this SER.

In reference to the 10 CFR 54.4(a)(2) components ((a)(2) components) (i.e., non-safety-related

affecting safety-related), the applicant stated that a one-time, internal, visual inspection will be

performed for possible general, crevice, galvanic, and pitting corrosion. In RAI B.1.23-1, the

staff requested the applicant to clarify (1) if aging of (a)(2) components is managed only by the

One-Time Inspection Program or is the One-Time Inspection Program used to augment other

AMPs for these components, and (2) if any (a)(2) components are managed only by the OneTime Inspection Program, describe the aging effects and justify the use of the program alone to

manage these aging effects. By letter dated October 3, 2003, the applicant stated the

following.

For most 10 CFR 54.4(a)(2) components that have intended functions of 'Leakage Boundary

(spatial)" or "Structural Integrity (attached)," the One-Time Inspection Program does not augment

other AMPs. However, as discussed in the response to RAI B.1.23-2, an additional aging

management program is applicable for 10 CFR 54.4(a)(2) components with an environment of

Lubricating Oil in the Reactor Core Cooling Isolation System and the High Pressure Coolant

Injection System, or... . For (a)(2) components where aging is managed only by a one-time

inspection, Exelon will perform a one-time Inspection of selected (a)(2) components to determine

whether degradation, if any, caused by loss of material due to general, crevice, or pitting corrosion

is proceeding at an acceptably slow rate to ensure that the Intended function(s) of the components

is maintained during the extended period of operation. The one-time inspection will be performed

near the end of the current operating term and before the period of extended operation.

This is part of Commitment #23 of Appendix A of this SER. The staff finds the applicant's

response to RAI B.1.23-1 (1) to be acceptable, based on the staff's acceptance of the

applicant's response to RAI B.1.23-2(a).

The applicant stated that based on the material-environment combinations associated with the

10 CFR 54.4(a)(2) components, aging, if any, is expected to progress very slowly. The visual

inspections will check for indications of general,'crevice, and pitting corrosion. For materialenvironment combinations with corrosion rates such that loss of intended function due to

excessive corrosion might occur during the extended period of operation, corrective actions,

such as replacement and/or implementation of additional aging management activities, will be

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taken. The staff finds the applicant's response to RAI B.1.23-1(2) to be acceptable, based on

the staff's acceptance of the applicant's response to RAI B.1.23-2(b).

In response to the staff's concern, expressed in RAI 2.1-2, regarding the extent of the boundary

of the non-safety-related piping attached to the safety-related piping, the applicant has since

included additional piping to the scope of license renewal. The applicant stated that while

additional components have been added to the scope of license renewal for each system, the

components are comprised of the same materials and experience the same environments as

other components within the system. As such, there are no new AMPs required. For the ESF

systems, only LRA Table 2.3.2-1, for HPCI system, needed revision to include additional AMR

references. No other ESF scoping and screening tables are affected. The staff has reviewed

the revised Table 2.3.2-1, and verified that the added piping and valves to the scope of license

renewal are included in the same AMPs already applied to other components within the system.

Based on the above, the staff concluded that the applicant's response to RAI 2.1-2 is

acceptable for the ESF systems.

Based on its review of the information provided in the LRA and the applicant's responses to the

above RAls, the staff concludes that the above-identified AMPs will effectively manage the

aging effects for the components of the HPCI system and that the intended functions of the

system will remain consistent with the CLB during the period of extended operation, as required

by 10 CFR 54.21 (a)(3).

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.2.2.4.2 Core Spray System

Summary of Technical Information in the Aoplication. The description of the core spray system

can be found in Section 2.3.2.2 of this SER. The passive, long-lived components in this system

that are subject to an AMR are identified in LRA Table 2.3.2-2. The components, aging effects,

and AMPs are provided in LRA Tables 3.2-1, and 3.2-2.

Aging Effects

Components of the core spray system are described in LRA Section 2.3.2.2 as being within the

scope of license renewal and subject to an AMR. Table 2.3.2-2 of the LRA lists individual

components of the system including closure bolting, flow elements, NSR vents or drains, piping

and fittings, pumps, restricting orifices, sight glasses, thermowells, tubing, and valves.

Low-alloy steel exposed to containment nitrogen is identified as being subject to crack initiation

and growth from cyclic loading and loss of material due to wear. Low-alloy steel exposed to air,

moisture, humidity, and leaking fluid is identified as being subject to loss of material due to

general corrosion, as well as crack initiation and growth due to cyclic loading stress-corrosion

cracking.

Carbon steel exposed to air, moisture, humidity, and leaking fluid is identified as being subject

to loss of material due to corrosion. Carbon steel exposed to 25-288 0C (77-550 OF)

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demineralized water or wet gas is identified as being subject to loss of material due to general,

pitting, and crevice corrosion. Carbon steel exposed up to 225 OC (437 0F) reactor coolant

water and carbon steel casting exposed to 25-288 OC (77-550 0F) demineralized water are

identified as being subject to wall thinning due to flow-accelerated corrosion.

Carbon steel casting and carbon steel forging exposed to 25-288 'C (77-550 0F)

demineralized water are identified as being subject to loss of material due to general, pitting,-

and crevice corrosion.

Stainless steel and stainless steel forging exposed to 25-288 0C (77-550 0F) demineralized

water are identified as being subject to crack initiation and growth due to stress-corrosion

cracking. Stainless steel exposed to 25-288 0C (77-550 0F) demineralized water and 288 0C

(550 OF) reactor coolant water or steam are identified as being subject to crack initiation and

growth due to stress-corrosion cracking and intergranular stress-corrosion cracking. Stainless

steel exposed to saturated air is identified as being subject to loss of material due to pitting and

crevice corrosion. Stainless steel exposed to air, moisture, humidity, and leaking fluid is

identified as being subject to loss of material due to corrosion.

Brass and bronze exposed to air, moisture, humidity, and leaking fluid are identified as being

subject to loss of material due to corrosion.

Aging Management Programs

The following AMPs are utilized to manage aging effects in the core spray system:

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* Structures Monitoring Program (Section 3.0.3.14)

A description of these AMPs is provided in Appendix B of the LRA. The applicant stated that

the effects of aging associated with the components of the core spray system will be

adequately managed by these AMPs during the period of extended operation.

Staff Evaluation.

Aging Effects

The staff reviewed the information in LRA Tables 2.3.2-2, 3.2-1, and 3.2-2 for the core spray

system. On the basis of its review, the staff finds the applicant has identified the appropriate

aging effects for the materials and environments associated with the system.

The aging effects identified in the LRA for the core spray system are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

plausible aging effects were identified and that the aging effects listed are appropriate for the

combination of materials and environments specified.

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Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects for the core spray

system:

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* Structures Monitoring Program (Section 3.9.3.14)

* Periodic Inspection of Components Subject to Moist Environments (Section 3.0.3.18)

As part of RAI B.1.23.2-6, the staff questioned the use of the one-time inspections to manage

aging for components in a moist air environment. In its response dated March 25, 2004, the

applicant credited the Periodic Inspection of Components Subject to Moist Environments

program to manage aging effects for stainless steel, carbon steel, cast iron, aluminum, copper,

and brass and bronze components exposed to moist air environments and subject to wetting.

The staff's evaluation of the Periodic Inspection of Components Subject to Moist Environments

AMP is contained in SER section 3.0.3.18.

These AMPs are credited for managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. The staff has evaluated these

common AMPs and has found them to be acceptable for managing the aging effects identified

for this system.

After evaluating the applicant's AMR for each of the components in the core spray system, the

staff evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects. For those components identified in LRA Table 3.2-1, the staff verified

that the applicant credited the AMPs recommended by the GALL Report. For the components

identified in LRA Table 3.2-2, the staff verifies that the applicant credited an AMP that is

appropriate for the identified aging effect. During its review of Table 3.2-2, the staff determined

that additional information was needed to complete its review.

The staff's request for additional information was provided in RAI B.1.23-2 for the applicant to

justify the use of the One-Time Inspection Program alone to manage the age-related

degradation associated with components in the core spray system, or to provide an

accompanying program to monitor and/or prevent aging. The staff's discussion of this RAI and

its resolution by the applicant are provided in Section 3.0.3.10 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the core spray

system will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

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3.2.2.4.3 Containment Isolation Components and Primary Containment Piping System

Summary of Technical Information in the Application. The description of the containment

isolation components and primary containment piping system can be found in Section 2.3.2.3 of

this SER. The passive, long-lived components in this system that are subject to an AMR are

identified in LRA Table 2.3.2-3. The components, aging effects, and AMPs are provided in LRA

Tables 3.2-1 and 3.2-2.

Aging Effects

Components of the containment isolation components and primary containment piping system

are described in LRA Section 2.3.2.3 as being within the scope of license renewal and subject

to an AMR. Table 2.3.2-3 of the LRA lists individual components of the system including

closure bolting, flow elements, NSR vents or drains, piping and fittings, restricting orifices,

thermowells, tubing, valves, flexible hoses, isolation barriers, and tanks.

Low-alloy steel exposed to containment nitrogen is identified as being subject to crack initiation

and growth from cyclic loading and loss of material due to wear. Low-alloy steel exposed to air,

moisture, humidity, and leaking fluid is identified as being subject to loss of material due to

general corrosion, as well as crack initiation and growth due to cyclic loading stress-corrosion

cracking.

Carbon steel exposed to air, moisture, humidity, and leaking fluid is identified as being subject

to loss of material due to corrosion. Carbon steel occasionally exposed to moist air on the

inside surface and ambient air on the outside surface is identified as being subject to loss of

material due to general, pitting, and crevice corrosion. Carbon steel exposed to treated water

or raw water on the inside surface and ambient air on the outside surface is identified as being

subject to loss of material due to general, pitting, and crevice corrosion, MIC, and biofouling.

Carbon steel exposed to moist atmosphere (air/nitrogen), steam, or demineralized water is

identified as being subject to loss of material due to general, pitting, and crevice corrosion.

Carbon steel exposed to 25-288 0C (77-550 'F) demineralized water, or saturated air, warm

moist air, or wet gas is identified as being subject to loss of material due to general, pitting, and

crevice corrosion.

Carbon steel casting exposed to 25-288 'C (77-550 'F) demineralized water is identified as

being subject to wall thinning due to flow-accelerated corrosion. Carbon steel casting and

carbon steel forging exposed to 25-288 'C (77-550 'F) demineralized water are identified as

being subject to loss of material due to general, pitting, and crevice corrosion.

Stainless steel casting and stainless steel forging exposed to 25-288 'C (77-550 'F)

demineralized water are identified as being subject to crack initiation and growth due to stresscorrosion cracking.

Stainless steel exposed to 25-288 'C (77-550 'F) demineralized water is identified as being

subject to crack initiation and growth due to stress corrosion cracking and intergranular stresscorrosion cracking. Stainless steel exposed to warm moist air and saturated air is identified as

being subject to loss of material due to pitting and crevice corrosion. Stainless steel exposed to

air, moisture, humidity, and leaking fluid is identified as being subject to loss of material due to

corrosion.

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Brass and bronze exposed to air, moisture, humidity, and leaking fluid are identified as being

subject to loss of material due to corrosion. Brass and bronze exposed to saturated air are

identified as being subject to loss of material due to pitting and crevice corrosion.

Elastomers neoprene and similar material exposed to saturated air are identified as being

subject to hardening and loss of strength due to elastomer degradation.

Copper exposed to saturated air or warm, moist air is identified as being subject to loss of

material due to pitting and crevice corrosion.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects for the containment

isolation components and primary containment piping system:

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* 10 CFR Part 50, Appendix J Inspection Program (Section 3.0.3.13)

A description of these AMPs is provided in Appendix B of the LRA. The applicant states that

the effects of aging associated with the components of the containment isolation components

and primary containment piping system will be adequately managed by these AMPs during the

period of extended operation.

Staff Evaluation.

Aging Effects

The staff reviewed the information in LRA Tables 2.3.2-3, 3.2-1, and 3.2-2 for the containment

isolation components and primary containment piping system. On the basis of its review, the

staff finds the applicant has identified the appropriate aging effects for the materials and

environments associated with the system.

The aging effects identified in the LRA for the containment isolation components and primary

containment piping system are consistent with industry operating experience for the materials

and environments listed. The staff finds that all the plausible the aging effects were identified

and that the aging effects listed are appropriate for the combination of materials and

environments specified.

Aging Management Programs

The applicant credited the following AMPs for managing the aging effects in the containment

isolation components and primary containment piping system:

* Water Chemistry Program (Section 3.0.3.2)

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* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section (3.0.3.5)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* 10 CFR Part 50, Appendix J Inspection Program (Section 3..0.3.13)

* Periodic Inspection of Components Subject to Moist Environments (Section 3.0.3.18)

As part of RAI B.1.23.2-6, the staff questioned the use of the one-time inspections to manage

aging for components in a moist air environment. In its response dated March 25, 2004, the

applicant credited the Periodic Inspection of Components Subject to Moist Environments

program to manage aging effects for stainless steel, carbon steel, cast iron, aluminum, copper,

and brass and bronze components exp6sed to moist air environments and subject to wetting.

The staff's evaluation of the Periodic Inspection of Components Subject to Moist Environments

AMP is contained in SER section 3.0.3.18.

These AMPs are credited for managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. The staff has evaluated these

common AMPs and has found them to be acceptable for managing the aging effects identified

for this system.

After evaluating the applicant's AMR for each of the components in the containment isolationcomponents and primary containment piping system, the staff evaluated the AMPs listed above

to determine if they are appropriate for managing the identified aging effects. For those

components identified in LRA Table 3.2-1, the staff verified that the applicant credited the AMPs

recommended by the GALL Report. For the components identified in LRA Table 3.2-2, the staff

verified that the applicant credited an AMP that is appropriate for the identified aging effect.

During its review of Table 3.2-2, the staff determined that additional information was needed to

complete its review.

The staff's request for additional information was provided in RAI B.1.23-2 for the applicant to

justify the use of the One-Time Inspection Program alone to manage the age-related

degradation associated with components in the containment isolation components and primary

containment piping, or to provide an accompanying program to monitor and/or prevent aging.

The staff's discussion of this RAI and its resolution by the applicant are provided in Section

3.0.3.10 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the containment

isolation components and primary containment piping system will effectively manage or monitor

the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

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3.2.2.4.4 Reactor Core Isolation Cooling System-Quad Cities Only

Summary of Technical Information in the Application. The description of the RCIC system can

be found in Section 2.3.2.4 of this SER. The passive, long-lived components in this system that

are subject to an AMR are identified in LRA Table 2.3.2-4. The components, aging effects, and

AMPs are provided in LRA Tables 3.2-1 and 3.2-2.

Aging Effects

Components of the RCIC system are described in LRA Section 2.3.2.4 as being within the

scope of license renewal and subject to an AMR. Table 2.3.2-4 of the LRA lists individual

components of the system including closure bolting, dampeners, filters/strainers, NSR vents or

drains, piping and fittings, pumps, restricting orifices, sight glasses, tubing, valves, flexible

hoses, tanks, traps, and turbine casings.

Low-alloy steel exposed to containment nitrogen is identified as being subject to crack initiation

and growth from cyclic loading and loss of material due to wear. Low-alloy steel exposed to air,

moisture, humidity, and leaking fluid is identified as being subject to loss of material due to

general corrosion, as well as crack initiation and growth due to cyclic loading stress-corrosion

cracking.

Carbon steel exposed to air and steam up to 320 0C (608 OF) (primarily air) or air and steam up

to 320 0C (608 OF) (primarily steam) is identified as being subject to loss of material due to

pitting and crevice corrosion. Carbon steel exposed to air, moisture, humidity, and leaking fluid

is identified as being subject to loss of material due to corrosion. Carbon steel exposed to

25-288 0C (77-550 OF) demineralized water or air, or 288 OC (550 OF) steam, or air and steam

up to 320 0C (608 OF) (primarily steam), or air and steam up to 320 0C (608 OF) experiences

loss of material due to general, pitting, and crevice corrosion. Carbon steel exposed to 288 OC

(608 OF) steam is identified as experiencing wall thinning due to flow-accelerated corrosion.

Carbon steel exposed to lubricating oil (with contaminants and/or moisture) or air is subject to

loss of material due to general, galvanic, pitting, and crevice corrosion.

Carbon steel casting or carbon steel forging exposed to 25-288 'C (77-550 0F) demineralized

water is subject to wall thinning due to flow-accelerated corrosion, as well as loss of material

due to general, pitting, and crevice corrosion.

Stainless steel casting and stainless steel forging exposed to 25-288 'C (77-550 OF)

demineralized water are identified as being subject to crack initiation and growth due to stresscorrosion cracking.

Stainless steel exposed to 25-288 0C (77-550 0F) demineralized water and 288 0C (550 OF)

reactor coolant water, or air and steam up to 320 0C (608 OF) (primarily steam), is identified as

being subject to crack initiation and growth due to stress-corrosion cracking and intergranular

stress-corrosion cracking. Stainless steel exposed to saturated air, or air and steam up to

320 0C (608 OF) (primarily air), or lubricating oil (with contaminants and/or moisture) is identified

as being subject to loss of material due to pitting and crevice corrosion. Stainless steel

exposed to air, moisture, humidity, and leaking fluid is identified as being subject to loss of

material due to corrosion. Stainless steel exposed to air and steam up to 320 °C (608 °F) is

identified as being subject to loss of material due to pitting and crevice corrosion.

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Brass and bronze exposed to air, moisture, humidity, and leaking fluid are identified as being

subject to loss of material due to corrosion.

Steel chrome moly exposed to 25-288 0C (77-550 'F) demineralized water is identified as

being subject to loss of material due to pitting. No aging effects are identified for steel chrome

moly exposed to air, moisture, and humidity <100 0C (212 'F).

Cast iron exposed to lubricating oil (with contaminants and/or moisture) is identified as being

subject to loss of material due to general, galvanic, pitting, and crevice corrosion. Cast iron

exposed to 25-288 0C (77-550 0F) demineralized water is identified as being subject to loss of

material due to selective leaching. Cast iron exposed to air, moisture, and humidity <100 0C

(212 OF) is identified as being subject to loss of material due to pitting and crevice corrosion.

Alloy steel casting exposed to air and steam up to 320 OC (608 'F) is identified as being subject

to loss of material due to general, pitting, and crevice corrosion.

Elastomers, neoprene, and similar materials subjected to moist containment atmosphere

(air/nitrogen), steam, or demineralized water are identified as being subject to hardening and

loss of strength due to elastomer degradation.

No aging effects are identified for glass exposed to lubricating oil (with contaminants and/or

moisture), air, moisture, and humidity <100 0C (212 'F).

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects for the RCIC

system:

* Inservice Inspection Program (Section 3.0.3.1)

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* One-Time Inspection Program (Section 3.0.3.10)

* Selective Leaching of Materials Program (Section 3.0.3.11)

* Structures Monitoring Program (Section 3.0.3.14)

A description of these AMPs is provided in Appendix B of the LRA. The applicant states that

the effects of aging associated with the components of the RCIC system will be adequately

managed by these AMPs during the period of extended operation.

Staff Evaluation.

Aging Effects

The staff reviewed the information in LRA Tables 2.3.2-4, 3.2-1, and 3.2-2 for the RCIC system.

During its review, the staff determined that additional information was needed to complete its

review.

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The staff's request for additional information was provided in RAI 3.2-1 (a) for the applicant to

justify the use of the One-Time Inspection Program alone to manage the aging effects for the

components covered in LRA Table 3.2-1, Items 3.2.1.3 and 3.2.1.5. The staff's request for

additional information was also provided in RAI 3.2-1 (b) for the applicant to provide the basis for

the determination of the sample size and location for inspection, and to explain why the

proposed one-time inspection of the HPCI and SR discharge piping will be adequate to ensure

that the effects of aging to the RCIC piping will be adequately managed during the extended

operation. The staff's discussion of these RAls and their resolution by the applicant are

provided in Section 3.2.2.2.2 of this SER.

The staff's request for additional information was provided in RAI 3.2-2 for the applicant to

explain why the AMR links, Items 3.2.1.3. and 3.2.1.5, are not included in LRA Tables 2.3.2-1

and 2.3.2-4. The staff's discussion of this RAI and its resolution by the applicant are provided

in Section 3.2.2.4.1.2 of this SER.

The aging effects identified in the LRA for the RCIC system are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant credited the following AMPs for managing the aging effects in the RCIC system:

* Inservice Inspection Program (Section 3.0.3.1)

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* One-Time Inspection Program (Section 3.0.3.10)

* Selective Leaching of Materials Program (Section 3.0.3.1 1)

* Structures Monitoring Program (Section 3.0.3.14)

* Lubricating Oil Monitoring Program (Section 3.0.3.16)

* Periodic Inspection of Components Subject to Moist Environments Program (Section

3.0.3.18)

As part of RAI B.1.23.2-6, the staff questioned the use of the one-time inspections to manage

aging for components in a moist air environment. In its response dated March 25, 2004, the

applicant credited the Periodic Inspection of Components Subject to Moist Environments

program to manage aging effects for stainless steel, carbon steel, cast iron, aluminum, copper,

and brass and bronze components exposed to moist air environments and subject to wetting.

The staff's evaluation of the Periodic Inspection of Components Subject to Moist Environments

AMP is contained in SER section 3.0.3.18.

These AMPs are credited for managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. The staff has evaluated these

common AMPs and has found them to be acceptable for managing the aging effects identified

for the RCIC system.

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After evaluating the applicant's AMR for each of the components in the RCIC system, the staff

evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects. For those components identified in LRA Table 3.2-1, the staff verified

that the applicant credited the AMPs recommended by the GALL Report. For the components

identified in LRA Table 3.2-2, the staff verified that the applicant credited an AMP that is

appropriate for the identified aging effect. During its review of Table 3.2-2, the staff determined

that additional information was needed to complete its review.

The staff's request for additional information was provided in RAI B.1.23-2 for the applicant to

justify the use of the One-Time Inspection Program alone to manage the age-related

degradation associated with components in the RCIC system, or to provide an accompanying

program to monitor and/or prevent aging. The staff's discussion of this RAI and its resolution

by the applicant are provided in Section 3.0.3.10 of this SER.

The staff's request for additional information was provided in RAI B.1.23-1 for the applicant to

clarify and justify the use of the One-Time Inspection Program for managing the age-related

degradation of 10 CFR 54.4(a)(2) components. The staff's discussion of this RAI and its

resolution by the applicant are provided in Section 3.2.2.4.1.2 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the RCIC system

will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.2.2.4.5 Isolation Condenser-Dresden Only

Summary of Technical Information in the Application. The description of the isolation

condenser can be found in Section 2.3.2.5 of this SER. The passive, long-lived components in

this system that are subject to an AMR are identified in LRA Table 2.3.2-5. The components,

aging effects, and AMPs are provided in LRA Tables 3.2-1 and 3.2-2.

Aging Effects

Components of the isolation condenser are described in LRA Section 2.3.2.5 as being within

the scope of license renewal and subject to an AMR. Table 2.3.2-5 of the LRA lists individual

components of the system including closure bolting, flow elements, NSR vents or drains, piping

and fittings, pumps, sight glasses, thermowells, tubing, valves, isolation condensers, and tanks.

Low-alloy steel exposed to containment nitrogen is identified as being subject to crack initiation

and growth from cyclic loading and loss of material due to wear. Low-alloy steel exposed to air,

moisture, humidity, and leaking fluid is identified as being subject to loss of material due to

general corrosion, as well as crack initiation and growth due to cyclic loading stress-corrosion

cracking. Low-alloy steel exposed to outdoor ambient conditions is identified as being subject

to loss of material due to general corrosion and wear.

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Carbon steel exposed to air, moisture, humidity, and leaking fluid is identified as being subject

to loss of material due to corrosion. Carbon steel exposed to 25-288 0C (77-550 0F)

demineralized water, outdoor ambient conditions, or treated water is identified as being subject

to loss of material due to general, pitting, and crevice corrosion. No aging effects are identified

for carbon steel exposed to containment nitrogen.

Carbon steel casting and carbon steel forging exposed to 25-288 0C (77-550 OF)

demineralized water are identified as being subject to loss of material due to general, pitting,

and crevice corrosion.

Stainless steel casting exposed to 25-288 0C (77-550 0F) demineralized water is identified as

being subject to crack initiation and growth due to stress-corrosion cracking.

Stainless steel exposed to 25-288 0C (77-550 OF) demineralized water and 288 0C (550 OF)

reactor coolant water is identified as being subject to crack initiation and growth due to stresscorrosion cracking and intergranular stress-corrosion cracking. Stainless steel exposed to

288 0C (550 OF) reactor coolant water is subject to crack initiation and growth due to stresscorrosion cracking and intergranular stress-corrosion cracking due to thermal and mechanical

loading. Stainless steel exposed to saturated air is identified as being subject to loss of

material due to pitting and crevice corrosion. Stainless steel exposed to air, moisture, humidity,

and leaking fluid is identified as being subject to loss of material due to corrosion.

Brass and bronze exposed to air, moisture, humidity, and leaking fluid are identified as being

subject to loss of material due to corrosion.

Aluminum exposed to 25-288 0C (77-550 OF) demineralized water is identified as being subject

to loss of material due to pitting and crevice corrosion. Aluminum exposed to outdoor ambient

conditions is identified as being subject to loss of material due to pitting.

Stainless steel tubes, carbon steel tube sheets, stainless and carbon steel channel heads, and

carbon steel shells exposed to steam on the tube side and demineralized water on the shell

side are identified as being subject to loss of material due to general pitting and crevice

corrosion, as well as crack initiation and growth due to stress corrosion cracking and cyclic

loading. Stainless steel tubes exposed to steam on the tube side and demineralized water on

the shell side are identified as being subject to deposit buildup due to fouling.

No aging effects are identified for glass exposed to 25-288 0C (77-550 0F) demineralized

water or saturated air.

Aging Management Programs

The following AMPs are utilized to manage aging effects in the isolation condenser:

* Inservice Inspection Program (Section 3.0.3.1)

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* Compressed Air Monitoring Program (Section 3.0.3.8)

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* One-Time Inspection Program (Section 3.0.3.10)

* Structures Monitoring Program (Section 3.0.3.14)

* Heat Exchanger Test and Inspection Activities Program (Section 3.0.3.15)

A description of these AMPs is provided in Appendix B of the LRA. The applicant stated that

the effects of aging associated with the components of the isolation condenser system will be

adequately managed by these AMPs during the period of extended operation.

Staff Evaluation.

Aging Effects

The staff reviewed the information in LRA Tables 2.3.2-5, 3.2-1, and 3.2-2 for the isolation

condenser. On the basis of its review, the staff finds the applicant has identified the appropriate

aging effects for the materials and environments associated with the isolation condenser.

The aging effects identified in the LRA for the isolation condenser are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant credited the following AMPs for managing the aging effects in the isolation

condenser:

* Inservice Inspection Program (Section 3.0.3.1)

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* Structures Monitoring Program (Section 3.0.3.14)

* Heat Exchanger Test and Inspection Activities Program (Section 3.0.3.15)

These AMPs are credited for managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. The staff has evaluated these

common AMPs and has found them to be acceptable for managing the aging effects identified

for the isolation condenser.

After evaluating the applicant's AMR for each of the components in the isolation condenser, the

staff evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects. For those components identified in LRA Table 3.2-1, the staff verified

that the applicant credited the AMPs recommended by the GALL Report. For the components

identified in LRA Table 3.2-2, the staff verified that the applicant credited an AMP that is

appropriate for the identified aging effect. During its review of Table 3.2-2, the staff determined

that additional information was needed to complete its review.

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The staff's request for additional information was provided in RAI B.1.23-2 for the applicant to

justify the use of the One-Time Inspection Program alone to manage the age-related

degradation associated with components in the isolation condenser. The staff's discussion of

this RAI and its resolution by the applicant are provided in Section 3.0.3.10 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the isolation

condenser will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.2.2.4.6 Residual Heat Removal System-Quad Cities Only

Summary of Technical Information in the Application. The description of the residual heat

removal (RHR) system can be found in Section 2.3.2.6 of this SER. The passive, long-lived

components in this system that are subject to an AMR are identified in LRA Table 2.3.2-6. The

components, aging effects, and AMPs are provided in LRA Tables 3.2-1 and 3.2-2.

Aging Effects

Components of the RHR system are described in LRA Section 2.3.2.6 as being within the

scope of license renewal and subject to an AMR. Table 2.3.2-6 of the LRA lists individual

components of the system including closure bolting, dampeners, ECCS suction headers,

filters/strainers, flow elements, NSR vents or drains, piping and valves, piping and fittings,

pumps, restricting orifices, sight glasses, spray nozzles, thermowells, tubing, and valves.

Alloy steel exposed to containment nitrogen is identified as being subject to crack initiation and

growth from cyclic loading and loss of material due to wear. Low-alloy steel exposed to air,

moisture, humidity, and leaking fluid is identified as being subject to loss of material due to

general corrosion, as well as crack initiation and growth due to cyclic loading stress-corrosion

cracking.

Carbon steel exposed to air, moisture, humidity, and leaking fluid is identified as being subject

to loss of material due to corrosion. Carbon steel exposed to 25-288 0C (77-550 OF)

demineralized water or air is identified as being subject to loss of material due to general,

pitting, and crevice corrosion. Carbon steel exposed to air, moisture, and humidity <100 0C

(212 OF) is identified as being subject to loss of material due to general corrosion. Carbon steel

exposed to air or saturated air is identified as being subject to loss of material due to general

and pitting corrosion. Carbon steel exposed to air and steam up to 320 OC (608 OF) is identified

as being subject to wall thinning due to accelerated corrosion.

Carbon steel casting exposed to 25-288 0C (77-550 OF) demineralized water is identified as

being subject to wall thinning due to flow-accelerated corrosion.

Stainless steel exposed to 25-288 'C (77-550 0F) demineralized water and 288 0C (550 OF)

reactor coolant water is identified as being subject to crack initiation and growth due to stresscorrosion cracking and intergranular stress-corrosion cracking. Stainless steel exposed to air

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and saturated air is identified as being subject to loss of material due to pitting and crevice

corrosion.' Stainless steel exposed to air, moisture, humidity, and leaking fluid is identified as

being subject to loss of material due to corrosion. No aging effects are identified for stainless

steel exposed to air, moisture, and humidity where the surface is >100 0C (212 0F),

containment nitrogen, or air, moisture, and humidity <100 CC (212 IF).

Stainless steel forging exposed to 25-288 0C (77-550 0F) demineralized water is identified as

being subject to crack initiation and growth due to stress-corrosion cracking.

Brass or bronze exposed to air, moisture, humidity, and leaking fluid is identified as being

subject to loss of material due to corrosion. Brass and bronze exposed to air are identified as

being subject to plugging of flow orifices and spray nozzles due to general corrosion.

No aging effects are identified for brass, bronze, and carbon steel exposed to containment

nitrogen.

No aging effects are identified for glass exposed to 25-288 0C (77-550 OF) demineralized

water and air, moisture, and humidity <100 CC (212 0F).

Aging Management Programs

The following AMPs are utilized to manage aging effects in the RHR system:

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* Structures Monitoring Program (Section 3.0.3.14)

* Periodic Testing of Drywell and Torus Spray Nozzles (Section 3.2.2.3.1)

A description of these AMPs is provided in Appendix B of the LRA. The applicant stated that

the effects of aging associated with the components of the RHR system will be adequately

managed by these AMPs during the period of extended operation.

Staff Evaluation.

Aging Effects

The staff reviewed the information in LRA Tables 2.3.2-6, 3.2-1, and 3.2-2 for the RHR system.

During its review, the staff determined that additional information was needed to complete its

review.

The staff's request for additional information was provided in RAI 3.2-4 for the applicant to

clarify the information provided in LRA Table 3.2-1, Item 3.2.1.1, regarding the AMR of drywell

and suppression chamber spray system nozzles and flow orifices. The staff's discussion of this

RAI and its resolution by the applicant are provided in Section 3.2.2.6 of this SER.

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In LRA Table 2.3.2-6, Items 3.2.2.22, 3.2.2.23, and 3.2.2.30 were identified as AMR links for

RHR dampers (Quad Cities only), all made of stainless steel. Items 3.2.2.22 and 3.2.2.23

identify air, moisture, and humidity (<212 and >212 OF, respectively) as the external

environment, whereas air is identified as the environment for Item 3.2.2.30. In RAI 3.2-5, the

staff requested the applicant to explain the effects of the two different temperature

environments on the AMR for the dampers. The staff also requested the applicant to provide

the basis for not identifying an aging effect for Items 3.2.2.22 and 3.2.2.23, while loss of

material was identified for Item 3.2.2.30. By letter dated October 3, 2003, the applicant stated

the following.

LRA Table 3.2-2, Aging Management References 3.2.2.22 and 3.2.2.23 pertain to dampener (pulsation dampener) external surfaces. For Aging Management Reference 3.2.2.23, with an

environment of 'Air, moisture and humidity > 100 "C (212 'F)," the external surfaces of the

associated components are normally in excess of 212 OF. EPRI 1003056, 'Non-Class 1

Mechanical Implementation Guideline and Mechanical Tools," Revision 3, Appendix E, considers

212 'F as a 'threshold temperature" for all materials in an external environment since moisture

must be present (in contact with the material) for corrosion to occur. Therefore, components whose external surface temperatures are >212 OF do not require aging management of their

external surfaces.

For Aging Management Reference 3.2.2.22, the applicant stated that for Item 3.2.2.22, the

external surfaces of the associated components are in contact with the NUREG 1801 'Air,

moisture, and humidity <212 OF' environment. These general plant environmental conditions were

assumed for the majority of the NUREG 1801 and non-NUREG 1801 system piping and

component external surfaces. System piping and component materials under 212 OF exposed to

moisture and humidity were evaluated separately for their susceptibility to corrosion degradation. EPRI 1003056, Appendix E, concludes that for an indoor (air, moisture, and humidity <212 OF)

ambient environment, stainless steel that is not subjected to frequent moisture can be excluded

from further consideration.

Aging Management Reference 3.2.2.30 pertains to dampers (pulsation dampener) internal

surfaces. The 'air" environment is ambient plant air with humidity to 100% and a temperature less

than 212 "F. EPRI 1003056, Appendix D, concludes that pitting and crevice corrosion is a

concern for stainless steel in an environment with a potential for concentrating contaminants and

when the material is susceptible to becoming wetted.

The staff finds the applicant's response to be acceptable because it has provided adequate

detail related to the differences in the dampener's internal and external environmental

conditions, and the expected aging effects. Also, the explanation and supporting references

provided by the applicant related to the differences in potential aging effects, below and above

external temperatures of 212 OF, are found to be acceptable to the staff.

In LRA Table 2.3.2-6, the AMR link, 3.2.2.14, is specified for the external surfaces of carbon

steel piping and fittings (Quad Cities only), for which no aging effect was identified in a

containment nitrogen environment. In RAI 3.2-6, the staff requested the applicant to provide

justification for the determination that a containment nitrogen environment is not conducive to

promoting aging degradation. By letter dated October 3, 2003, the applicant stated the

following.

The containment nitrogen environment exists inside the drywell and in the suppression chamber

air space. These areas are made inert with nitrogen to render the primary containment

atmosphere non-flammable by maintaining the oxygen content below 4% by volume during normal

station operation. For loss of material corrosion degradation to occur, both moisture and oxygen

must be present. For containment nitrogen component external surfaces that are not in contact

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with an aqueous environment, Non-Class 1 Mechanical Implementati6n Guideline and Mechanical

Tools, Revision 3, EPRI 1003056, Appendix D, does not consider corrosion to be a concern.

The staff finds the applicant's response to be acceptable because external environmental

conditions, as stated in the applicant's response relating to the minimal oxygen and moisture

level, would not be conducive to the promotion of known aging effects. This is supported

adequately by EPRI 1003056, Appendix D, "Non-Class 1 Mechanical Implementation Guideline

and Mechanical Tools," Revision 3.

The aging effects identified in the LRA for the RHR system are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant credited the following AMPs for managing the aging effects in the RHR system:

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* Structures Monitoring Program (Section 3.0.3.14)

* Periodic Testing of Drywell and Torus Spray Nozzles Program (Section 3.2.2.3.1)

* Periodic Inspection of Components Subject to Moist Environments Program (Section

3.0.3.18)

As part of RAI B.1.23.2-6, the staff questioned the use of the one-time inspections to manage

aging for componentsjn a moist air environment. In its response dated March 25, 2004, the

applicant credited the Periodic Inspection of Components Subject to Moist Environments

program to manage aging effects for stainless steel, carbon steel, cast iron, aluminum, copper,

and brass and bronze components exposed to moist air environments and subject to wetting.

The staff's evaluation of the Periodic Inspection of Components Subject to Moist Environments

AMP is contained in SER section 3.0.3.18.

With the exception of Periodic Testing of Drywell and Torus Spray Nozzles Program, these

AMPs are credited for managing the aging effects of components in several structures and

systems and, therefore, are considered common AMPs. The staff has evaluated these

common AMPs and has found them to be acceptable for managing the aging effects identified

for this system.

After evaluating the applicant's AMR for each of the components in the RHR system, the staff

evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects. For those components identified in LRA Table 3.2-1, the staff verified

that the applicant credited the AMPs recommended by the GALL Report. For the components

identified in LRA Table 3.2-2, the staff verified that the applicant credited an AMP that is

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appropriate for the identified aging effect. During its review of Table 3.2-2, the staff determined

that additional information was needed to complete its review.

The staff's request for additional information was provided in RAI B.1.23-2 for the applicant to

justify the use of the One-Time Inspection Program alone to manage the age-related

degradation associated with components in the RHR system, or to provide an accompanying

program to monitor and/or prevent aging. The staff's discussion of this RAI and its resolution

by the applicant are provided in Section 3.0.3.10 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the RHR system

will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.2.2.4.7 Low-Pressure Coolant Injection System-Dresden Only

Summary of Technical Information in the Application. The description of the LPCI system can

be found in Section 2.3.2.7 of this SER. The passive, long-lived components in this system that

are subject to an AMR are identified in LRA Table 2.3.2-7. The components, aging effects, and

AMPs are provided in LRA Tables 3.2-1 and 3.2-2.

Aging Effects

Components of the LPCI system are described in LRA Section 2.3.2.7 as being within the

scope of license renewal and subject to an AMR. Table 2.3.2-7 of the LRA lists individual

components of the system including closure bolting, ECCS suction headers, filters/strainers,

flow elements, NSR vents or drains, piping and valves, piping and fittings, pumps, restricting

orifices, sight glasses, spray nozzles, thermowells, tubing, and valves.

Low-alloy steel exposed to air, moisture, humidity, and leaking fluid is identified as being

subject to loss of material due to general corrosion, as well as crack initiation and growth due to

cyclic loading stress-corrosion cracking. Low-alloy steel exposed to containment nitrogen is

identified as being subject to loss of material due to wear, as well as crack initiation and growth

from cyclic loading.

Carbon steel exposed to air, moisture, humidity <100 OC (212 OF), and leaking fluid is identified

as being subject to loss of material due to corrosion. Carbon steel exposed to air and steam up

to 320 0C (608 0F) is identified as being subject to wall thinning due to flow-accelerated

corrosion. Carbon steel exposed to 25-288 'C (77-550 0F) demineralized water, wet gas, or

warm moist air is identified as being subject to loss of material due to general, pitting, and

crevice corrosion.

Carbon steel casting exposed to air and steam up to 320 0C (608 OF) is identified as being

subject to wall thinning due to flow-accelerated corrosion.

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Stainless steel exposed to 25-288 OC (77-550 0F) demineralized water or 288 0C (550 °F)

reactor coolant water is identified as being subject to crack initiation and growth due to stresscorrosion cracking and intergranular stress corrosion. Stainless steel exposed to saturated air

and warm, moist air is identified as being subject to loss of material due to pitting and crevice

corrosion. Stainless steel exposed to air, moisture, humidity, and leaking fluid is identified as

being subject to loss of material due to corrosion. No aging effects are identified for stainless

steel exposed to air, moisture, and humidity <100 CC (212 OF) and containment nitrogen.

Stainless steel forging exposed to 25-288 0C (77-550 OF) demineralized water is identified as

being subject to crack initiation and growth due to stress-corrosion cracking.

Brass and bronze exposed to air, moisture, humidity, and leaking fluid is identified as being

subject to loss of material due to corrosion. Brass and bronze exposed to air are identified as

being subject to plugging of flow orifices and spray nozzles due to general corrosion. No aging effects are identified for brass exposed to containment air.

Aging Management Programs

The following AMPs are utilized to manage aging effects in the LPCI system:

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* Structures Monitoring Program (Section 3.0.3.14)

* Periodic Testing of Drywell and Torus Spray Nozzles Program (Section 3.2.2.3.1)

A description of these AMPs is provided in Appendix B of the LRA. The applicant stated that

the effects of aging associated with the components of the LPCI system will be adequately

managed by these AMPs during the period of extended operation.

Staff Evaluation.

Aging Effects

The staff reviewed the information in LRA Tables 2.3.2-7, 3.2-1, and 3.2-2 for the LPCI system.

During its review, the staff determined that additional information was needed to complete its

review.

The staff's request for additional information was provided in RAI 3.2-4 for the applicant to

clarify the information provided in LRA Table 3.2-1, Item 3.2.1.1, regarding the AMR of drywell

and suppression chamber spray system nozzles and flow orifices. The staff's discussion of this

RAI and its resolution by the applicant are provided in Section 3.2.2.6 of this SER.

The aging effects identified in the LRA for the LPCI system are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

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plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant credited the following AMPs for managing the aging effects in the LPCI system:

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* Structures Monitoring Program (Section 3.0.3.14)

* Periodic Testing of Drywell and Torus Spray Nozzles Program (Section 3.2.2.3.1)

* Periodic Inspection of Components Subject to Moist Environments Program (Section

3.0.3.18)

As part of RAI B.1.23.2-6, the staff questioned the use of the one-time inspections to manage

aging for components in a moist air environment. In its response dated March 25, 2004, the

applicant credited the Periodic Inspection of Components Subject to Moist Environments

program to manage aging effects for stainless steel, carbon steel, cast iron, aluminum, copper,

and brass and bronze components exposed to moist air environments and subject to wetting.

The staff's evaluation of the Periodic Inspection of Components Subject to Moist Environments

AMP is contained in SER section 3.0.3.18.

With the exception of the Periodic Testing of Drywell and Torus Spray Nozzles Program, these

AMPs are credited for managing the aging effects of components in several structures and

systems and, therefore, are considered common AMPs. The staff has evaluated these

common AMPs and has found them to be acceptable for managing the aging effects identified

for this system.

After evaluating the applicant's AMR for each of the components in the LPCI system, the staff

evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects. For those components identified in LRA Table 3.2-1, the staff verified

that the applicant credited the AMPs recommended by the GALL Report. For the components

identified in LRA Table 3.2-2, the staff verified that the applicant credited an AMP that is

appropriate for the identified aging effect. During its review of Table 3.2-2, the staff determined

that additional information was needed to complete its review.

The staff's request for additional information was provided in RAI B.1.23-2 for the applicant to

justify the use of the One-Time Inspection Program alone to manage the age-related

degradation associated with components in the LPCI system. The staff's discussion of this RAI

and its resolution by the applicant are provided in Section 3.0.3.10 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the LPCI system

will effectively manage or monitor the aging effects identified in the LRA.

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Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.2.2.4.8 Standby Liquid Control System

Summary of Technical Information in the ApDlication. The description of the standby liquid

control (SLC) system can be found in Section 2.3.2.8 of this SER. The passive, long-lived

components in this system that are subject to an AMR are identified in LRA Table 2.3.2-8. The

components, aging effects, and AMPs are provided in LRA Tables 3.2-1 and 3.2-2.

Aging Effects

Components of the SLC system are described in LRA Section 2.3.2.8 as being within the scope

of license renewal and subject to an AMR. Table 2.3.2-8 of the LRA lists individual components

of the system including accumulators, closure bolting, dampeners, NSR vents or drains, piping

and valves, piping and fittings, pumps, sight glasses, tanks, thermowells, tubing, and valves.

Low-alloy steel exposed to air, moisture, humidity, and leaking fluid is identified as being

subject to loss of material due to general corrosion, as well as crack initiation and growth due to

cyclic loading stress-corrosion cracking. Low-alloy steel exposed to containment nitrogen is

identified as being subject to loss of material due to wear, as well as crack initiation and growth

from cyclic loading.

Carbon steel exposed to air, moisture, humidity, and leaking fluid is identified as being subject

to loss of material due to corrosion. Carbon steel exposed to sodium pentaborate solution at

21-32 -C (70-90 0F) (24,500 ppm boron) or lubricating oil (with contaminates and/or moisture)

is identified as being subject to loss of material due to general, galvanic, pitting, and crevice

corrosion. Carbon steel exposed to treated water or oxygenated water, up to 288 0C (550 'F)

is identified as being subject to loss of material due to general pitting and crevice corrosion.

Stainless steel exposed to saturated air or sodium pentaborate solution at 21-32 0C (70-90 OF)

(24,500 ppm boron), or saturated air or oxygenated water, up to 288 OC (550 0F) is identified as

being subject to loss of material due to pitting and crevice corrosion. Stainless steel exposed to

288 0C (550 0F) reactor coolant water or steam is identified as being subject to crack initiation

and growth due to stress-corrosion cracking intergranular stress-corrosion cracking. Stainless

steel or stainless steel casting exposed to sodium pentaborate solution at 21-32 0C (70-90 OF)

(24,500 ppm boron) or oxygenated water, up to 288 OC (550 OF) is identified as being subject to

crack initiation and growth due to stress-corrosion cracking. Stainless steel exposed to air,

moisture, humidity, and leaking fluids is identified as being subject to loss of material due to

corrosion. No aging effects are identified for stainless steel exposed to containment nitrogen.

Brass and bronze exposed to air, moisture, humidity, and leaking fluids are identified as being

subject to loss of material due to corrosion.

No aging effects are identified for glass exposed to air, moisture, and humidity <100 OC

(212 OF) or sodium pentaborate solution at 21-32 0C (70-90 0F) (24,500 ppm boron).

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Aging Management Programs

The following AMPs are utilized to manage aging effects in the SLC system:

F * Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Bolting Integrity Program (Section 3.0.3.5)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

A description of these AMPs is provided in Appendix B of the LRA. The applicant stated that

the effects of aging associated with the components of the SLC system will be adequately

managed by these AMPs during the period of extended operation.

Staff Evaluation.

Aging Effects

The staff reviewed the information in LRA Tables 2.3.2-8, 3.2-1, and 3.2-2 for the SLC system.

On the basis of its review, the staff finds the applicant has identified the appropriate aging

effects for the materials and environments associated with the SLC system.

The aging effects identified in the LRA for the SLC system are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

plausible the aging effects were identified and that the aging effects listed are appropriate for

I the combination of materials and environments specified.

Aging Management Programs

The applicant credited the following AMPs for managing the aging effects in the SLC system:

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Bolting Integrity Program (Section 3.0.3.5)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.'0)

These AMPs are credited for managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. The staff has evaluated these

common AMPs and has found them to be acceptable for managing the aging effects identified

for the SLC system.

After evaluating the applicant's AMR for each of the components in the SLC system, the staff

evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects. For those components identified in LRA Table 3.2-1, the staff verified

that the applicant credited the AMPs recommended by the GALL Report. For the components

identified in LRA Table 3.2-2, the staff verified that the applicant credited an AMP that is

appropriate for the identified aging effect.

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On the basis of its review, the staff finds that the AMPs credited in the LRA for the SLC system

will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.2.2.4.9 Standby Gas Treatment System

Summary of Technical Information in the Application. The description of the standby gas

treatment (SBGT) system can be found in Section 2.3.2.9 of this SER. The passive, long-lived

components in this system that are subject to an AMR are identified in LRA Table 2.3.2-9. The

components, aging effects, and AMPs are provided in LRA Tables 3.2-1 and 3.2-2.

Aging Effects

Components of the SBGT system are described in LRA Section 2.3.2.9 as being within the

scope of license renewal and subject to an AMR. Table 2.3.2-9 of the LRA lists individual

components of the system including closure bolting, duct, doors, closure bolts, equipment

frames, fan housing, filters/strainers, flex collars, damper seals, housing and supports,

manifolds, NSR vents or drains, piping and valves, seals, tubing, and valves.

Low-alloy steel exposed to outdoor ambient air and air, moisture, and humidity <100 'C

(212 OF) is subject to loss of material due to general corrosion and wear.

Carbon steel exposed to air, moisture, humidity, and leaking fluids is identified as being subject

to loss of material due to corrosion. Carbon steel exposed to air and steam up to 320 OC

(608 OF) is identified as being subject to wall thinning due to flow-accelerated corrosion.

Carbon steel exposed internally to moist air and externally to ambient plant air environment is

identified as being subject to loss of material due to general, pitting, and crevice corrosion.

Carbon steel exposed to outdoor ambient air conditions is identified as being subject to loss of

material due to general, pitting, and crevice corrosion. Carbon steel exposed to soil and ground

water is identified as being subject to loss of material due to general, pitting, crevice, and MIC.

Stainless steel exposed internally to moist air and externally to ambient plant air environment is

identified as being subject to loss of material due to general, galvanic, pitting, and crevice

corrosion. Stainless steel exposed to air, moisture, humidity, and leaking fluid is identified as

being subject to loss of material due to corrosion

Cast iron exposed internally to moist air and externally to ambient plant air environment is

identified as being subject to loss of material due to general, galvanic, pitting, and crevice

corrosion.

Brass and bronze exposed internally to moist air and externally to ambient plant air environment

is identified as being subject to loss of material due to general, galvanic, pitting, and crevice

corrosion. Brass and bronze exposed to air, moisture, humidity, and leaking fluid are identified

as being subject to loss of material due to corrosion. Brass and bronze exposed to saturated

air are identified as being subject to loss of material due to pitting and crevice corrosion.

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Elastomers, neoprene, and similar materials exposed internally to moist air and externally to

ambient plant air environment or moist air is identified as being subject to hardening and loss of

strength.

Aging Management Programs

The following AMPs are utilized to manage aging effects in the SBGT system:

* Bolting Integrity Program (Section 3.0.3.5)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* Buried Piping and Tanks Inspection Program (Section 3.0.3.12)

A description of these AMPs is provided in Appendix B of the LRA. The applicant stated that

the effects of aging associated with the components of the SBGT system will be adequately

managed by these AMPs during the period of extended operation.

Staff Evaluation.

Aging Effects

The staff reviewed the information in LRA Tables 2.3.2-9, 3.2-1, and 3.2-2 for the SBGT

system. On the basis of its review, the staff finds the applicant has identified the appropriate

aging effects for the materials and environments associated with the SBGT system.

The aging effects identified in the LRA for the SBGT system are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant credited the following AMPs for managing the aging effects in the SBGT system:

* Bolting Integrity Program (Section 3.0.3.5)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* Buried Piping and Tanks Inspection Program (Section 3.0.3.12)

These AMPs are credited for managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. The staff has evaluated these

common AMPs and has found them to be acceptable for managing the aging effects identified

for the SBGT system.

After evaluating the applicant's AMR for each of the components in the SBGT system, the staff

evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects. For those components identified in LRA Table 3.2-1, the staff verified

that the applicant credited the AMPs recommended by the GALL Report. For the components

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identified in LRA Table 3.2-2, the staff verifies that the applicant credited an AMP that is

appropriate for the identified aging effect.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the SBGT

system will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.2.2.4.10 Automatic Depressurization System

Summary of Technical Information in the Application. The description of the automatic

depressurization system (ADS) can be found in Section 2.3.2.10 of this SER. The passive,

long-lived components in this system that are subject to an AMR are identified in LRA Table

2.3.2-10. The applicant stated that Dresden and Quad Cities design-basis documents treat the

ADS relief valves and associated piping, solenoids, pressure controllers, and position switches

as components of the main steam system. The components, aging effects, and AMPs are,

therefore, provided in LRA Tables 2.3.4-1, 3.4-1, and 3.4-2.

Aging Effects

Components of the ADS are described in LRA Sections 2.3.2.10 and 2.3.4.1 as being within the

scope of license renewal and subject to an AMR. The aging effects associated with these

mechanical components of the ADS are provided in Section 3.4.2.4.1.1 of this SER.

Aging Management Programs

The AMPs utilized to manage the identified aging effects for the ADS are provided in Section

3.4.2.4.1.1 of this SER.

Staff Evaluation.

Aging Effects

The staff reviewed the information in LRA Tables 2.3.2-10, 2.3.4-1, 3.4-1, and 3.4-2 for the

ADS. During its review, the staff determined that additional information was needed to

complete its review.

In LRA Table 3.4-2, Item 3.4.2.51, under Discussion, the applicant stated that NUREG-1801

does not address crevice and pitting corrosion of stainless steel valves in a treated water

environment. Under Aging Effect/Mechanism of Item 3.4.2.51, however, crack initiation and

growth/stress-corrosion cracking and intergranular stress-corrosion cracking are identified as

aging effects/mechanisms requiring management in a 288 'C steam environment. In RAI 3.2-

8, the staff requested that the applicant clarify whether these valves, identified in Item 3.4.2.51,

apply to the ADS system. The staff also requested the applicant to explain the above

discrepancies found and to provide the correct AMR review results.

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By letter dated October 3, 2003, the applicant stated the following.

The valves in LRA Table 3.4-2, Item 3.4.2.51, are main steam system valves in applications such

as main steam line drains, pressure switch and pressure transmitter isolation, and pressure control

valve bypass. There are no valves in this component group that apply to the ADS system. Since

the ADS system utilizes valves and other components from the main steam system, the Aging

Management References for them can be found in Table 2.3.4-1, under the Component Group of

"Valves." The specific reference for each particular valve will depend on its materials of

construction and internal environment. For example, a main steam line PORV has an internal

environment of "288 OC (550 "F) steam' and an Aging Management Reference of 3.1.1.11. The

pressure controller shutoff valve for the same PORV has an internal environment of "288 0C (550

'F) reactorcoolant water," and an Aging Management Reference of 3.1.1.15. The drywell

pneumatic air shutoff valve for the same PORV has an internal environment of 'saturated air," and

an Aging Management Reference of 3.4.2.53.

The aging effect/mechanism of 'crack initiation and growth/stress corrosion cracking and

intergranular stress corrosion cracking" and the environment of "288 'C (550 'F) steam' are

correct as stated. The text in the 'Discussion" column of the Aging Management Reference

3.4.2.51, was intended to explain why this line is a non-NUREG-1 801 item, but is inappropriate for

the attributes listed. The text should have read, 'NUREG-1 801, Chapter Vill, does not address

stainless steel components in a 550 "F steam environment.

The staff has reviewed the above aging management references provided by the applicant for

the ADS valves, and finds them acceptable because they provided adequate detail to explain

how the AMR of the ADS components is performed. The staff also finds the applicant's

response provided adequate detail to clarify the clerical error made in Aging Management

Reference 3.4.2.51, and is, therefore, acceptable.

The aging effects identified in the LRA for the ADS are consistent with industry operating

experience for the materials and environments listed. The staff finds that all the plausible the

aging effects were identified and that the aging effects listed are appropriate for the

combination of materials and environments specified.

Aging Management Programs

The staff's evaluation of the AMPs utilized to manage the aging effects for the ADS are

provided in Section 3.4.2.4.1.2 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the ADS will

effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.2.2.4.11 Anticipated Transient Without Scram System

Summary of Technical Information in the Application. The description of the anticipated

transient without scram (ATWS) system can be found in Section 2.3.2.11 of this SER. The

passive, long-lived components in this system that are subject to an AMR are identified in LRA

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Table 2.3.2-11. The components,: aging effects, and AMPs are provided in LRA Tables 3.2-1

and 3.2-2.

Aging Effects

Components of the ATWS system are described in LRA Section 2.3.2.11 as being within the

scope of license renewal and subject to an AMR. Table 2.3.2-11 of the LRA lists individual

components of the system including closure bolting, piping and fittings, and valves.

Low-alloy steel exposed to air, moisture, humidity, and leaking fluids is identified as being

subject to loss of material due to general corrosion, as well as crack initiation and growth due to

cyclic loading stress corrosion cracking.

Carbon steel exposed to air, moisture, and humidity <100 'C (212 'F) is identified as being

subject to loss of material due to general corrosion.

Carbon steel forging exposed to 25-288 cC (77-550 0F) demineralized water is identified as

being subject to loss of material due to general, pitting, and crevice corrosion. Carbon steel

forging exposed to 25-288 0C (77-550 0F) demineralized water is identified as being subject to

wall thinning due to flow-accelerated corrosion.

Stainless steel and stainless steel casting exposed to 25-288 OC (77-550 0F) demineralized

water are identified as being subject to crack initiation and growth due to stress-corrosion

cracking and intergranular stress-corrosion cracking. No aging effects are identified for

stainless steel exposed to air, moisture, and humidity <100 'C (212 'F).

Aging Management Programs

The following AMPs are utilized to manage aging effects in the ATWS system:

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* One-Time Inspection Program (Section 3.0.3.10)

A description of these AMPs is provided in Appendix B of the LRA. The applicant stated that.

the effects of aging associated with the components of the ATWS system will be adequately

managed by these AMPs during the period of extended operation.

Staff Evaluation.

Aging Effects

The staff reviewed the information in LRA Tables 2.3.2-11, 3.2-1, and 3.2-2 for the ATWS

system. During its review, the staff determined that additional information was needed to

complete its review.

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In LRA Table 2.3.2-11, Item 3.2.1.12 is identified as an AMR link for valves in the ATWS

system. The aging effect/mechanism identified for Item 3.2.1.12 is wall thinning due to flowaccelerated corrosion, with Flow-Accelerated Corrosion (B.1.1 1) identified as an AMP. The

applicant identified exceptions to flow-accelerated corrosion in LRA Section 3.2.1.2.1, where it

states the following.

Flow accelerated corrosion is an applicable aging mechanism for the Quad Cities HPCI steam line

drains. However, carbon steel components in the ATWS, isolation condenser, core spray, LPCI

(Dresden only), RHR (Quad Cities only), primary containment and suppression pool piping, HPCI

(except as previously noted) and RCIC (Quad Cities only) systems are not susceptible to flow

accelerated corrosion and do not require aging management.

In RAI 3.2-9, the staff requested that the applicant clarify the above discrepancy for the AMR of

valves in the ATWS system, and verify that the aging effect/mechanism of wall thinning due to

flow-accelerated corrosion, as addressed in Item 3.2.1.12, is applicable to the ATWS system.

By letter dated October 3, 2003, the applicant stated the following.

All of the ATWS system valves are installed in piping associated with reactor vessel pressure and

level process instrumentation. The valves are used to isolate, vent, drain, calibrate, and prepressurize these instruments. There is no flow in the process lines associated with these

instruments; therefore, wall thinning due to flow-accelerated corrosion is not an applicable aging

effect/mechanism for the ATWS system valves. This was not a discrepancy in the LRA. The

ATWS system valves are emergency core cooling system valves that have the same component

group-material-environment as in NUREG-1801, V.D2.3-a. NUREG-1801, V.D2.3-a identifies an

aging effect/mechanism of Wall thinning/Flow-accelerated corrosion." The ATWS valves were

included in the SRP line for V.D2.3-a to be in alignment with NUREG-1 801, but, since there is no

flow in the process lines associated with them, an exception was taken.

The staff finds the applicant has provided adequate information and detail related to the type,

location, and function of the ATWS system valves identified in LRA Table 2.3.2-11, Item

3.2.1.12, and has adequately explained why the conditions necessary to promote flowaccelerated corrosion do not exist at the pertinent valve locations. This is acceptable to the

staff. For more information on the exception taken by Dresden and Quad Cities on flowaccelerated corrosion, reference is made to the discussion provided in Section 3.2.2.2.7 of this

SER.

The aging effects identified in the LRA for the ATWS system are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant credited the following AMPs for managing the aging effects in the ATWS system:

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* One-Time Inspection Program (Section 3.0.3.10)

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These AMPs are credited for managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. The staff has evaluated these

common AMPs and has found them to be acceptable for managing the aging effects identified

for the ATWS system. These AMPs are evaluated in Sections 3.0.3.2, 3.0.3.3, 3.0.3.4, 3.0.3.5,

and 3.0.3.10, respectively, of this SER.

After evaluating the applicant's AMR for each of the components in the ATWS system, the staff

evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects. For those components identified in LRA Table 3.2-1, the staff verified

that the applicant credited the AMPs recommended by the GALL Report. For the components

identified in LRA Table 3.2-2, the staff verifies that the applicant credited an AMP that is

appropriate for the identified aging effect.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the ATWS

system will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.3 Auxiliary Systems

This section addresses the aging management of the components of the auxiliary systems

group. The following systems make up the auxiliary systems group and are described in this

section:

* Refueling equipment system

* Shutdown cooling system (Dresden only)

* Control rod drive hydraulic system

* Reactor water cleanup system

* Fire protection system

* Emergency diesel generator and auxiliaries system

* HVAC-Main Control Room

* HVAC-Reactor Building

* Emergency core cooling system corner room HVAC

* Station blackout building HVAC

* Station blackout system (diesels and auxiliaries)

* Diesel generator cooling water system

* Diesel fuel oil system

* Process sampling system

* Carbon dioxide system

* Service water system

* Reactor building closed cooling water system

* Turbine building closed cooling water system

* Demineralized water makeup system

* Residual heat removal service water system (Quad Cities only)

* Containment cooling service water system (Dresden only)

* Ultimate heat sink

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* Fuel pool cooling and filter demineralizer system (Dresden only)

* Plant heating system

* Containment atmosphere monitoring system

* Nitrogen containment atmosphere dilution system

* Drywell nitrogen inerting system

* Safe shutdown makeup pump system (Quad Cities only)

As discussed in Section 3.0.1 of this SER, the components in each of the systems are

described in the LRA tables. LRA Table 3.3-1 consists of auxiliary system components that are

evaluated in the GALL Report. LRA Table 3.3-2-X lists all of the components in each system,

regardless of whether they are addressed in the GALL Report. For those system components

that are addressed in the GALL Report, LRA Table 3.3-2-X refers to LRA Table 3.3-1 for

additional information.

3.3.1 Summary of Technical Information in the Application

In LRA Section 3.3, the applicant described its AMRs for the auxiliary systems group.

The description of the systems that comprise the auxiliary systems group can be found

in LRA Section 2.3.3. The passive, long-lived components in these systems that are

subject to an AMR are identified in LRA Tables 2.3.3-1 through 2.3.3-28.

The applicant's AMRs included an evaluation of plant-specific and industry operating

experience. The plant-specific evaluation included reviews of condition reports and discussions

with appropriate site personnel to identify aging effects that require management. These

reviews concluded that the aging effects requiring management, based on plant-specific

operating experience, were consistent with the aging effects identified in GALL.

The applicant's review of industry operating experience included a review of operating

experience through 2002. The results of this review concluded that the aging effects requiring

management, based on industry operating experience, were consistent with the aging effects

identified in GALL.

The applicant's ongoing review of plant-specific and industry-wide operating experience is

conducted in accordance with the Exelon Operating Experience Program.

3.3.2 Staff Evaluation

In Section 3.3 of the LRA, the applicant described its AMR for the auxiliary systems at Exelon.

The staff reviewed LRA Section 3.3 to determine whether the applicant had provided sufficient

information to demonstrate that the effects of aging will be adequately managed so that the

component intended functions will be maintained consistent with the CLB throughout the period

of extended operation, in accordance with the requirements of 10 CFR 54.21 (a)(3), for the

auxiliary system components that are determined to be within the scope of license renewal and

subject to an AMR.

The applicant referenced the GALL Report in its AMR. The staff has previously evaluated the

adequacy of the aging management of auxiliary system components for license renewal, as

documented in the GALL Report. Thus, the staff did not repeat its review of the matters

described in the GALL Report, except to ensure that the material presented in the LRA was

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applicable, and to verify that the applicant had identified the appropriate programs as described

and evaluated in the GALL Report. The staff evaluated those aging management issues

recommended for further evaluation in the GALL Report. The staff also reviewed aging

management information submitted by the applicant that was different from that in the GALL

Report or was not addressed in the GALL Report. Finally, the staff reviewed the USAR

Supplement to ensure that it provided an adequate description of the programs credited with

managing aging for the auxiliary system components.

Table 3.3-1 below provides a summary of the staff's evaluation of components, aging effects/mechanisms, and AMPs listed in LRA Section 3.3 that are addressed in the GALL

Report.

Table 3.3-1. Summary of Aging Management for Auxiliary Systems Evaluated In Chapter

VII of the GALL Report

Component Aging Effect/ AMP In GALL AMP In LRA Staff Evaluation

Group Mechanism Report

Components In spent fuel Loss of material due to Water Chemistry; One- Water Chemistry Consistent with GALL

pool cooling and cleanup general, pitting, and Time Inspection Program; One-Time with exceptions. GALL

crevice corrosion Inspection Program recommends further

evaluation (see Section

3.3.2.2.1 below).

Unings In spent fuel pool Hardening, cracking, Plant specific Periodic Inspection of Consistent with GALL

cooling and cleanup and loss of strength Ventilation System GALL recommends

system; seals and collars due to elastomer Elastomers Program further evaluation (see

In ventilation systems degradation; loss of Section 3.3.2.2.2

material due to wear below).

Components In load Cumulative fatigue TILAA, evaluated In TLAA GALL recommends

handling, chemical and damage accordance with further evaluation

volume control system 1 0 CFR 54.21 (c) (see Section 3.3.2.2.3

(PWR); reactor water below).

cleanup and shutdown

cooling systems (older

BWR)

Heat exchangers in reactor Crack initiation and Plant specific None Applicant has

water cleanup system growth due to SCC or determined that heat

(BWR); high pressure cracking exchangers in reactor

pumps in chemical and water cleanup system

volume control system (BWR) are not In scope

(PWR) of license renewal (see

Section 3.3.2.2.4

below).

Components In ventilation Loss of material due to Plant specific Bolting Integrity Consistent with GALL

systems, diesel fuel oil general, pitting, and Program; Open-Cycle with exceptions. GALL

system, and emergency crevice corrosion and Cooling Water System recommends further

diesel generator systems; MIC Program; Fire evaluation (see Section

external surfaces of Protection Program; 3.32.2.5 below).

carbon steel components Buried Piping and

Tanks Inspections

Program

Components in reactor Loss of material due to One-Time Inspection Not applicable. Not applicable.

coolant pump oil collection galvanic, general,

system pitting, and crevice

corrosion

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Component Aging Effect/ AMP In GALL AMP In LRA Staff Evaluation

Group Mechanism Report

Diesel fuel oil tanks in Loss of material due to Fuel Oil Chemistry; Fuel Oil Chemistry Consistent with GALL

diesel fuel oil system; general, pitting, and One-Time Inspection Program; One-Time with exceptions. GALL

emergency diesel crevice corrosion, MIC, Inspection Program recommends further

generator system and biofouling evaluation (see Section

3.3.2.2.7 below).

Piping, pump casing, and Loss of material due to Water Chemistry; One- Water Chemistry Consistent with GALL

valve body and bonnets in pitting and crevice Time Inspection Program; One-Time with exceptions. GALL

shutdown cooling system corrosion Inspection Program recommends further

(older BWR) evaluation (see Section

3.3.2.2.1 below).

Neutron absorbing sheets Reduction of neutron Plant specific Water Chemistry These components are

in spent fuel storage racks absorbing capacity and Program scoped under structures

loss of material due to and are addressed in

general corrosion Section 3.5.2.4.2.2 of

(Boral, boron steel) this SER.

New fuel rack assembly Loss of material due to Structures Monitoring Structures Monitoring These components are

general, pitting, and Program scoped under structures

crevice corrosion and are addressed in

Section 3.5.2.4.2.2 of

this SER.

Spent fuel storage rack Crack initiation and Water Chemistry Water Chemistry Consistent with GALL

and valves in spent fuel growth due to SCC Program (see Section 3.3.2.1

pool cooling and cleanup below).

Neutron absorbing sheets Reduction of neutron Boraflex Monitoring Boraflex Monitoring These components are

in spent fuel storage racks absorbing capacity due Program scoped under structures

to Boraflex degradation and are addressed in

Section 3.5.2.4.2.2 of

this SER.

Closure bolting and Loss of material due to Boric Acid Corrosion Not applicable The environment

external surfaces of boric acid corrosion Identified in GALL is not

carbon steel and low-alloy applicable. steel components

Components in or serviced Loss of material due to Closed-Cycle Cooling Closed-Cycle Cooling Consistent with GALL

by closed-cycle cooling general, pitting, and Water System Water System (see Section 3.3.2.1

water system crevice corrosion and Program below). MIC

Cranes, including bridge Loss of material due to Overhead Heavy Load Inspection of Overhead Consistent with GALL,

and trolleys, and rail general corrosion and and Light Load Heavy Load and Ught with exception (see

system in load handling wear Handling Systems Load (related to Section 3.3.2.1 below).

system refueling) Handling

Systems Program

Components in or serviced Loss of material due to Open-Cycle Cooling Open-Cycle Cooling Consistent with GALL

by open-cycle cooling general, pitting, Water System Water System with exceptions (see

water systems crevice, and galvanic Program Section 3.3.2.1 below). corrosion, MIC, and

biofouling; buildup of

deposit due to

biofouling

Buried piping and fittings Loss of material due to Buried Piping and Buried Piping and Consistent with GALL

general, pitting, and Tanks Surveillance Tanks Inspection with exceptions. GALL

crevice corrosion and or Buried Piping and Program recommends further

MIC Tanks Inspection evaluation (see Section

_3.3.2.2.10 below).

Components in Loss of material due to Compressed Air Compressed Air Consistent with GALL

compressed air system general and pitting Monitoring Monitoring Program (see Section 3.3.2.1

corrosion below).

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Component Aging Effect/ AMP In GALL AMP In LRA Staff Evaluation

Group Mechanism Report

Components (doors and Loss of material due to Fire Protection Fire Protection Exceptions taken to

barrier penetration seals) wear, hardening and Program GALL on fire door at a

and concrete structures In shrinkage due to frequency of every fire protection system weathering operating cycle under

the CLB rather than the

bi-monthly frequency recommended in GALL

(see Section 3.3.2.3.3

below).

Components in water- Loss of material due to Fire Water System Fire Water System Consistent with

based fire protection general, pitting, GALIJISG (see Section

system crevice, and galvanic 3.3.2.3.4 below).

corrosion, MIC, and

biofouling

Components in diesel fire Loss of material due to Fire Protection Fire Protection Exception taken to

pump fuel system general, pitting, and Program GALL on trending of

crevice corrosion, MIC, test results (see Section

and biofouling 3.3.2.3.3 below).

Tanks in diesel fuel oil Loss of material due to Aboveground Carbon None There are no abovesystem general, pitting, and Steel Tanks ground carbon steel

crevice corrosion tanks in the diesel fuel

oil system.

Closure bolting Loss of material due to Bolting Integrity Bolting Integrity Consistent with GALL

general corrosion; Program with exceptions (see

crack Initiation and Section 3.3.2.1 below).

growth due to cyclic

loading and SOC -

Components In contact Crack initiation and Water Chemistry Water Chemistry These components are

with sodium pentaborate growth due to SCC Program scoped under ESF and

solution in standby liquid are addressed in

control system (BWR) Section 32.4.8.2 of this

SER.

Components In reactor Crack Initiation and Reactor Water BWR Reactor Water Consistent with GALL

water cleanup system growth due to SCC Cleanup System Cleanup System with exceptions (see

and IGSCC Inspection Program Section 3.3.2.1 below).

Components in shutdown Crack Initiation and BWR Stress Corrosion BWR Stress Corrosion Consistent with GALL

cooling system (older growth due to SCC Cracking; Water Cracking Program; with exceptions (see

BWR) Chemistry Water Chemistry Section 3.3.2.1 below).

Program

Components in shutdown Loss of material due to Closed-Cycle Cooling Closed-Cycle Cooling Consistent with GALL

cooling system (older pitting and crevice Water System Water System (see Section 3.3.2.1

BWR) corrosion and MIC Program; Flow- below).

Accelerated Corrosion

Program

Components (aluminum Loss of material due to Selective Leaching of Selective Leaching of Consistent with GALL

bronze, brass, cast iron, selective leaching Materials Materials Program with exceptions (see

cast steel) in open-cycle Section 3.3.2.1 below).

and closed-cycle cooling

water systems; ultimate

heat sink .-

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Component Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

Group Mechanism Report

Fire barriers, walls, Concrete cracking and Fire Protection; Fire Protection These components are

ceilings, and floors in fire spalling due to freeze- Structures Monitoring Program; Structures scoped under structures

protection system thaw, aggressive Monitoring Program and are addressed in

chemical attack, and Sections 3.5.2.4.1 and

reaction with 3.5.2.4.2 of this SER.

aggregates; loss of Exceptions taken to

material due to GALL on concrete fire

corrosion of embedded barrier inspection steel frequency of every five

years under

ACI 349.3R-96 concrete

structures (see Section

3.3.2.3.3 below).

The staff's review of the auxiliary systems for the Dresden and Quad Cities LRA is contained

within four sections of this SER. Section 3.3.2.1 is the staff review of components in the

auxiliary systems that the applicant indicated are consistent with GALL and do not require

further evaluation. Section 3.3.2.2 is the staff review of components in the auxiliary systems

that the applicant indicated are consistent with GALL and for which GALL recommends further

evaluation. Section 3.3.2.3 is the staff evaluation of AMPs that are specific to the auxiliary

systems group. Section 3.3.2.4 contains an evaluation of the adequacy of aging management

for components in each system in the auxiliary systems group and includes an evaluation of

components in the auxiliary systems that the applicant indicated are not in GALL.

3.3.2.1 Aging Management Evaluations in the GALL Report That Are Relied on for License

Renewal, Which Do Not Require Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL does not recommend further evaluation, the staff sampled

components in these groups to determine whether the plant-specific components contained in

these GALL component groups were bounded by the GALL evaluation. The staff also sampled

component groups to determine whether the applicant had properly identified those component

groups in GALL that were not applicable to its plants. The staff also identified several areas

where additional information or clarification was needed.

On the basis of its review, the staff has verified the applicant's claim of consistency with the

GALL report. The staff finds that the applicant has demonstrated that the effects of aging will

be adequately managed so that the intended functions will be maintained consistent with the

CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.2 Aging Management Evaluations in the GALL Report That Are Relied on for License

Renewal, For Which GALL Recommends Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL recommends further evaluation, the staff reviewed the applicant's

evaluation to determine whether it adequately addressed the issues for which GALL

recommended further evaluation. In addition, the staff sampled components in these groups to

determine whether the plant-specific components contained in these GALL component groups

were bounded by the GALL evaluation.

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The GALL Report indicates that further evaluation should be performed for the aging effects

discussed in the following sections.

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

Loss of material due to pitting and crevice corrosion could occur in the piping, filter housing,

valve bodies, and shell and nozzles of the ion exchanger in the spent fuel pool cooling and

cleanup system (BWR) and in the piping/fitting, pump casing, and valves, and their related

components, in the shutdown cooling system (older BWR). The Water Chemistry Program

relies on monitoring and control of reactor water chemistry, based on the EPRI guidelines

outlined in BWRVIP-29 (TR-1 03515) for water chemistry in BWRs, to manage the effect of loss

of material from pitting or crevice corrosion. However, high concentrations of impurities at

crevices and locations of stagnant flow conditions could cause pitting or crevice corrosion.

Therefore, verification of the effectiveness of the Chemistry Control Program should be ' performed to ensure that corrosion is not occurring. The GALL Report recommends further

evaluation of programs to manage loss of material from pitting and crevice corrosion to verify

the effectiveness of the Water Chemistry Program. A one-time inspection of select

components at susceptible locations is an acceptable method to ensure that corrosion is not

occurring and that the component intended functions will be maintained during the period of

extended operation.

The staff reviewed the applicant's proposed program to ensure that corrosion is not occurring

and that the component intended functions will be maintained during the period of extended

operation. If the applicant proposed a one-time inspection of select components at susceptible

locations to ensure that corrosion is not occurring, the staff verified that the applicant's selection

of susceptible locations was based on the severity of conditions, time of service, and lowest - design margin. The staff also verified that the proposed inspection would be performed using

techniques similar to ASME Code and ASTM standards, including visual, ultrasonic, and

surface techniques.

In Section 3.3.1.1.1 of the LRA, the applicant stated that the One-Time Inspection Program

(B.1.23) will be used to perform inspection of the Dresden fuel pool cooling and filter.

demineralizer system to confirm the effectiveness of the Water Chemistry Program (B.1.2).

The one-time inspection will be either a visual or ultrasonic examination of a stainless steel

component or piping for general, pitting, and crevice corrosion. The Water Chemistry Program

and the One-Time Inspection Program are evaluated in Sections 3.0.3.2 and 3.0.3.5,

respectively, of this SER.

The applicant also stated, in Section 3.3.1.1.2 of the LRA, that an inspection of selected

components exposed to a stagnant flow water environment will be conducted in accordance

with the One-Time Inspection Program (B.1.23). The inspection of selected components will

verify the effectiveness of the Chemistry Control Program to manage loss of material due to

general, pitting, and crevice corrosion in low flow or stagnant flow areas by ensuring that

significant degradation is not occurring and that the component intended function will be

maintained during the extended period of operation. Examinations will be conducted on carbon

and stainless steel components in areas where stagnant flow is typically present, but flow

occasionally occurs. Such flow will replenish the oxygen supply. Inspections will be conducted

on the HPCI torus suction check valves, the HPCI booster pumps, and the CRD scram valves.

These components were selected to provide representative samples of the aging effects seen

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in the shutdown cooling system. The carbon steel HPCI torus suction check valves are

exposed to torus water, while the carbon steel HPCI booster pumps and the stainless steel

CRD scram valves are exposed to CST water. Both will undergo a visual exam. This

inspection is also credited for those components exposed to reactor coolant, which are outside

NUREG-1801, Chapter IV.C1.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of loss of material due to pitting and crevice corrosion, as recommended

in the GALL report. Since the applicant's AMR results are otherwise consistent with the GALL

report, the staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.2.2 Hardening and Cracking or Loss of Strength Due to Elastomer Degradation or Loss

of Material Due to Wear

The GALL Report recommends further evaluation of programs to manage the hardening and

cracking due to elastomer degradation of valves in the spent fuel pool cooling and cleanup

system. The GALL Report also recommends further evaluation of programs to manage the

hardening and loss of strength due to elastomer degradation of the collars and seals of the duct

and the elastomer seals of the filters in the control room area, auxiliary and radwaste areas,

and primary containment heating and ventilation systems, as well as the collars and seals of the

duct in the diesel generator building ventilation system. The GALL Report also recommends

further evaluation of programs to manage the loss of material due to wear of the collars and

seals of the duct in the ventilation system. The staff reviewed the applicant's proposed

programs to ensure that an adequate program will be in place for the management of these

aging effects.

In Section 3.3.1.1.5 of the LRA, the applicant credited the Periodic Inspection of Ventilation

System Elastomers Program (B.2.3) for managing hardening and cracking or loss of strength

due to elastomer degradation or loss of material due to wear for components in the control

room, emergency diesel generator building, station blackout diesel generator building, and

reactor building (using the requirements of the containment ventilation) ventilation system

elastomers. The Periodic Inspection of Ventilation System Elastomers Programs is evaluated

in Section 3.0.3.17 of this SER.

The applicant indicated, in item 3.3.1.2 of Table 3.3-1, that the elastomer linings of the valves in

the fuel pool cooling and demineralizer system evaluated in NUREG-1 801, Chapter VII.A4, are

not within the scope of license renewal.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of hardening and cracking or loss of strength due to elastomer -

degradation or loss of material due to wear, as recommended in the GALL report. Since the

applicant's AMR results are otherwise consistent with the GALL report, the staff finds that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

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3.3.2.2.3 Cumulative Fatigue Damage

Fatigue is a TLAA, as defined in 10 CFR 54.3. TLAAs are required to be evaluated in

accordance with 10 CFR 54.21 (c)(1). The staff reviewed the evaluation of this TLAA in Section

4.3 of this SER, following the guidance in Section 4.3 of the SRP-LR.

Cumulative fatigue damage of auxiliary system piping and load handling cranes is a TLAA, as

defined in 10 CFR 54.3. The applicant stated that the RWCU pumps identified by NUREG1801, Chapters VII E3.2-b and VII E3.2-c are not in the scope of license renewal and are not

evaluated as a TLAA. The applicant further stated that cumulative fatigue damage of auxiliary

system piping and load handling cranes is required to be evaluated in accordance with

10 CFR 54.21 (c)(1). The staff's evaluation of the TLAA for auxiliary system piping outside the

RCPB is addressed in Section 4.3.3.2 of this SER. The staff's evaluation of the TLAA for load

handling cranes is addressed in Section 4.7.1 of this SER.

3.3.2.2.4 Crack Initiation and Growth Due to Cracking or Stress-Corrosion Cracking

The GALL Report recommends further evaluation of programs to manage crack initiation and

growth due to SCC that could occur in the regenerative and nonregenerative heat exchanger

components in the reactor water cleanup system (BWR). The applicant stated that heat

exchangers in the reactor water cleanup system are not in scope of license renewal. The staff

verified that this is the case. On the basis of its review, the staff finds that the applicant has

adequately evaluated the management of crack initiation and growth due to cracking or SCC for

components in the auxiliary systems, as recommended in the GALL Report.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of crack initiation and growth due to SCC, as recommended in the GALL

report. Since the applicant's AMR results are otherwise consistent with the GALL report, the

staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.2.5 Loss of Material Due to General, Microbiologically Influenced, Pitting, and Crevice

Corrosion

The GALL Report recommends further evaluation of programs to manage the loss of material

due to general, pitting, and crevice corrosion of the piping and filter housing and supports in the

control room area, the auxiliary and radwaste areas, and the primary containment heating and

ventilation systems; the piping of the diesel generator building ventilation system; and the

aboveground piping and fittings, valves, and pumps in the diesel fuel oil system and the diesel

engine starting air, combustion air intake, and combustion air exhaust subsystems in the

emergency diesel generator system. The GALL Report also recommends further evaluation of

programs to manage the loss of material due to general, pitting, and crevice corrosion and MIC

of the duct fittings, access doors, and closure bolts, equipment frames, and housing of the duct;

pitting and crevice corrosion of the heating/cooling coils of the air handler heating/cooling; and

general corrosion of the external surfaces of all carbon steel structures and components,

including bolting exposed to operating temperatures less than 100 °C (212 0F) in the ventilation

systems. The staff reviewed the applicant's proposed programs to ensure that they will be

adequate for the management of these aging effects.

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The applicant has identified loss of material due to general, pitting, and crevice corrosion and

MIC as an AERM for many of the above GALL items and numerous components that are not

addressed in GALL. The applicant uses the following AMPs to manage this AERM:

* Structures Monitoring Program (B.1.30)

* Bolting Integrity Program (B.1.12)

* One-Time Inspection-Compressed Gas Program (B.1.23)

* Heat Exchanger Testing and Inspection Program (B.2.6)

* One-Time Inspection-Ventilation System (B.2.6)

* Open-Cycle Cooling Water System Program (B.1.13)

* Buried Piping and Tanks Inspection Program (B.1.25)

* Fire Protection Program (B.1.18)

* One-Time Inspection-NSR/SR Inspection Program (B.1.23)

These AMPs are reviewed in Sections 3.0.3.5, 3.0.3.6, 3.0.3.10, 3.0.3.12, 3.0.3.14, 3.0.3.16,

and 3.3.2.3.3, respectively, of this SER. In its October 3, 2003, response to RAI 3.3-7, the

applicant provided additional information related to how these AMPs are used to manage the

loss of material. This additional information is discussed in Section 3.3.2.5.7 of the SER and in

the above SER sections related to the AMPs.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of loss of material due to general, pitting, and crevice corrosion and

MIC, as recommended in the GALL report. Since the applicant's AMR results are otherwise

consistent with the GALL report, the staff finds that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

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

The GALL Report recommends further evaluation of programs to manage the loss of material

due to general, galvanic, pitting, and crevice corrosion of tanks, piping, valve bodies, and tubing

in the reactor coolant pump oil collection system within the Fire Protection Program. This is not

applicable to either Dresden or Quad Cities.

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

Corrosion and Biofouling

The GALL Report recommends further evaluation of programs to manage loss of material due

to general, pitting, and crevice corrosion, MIC, and biofouling of the internal surface of tanks in

the diesel fuel oil system and due to general, pitting, and crevice corrosion and MIC of the tanks

of the diesel engine fuel oil system in the emergency diesel generator system. The GALL's

Fuel Oil Chemistry Program relies on monitoring and control of fuel oil contamination in

accordance with the guidelines of ASTM Standards D4057, D1 796, D2709, and D2276

concerning loss of material due to corrosion or biofouling. Corrosion or biofouling may occur at

locations where contaminants accumulate. Verification of the effectiveness of the Fuel Oil

Chemistry Program should be performed to ensure that corrosion/biofouling is not occurring

and that the component intended function will be maintained during the period of extended

operation.

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The applicant stated that an inspection will be performed in accordance with the One-Time

Inspection Program (B.1.23) to verify the effectiveness of the Fuel Oil Chemistry Program

(B.1.21) to prevent loss of material. A UT examination of the lower portion of one carbon steel

underground fuel oil storage tank and one day tank at each facility will be performed. The

applicant clarified that the Quad Cities Unit I underground fuel oil storage tank is constructed of

fiberglass; aging management for loss of material is discussed separately as a non-GALL item.

The applicant further stated that activities to prevent biofouling of the fuel oil systems are

performed in accordance with the Fuel Oil Chemistry Program (B.1.21). Preventive activities

under that program include routine sampling to provide assurance that contaminant levels,

including water, are kept at acceptable levels for fuel oil system components, and the addition

of a biocide to the underground fuel oil storage tanks with each new fuel delivery. The Fuel Oil

Chemistry and One-Time Inspection Programs are evaluated in Sections 3.0.3.10 and 3.0.3.11,

respectively, of this SER.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of loss of material due to general, pitting, and crevice corrosion, MIC,

and biofouling, as recommended in the GALLnreport. Since the applicant's AMR results are

otherwise consistent with the GALL report, the staff finds that the applicant has demonstrated

that the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.3.2.2.8 Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General

Corrosion

Reduction of neutron-absorbing capacity and loss of material due to general corrosion could

occur in the neutron-absorbing sheets of the spent fuel storage rack in the spent fuel storage

system. The GALL Report recommends further evaluation of programs to manage these aging

effects. The staff reviewed the applicant's proposed program to ensure that an adequate

program will be in place for the management of these aging effects.

In the LRA, these components are scoped under the structures. The staff's evaluation of other

Class 1 structures is documented in Section 3.5.2.4.2.2 of this SER.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of reduction of neutron-absorbing capacity and loss of material due to

general corrosion, as recommended in the GALL report. Since the applicant's AMR results are

otherwise consistent with the GALL report, the staff finds that the applicant has demonstrated

that the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.3.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion

Loss of material due to general, pitting, and crevice corrosion and MIC could occur in the

underground piping and fittings in the open-cycle cooling water system (service water system)

and in the diesel fuel oil system. The GALL's Buried Piping and Tanks Inspection Program

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relies on industry practice, frequency of pipe excavation, and operating experience to manage

the effects of loss of material from general, pitting, and crevice corrosion and MIC. The staff

reviews the effectiveness of the Buried Piping and Tanks Inspection Program, including its

inspection frequency and operating experience, to ensure that loss of material is not occurring

and that the component intended function will be maintained during the period of extended

operation.

Section 3.3.1.1.4 of the LRA states that the applicant's Buried Piping and Tanks Inspection

Program (B.1.25) relies on industry practice, frequency of pipe excavations, and operating

experience to manage the aging of buried components. The applicant stated that since

Dresden and Quad Cities infrequently expose buried components during yard excavation

activities, additional testing and inspection activities are credited. The applicant stated that with

the identified exceptions and enhancements, the AMP is consistent with GALL. The evaluation

of the Buried Piping and Tanks Inspection Program (B.1.25) is documented in Section 3.0.3.12

of this SER.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of loss of material due to general, pitting, and crevice corrosion and

MIC, as recommended in the GALL report. Since the applicant's AMR results are otherwise

consistent with the GALL report, the staff finds that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.3.2.3 Aging Management Programs for Auxiliary System Components

The applicant credits 23 AMPs (listed below) to manage the aging effects associated with

components in the auxiliary systems. Seventeen of the AMPs are credited to manage aging for

components in other system groups (common AMPs), while six AMPs are credited to manage aging only for auxiliary system components. The staff's evaluation of the common AMPs

credited with managing aging for the auxiliary system components is provided in Section 3.0.3

of this SER. These common AMPs are listed below, along with their section numbers.

* Inservice Inspection Program (Section3.0.3.1)

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* Open-Cycle Cooling Water System Program (Section 3.0.3.6)

* Closed-Cycle Cooling Water System Program (Section 3.0.3.7)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* Aboveground Carbon Steel Tanks Program (Section 3.0.3.9)

* One-Time Inspection Program (Section 3.0.3.10)

* Selective Leaching of Materials Program (Section 3.0.3.11)

* Buried Piping and Tanks Inspection Program (Section 3.0.3.12)

* 10 CFR Part 50, Appendix J Inspection Program (Section 3.0.3.13)

* Structures Monitoring Program (Section 3.0.3.14)

* Heat Exchanger Test and Inspection Activities Program (Section 3.0.3.15)

* Lube Oil Monitoring Program (Section 3.0.3.16)

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* Periodic Inspection of Ventilati6n System Elastomers Program (Section 3.0.3.17)

The staff's evaluation of the seven auxiliary system AMPs is provided in the following sections.

3.3.2.3.1 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling

Systems (B.1.15)

Summary of Technical Information in the Application. The applicant's overhead load handling

systems inspection program is discussed in LRA Section B.1.15, "Inspection of Overhead

Heavy Load and Light Load (Related to Refueling) Handling Systems." The applicant states

that, with enhancements, the program is consistent with the GALL program XL.M23, "Inspection

of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems" with the

exception that the applicant does not provide for tracking the magnitude and number of lifts

because administrative controls are implemented to ensure that only allowable loads are

handled and fatigue of structural elements is not expected. The applicant also states that the

enhancements will provide for specific inspections for rail wear and proper crane travel on rails,

and the program will provide for specific inspections for corrosion of crane structural

components.

The AMP is credited with managing aging due to the loss of material of bridge and trolley crane

components for the refueling systems.

The applicant claims the operating experience indicates that the program has been successful

in managing aging of structural components of overhead heavy load and light load (related to

refueling) handling systems so that intended functions have been maintained.

In its LRA, the applicant concludes that the of overhead heavy load and light load (related to

refueling) handling systems aging management program provides reasonable assurance that

loss of material aging effects are adequately managed so that the intended functions of crane

structural components within the scope of license renewal are maintained during the period of

extended operation. -

Staff Evaluation. In LRA Section B.1.15, "Inspection of Overhead Heavy Load and Light Load

(Related to Refueling) Handling Systems," the applicant described its AMP to manage aging in

bridge and trolley cranes structural components. The LRA stated that this AMP, with

enhancements, is consistent with the GALL AMP, XL.M23, "Inspection of Overhead Heavy Load

and Light Load (Related to Refueling) Handling Systems" with an exception regarding a

provision for tracking the magnitude and number of lifts because administrative controls are

implemented to ensure that only allowable loads are handled and fatigue of structural elements

is not expected. The staff confirmed the applicant's claim of consistency during the AMR

inspection. Furthermore, the staff reviewed the exception and its justification to determine

whether the AMP, remains adequate to manage the aging effects for which it is credited. The

staff reviewed the UFSAR supplement to determine whether it provides an adequate

description of the revised program. In addition, the staff determined whether the applicant

properly applied the GALL program to its facility.

LRA Table 3.3-1, Ref No 3.3.1.14 identifies the Overhead Heavy Load and Light Load (Related

to Refueling) Handling Systems (B.1.15) as the applicable aging management program to

manage loss of material due to general corrosion and wear in the refueling system cranes

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during the period of extended operation. This AMP, with enhancements, claims consistency

with the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling

Systems program, XL.M23 in NUREG-1 801 with the exception that it does not review the

number and magnitude of lifts as in element 3 of the GALL report AMP XL.M23. The LRA

states the reason for the exception is because administrative controls assure "... that only

allowable loads are handled and fatigue failure of structural elements is not expected." The

AMP also states that a time-limited aging analysis concludes that there are no fatigue concerns

for the period of extended operation. By letter dated August 4, 2003, the staff requested, in RAI

B.1.1 5, the applicant to provide justifications to demonstrate how the administrative control is

adequate in lieu of tracking of the number and magnitude of lifts as in element 3 of GALL report

AMP XL.M23.

Furthermore, the description of B.1.15 also states that the enhancements, specific inspections

for rail wear and proper crane travel on rails as well as specific inspections for corrosion of

crane structural components, are scheduled to be implemented prior to the period of extended

operation. This Commitment #15 of Appendix A in this SER. In the same letter mentioned

above, the applicant is requested to provide an explanation of the statement in the Operating

Experience section of B.1.15 which indicate that this program has been successful in the past

at Dresden and Quad Cities if the proposed enhancements to the AMP (which are the primary

attributes of XI.M23) have not yet been implemented. In addition, the staff also requested the

applicant to provide a statement to clarify that these enhanced inspections will be conducted on

a routine basis as in element 4 of the GALL report AMP XI.M23, and to provide an explanation

of how the conclusion that there are no fatigues concerns for the period of extended operation

can be achieved without a fatigue analysis that considers the number and magnitude of lifts.

In its response dated October 3, 2003, the applicant specifies the justification for the adequacy

of administrative controls in lieu of tracking the number and magnitude of lifts for the subject

cranes in terms of the following reasons:

(a) The number and magnitude of lifts that are anticipated for any crane is significantly below

the design limits. See section 4.7.1 of the LRA.

(b) Various industry documents were used to develop procedures governing crane inspections

at each site, including Vendor Manuals, OSHA Chapter XVII, Title 29 Part 1910.179, and'

ASME/ANSI B30.2, B30.10, B30.11, B30.16 Crane Standards, NUREG-0612, Control of

Heavy Loads at Nuclear Power Plants, and 10CFR50.65, Maintenance Rule

(c) Crane inspections and functional checks are periodically performed in accordance with the

above inspection procedures by qualified crane/structural steel inspectors

(d) Crane operating procedures require crane inspection prior to each use

(e) Crane operating procedures ensure that crane loading does not exceed crane capacities

(f) The reactor building overhead crane has the largest capacity of any in-scope crane at each

site. This crane was designed to CMAA-70 Class Al and is compatible with the

requirements of the Occupational Safety and Health Act of 1970, as amended in 1971, as

well as ANSI B30.2.0.

(g) The capacities of the cranes other than the reactor building overhead crane are relatively

small. Consequently, any associated fatigue-related degradation of crane components

would be identified via periodic inspections prior to loss of crane function.

The applicant further stated that enhancements to the Inspection of Overhead Heavy Load and

Light Load (Related to Refueling) Handling Systems program will include the addition of

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inspections for rail wear and proper crane travel on rails as well as for corrosion of crane

structural components. The existing program includes visual inspections of various crane

components. The applicant clarified that the statement in the Operating Experience section of

LRA Section B.1.1 5 indicating that the program has been successful in the past applies to the

existing program. Crane inspections under the existing program are routinely performed.

Inspections under the enhanced program will also be routinely performed. The applicant

agreed that a statement should have been added to the enhancements section of LRA Section

B.1.1 5 indicating that the subject crane inspections will be routinely performed.

The LRA Section B.1.15 conclusion that there are no fatigue concerns for the reactor building

overhead cranes for the period of extended operation is valid despite that fact that there was no

fatigue analysis. The applicant stated that the basis for this conclusion is provided in LRA

Section 4.7.1, Reactor Building Crane Load Cycles, which concludes that fatigue life is not

significant to the operation of the reactor building overhead crane for the period of extended

operation as its projected 60-year cycle estimate is only a fraction of the number of cycles for

which the crane was qualified.

On the basis of its review, the staff finds that the applicant's response acceptable because; 1)

the seven elements of the administrative procedures that the applicant has provided, 2) the

applicant clarified the enhancements section of LRA Section B.1.1 5 indicating that the subject

crane inspections will be routinely performed, and 3) the applicant has shown that fatigue life is

not significant to the operation of the reactor building overhead crane for the period of extended

operation as its projected 60-year cycle estimate is only a fraction of the number of cycles for

which the crane was qualified. All issues related to this RAI B.1.15 is considered resolved.

The staff reviewed the UFSAR supplement in Section 1.15 of Appendix A of the LRA and found

that the description of the Inspection of Overhead Heavy Load and Light Load (Related to

Refueling) Handling Systems is consistent with Section B.1.15 of the LRA. The staff finds that

the information provided in the UFSAR supplement provides an adequate summary of the

program activities as required by 10 CFR 54.21 (d).

Conclusions. On the basis of its review and audit of the applicant's program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. In addition, the staff has reviewed the

exceptions to the GALL program and finds that the applicant has demonstrated that the effects

of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR supplement for this aging

management program and finds that it provides an adequate summary description of the

program, as required by 10 CFR 54.21 (d).

3.3.2.3.2 BWR Reactor Water Cleanup System (B.1.17)

Summary of Technical Information in the Application. The applicant's program for monitoring

and controlling reactor water chemistry to reduce the susceptibility of reactor water cleanup

(RWCU) piping to stress corrosion cracking (SCC) and intergranular stress corrosion cracking

(IGSCC) is discussed in LRA Section B.1.17, "BWR Reactor Water Cleanup System." The

applicant stated that the program is consistent with GALL AMP XI.M25, "BWR Reactor Water

Cleanup System," with the exception that the specification of water chemistry control is in

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accordance with EPRI TR-1 03515-Revision 2 instead of the earlier EPRI TR-1 03515. The

applicant also stated that LRA Section B.1.2 presents the water chemistry aging management

program and the exceptions to the program as specified in GALL. The LRA credits the water

chemistry activities to reduce susceptibility to SCC and IGSCC.

The applicant stated that Dresden and Quad Cities have satisfactorily completed all actions

requested in NRC GL 89-10, "Safety-Related Motor-Operated Valve Testing and Surveillance,"

and have replaced the RWCU system piping with piping that is resistant to IGSCC in

accordance with NRC GL 88-01, "NRC Position on Intergranular Stress Corrosion Cracking

(IGSCC) in BWR Austenitic Stainless Steel Piping." The applicant concluded that inspection of

RWCU piping is not required. The applicant stated that operating experience has shown that,

since replacing the RWCU system piping with IGSCC-resistant piping, there have been no

adverse trends detected in the chemistry program.

The reactor water cleanup system is referenced in LRA Section 3, uAging Management Review

Results." This system-specific aging management program is credited only for the auxiliary

systems. In Table 3.3-1, Ref. No. 3.3.1.24, the applicant states that crack initiation and growth

due to SCC and IGSCC in components, piping and fittings in the reactor water cleanup system

is managed by reactor water cleanup system inspection. No further evaluation is

recommended.

In Section B.1.17 of the LRA, the applicant indicated that the BWR Reactor Water Cleanup

System AMP has been demonstrated to be capable of managing SCC and IGSCC aging

effects in the RWCU piping. The applicant concluded that the BWR Reactor Water Cleanup

System AMP provides reasonable assurance that the aging effects will be managed such that

the components subject to AMR will continue to perform their intended functions consistent with

the CLB during the period of extended operation.

Staff Evaluation. In LRA Section B.1.17, "BWR Reactor Water Cleanup System," the applicant

described its AMP to monitor and control reactor water chemistry to reduce the susceptibility of

RWCU piping to SCC and IGSCC. The LRA states that this AMP is consistent with GALL AMP

XL.M25, "BWR Reactor Water Cleanup System," with an exception regarding the specification

of water chemistry control in accordance with EPRI TR-1 03515-R2 which is the 2000 revision of

the 1993 revision of EPRI TR-103515, "BWR Water Chemistry Guidelines," and references the

LRA Section B.1.2, "Water Chemistry."

By NRC Aging Management Inspection Information Request Number AMI-15 dated September

30, 2003, the staff requested that an inspection of LRA AMP B.1.17 be included in the NRC

Inspection List. The staff noted that the purpose of the inspection was to verify that the criteria

delineated in GALL AMP XL.M25 are met for the Dresden and Quad Cities plants so that AMP

B.1.17 is consistent with GALL AMP XI.M25 (with the exception of the water chemistry

program) as stated by the applicant in AMP B.1.17 in Appendix B of the LRA. In AMP B.1.17,

the applicant also stated that the inspection of RWCU piping is not required because Dresden

and Quad Cities have satisfactorily completed all actions requested in NRC GL 89-10, and have

replaced the RWCU system piping with piping that is resistant to IGSCC in accordance with

NRC GL 88-01 (the applicant claimed that this met the GALL AMP XL.M25 criteria of not

requiring IGSCC inspection).

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Since the applicant stated that the 'entire RWCU system piping was replaced with IGSCCresistant piping in accordance with NRC GL 89-10, the staff subsequently requested the

applicant to provide the following information to be verified by the NRC Audit-Inspection Team:

(i) Clarify whether the entire RWCU system piping was replaced with IGSCC-resistant material

or whether only portions of the RWCU system piping for each plant were replaced.

(ii) Confirm that, if the entire RWCU system piping was replaced, the piping system includes all

the RWCU welds inboard and outboard of the second isolation valves. Confirm whether the

selection of material of the replaced piping and weld metal meet the material compositions as

described in GALL AMP XI.M25.

(iii) Verify that, if only portions of the RWCU system piping were replaced, the entire RWCU

system piping meets the screening criteria, 1 (a),'(b), and (c) in GALL AMP XI.M25 program

element 1, Scope of the Program, as well as the material specifications in GALL AMP XI.M25

program element 2, Preventive Actions.

This was identified as Confirmatory Item B.1.17.

During the audit, the team confirmed the following technical information relating to this AMP

with the applicant at the request of the NRC's technical staff:

* All in-scope portions of the RWCU system piping outboard of the second isolation valves

were replaced with ASTM SA312 or SA376 Gr. TP31 6L with a carbon content of less than

0.035 percent. RWCU piping inboard of the second isolation valve have not been replaced

with IGSCC resistant piping.

* The RWCU piping that is inboard of the second isolation valve is Class 1 and 2 piping that

is managed by the ISI Program (B.1.1), ASME Section Xl, Subsections IWB, IWC, and

IWD. All of the RWCU piping and welds on the in-scope portion outboard of the second

isolation valves were replaced. The replacement piping and weld metal meets the material

compositions as described in NUREG-1 801, AMP XI.M25.

* All the RWCU piping and welds on the in-scope portion outboard of the second isolation

valves were replaced with piping and weld material that meet the material compositions as

described in NUREG-1 801, AMP XI.M25. Screening criteria 1(a), (b), and (c) of NUREG1801, AMP XI.M25 do not apply to this piping.

* In a letter to the NRC, dated August 20, 1993, the licensee committed to replace all RWCU

IGSCC susceptible outboard supply and return line piping and the regenerative heat

exchangers with IGSCC resistant materials at both Dresden and Quad Cities.

License Renewal Boundary Drawings LR-DRE-M-30 and LR-QDC-M-47-1 show the piping

design table for the in-scope portion of the RWCU piping outboard of the second isolation

valves to be table AQ. Dresden specification K-4080 and Quad Cities specification R-4411

provide the material specification for piping design table AQ. Design table AQ provides the

information on the piping material: all in-scope portions of the RWCU system piping outboard of

the second isolation valves were replaced with ASTM SA312 or SA376 Gr. TP316L with a

carbon content of less than 0.035 percent.

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I

Based on the above information, the applicant confirmed that the ten elements of the GALL

program, UBWR Reactor Water Cleanup System," as specified in NUREG-1 801, AMP XI.M25

(with the exception of the Water Chemistry Program as noted in the LRA) are applicable to

Dresden and Quad Cities, and that the applicant's program B.1.17 is consistent with GALL AMP

XL.M25, with the exception as noted in the LRA.

On the basis of its review of this AMP, GALL AMP XL.M25, AMR topical report M.05, and the ISI

Program plan, the audit team determined that this AMP is consistent with GALL AMP XL.M25,

with the exception as noted in the LRA. Therefore, Confirmatory Item B.1.17 is closed.

Section A.1.17 of Appendix A to the LRA contains the applicant's UFSAR supplement for the

BWR reactor water cleanup system program at Dresden and Quad Cities nuclear power

stations. The staff reviewed the UFSAR supplement and found that the description of the BWR

reactor water cleanup system program is consistent with Section B.1.17 of the LRA. The staff

finds that the information contained in the UFSAR supplement presents an adequate summary

of the program activities as required by 10 CFR 54.21 (d).

The staff confirmed the applicant's claim of consistency during the AMR inspection.

Furthermore, the staff reviewed the exception and its justification to determine whether the

AMP, with the exception, remains adequate to manage the aging effects for which it is credited.

The staff also reviewed the USAR supplement to determine whether it provides an adequate

description of the revised program. In addition, for the Dresden and Quad Cities nuclear power

stations, the staff determined whether the applicant properly applied the GALL program to its

facilities.

Conclusions. On the basis of its review and audit of the applicants program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. In addition, the staff has reviewed the

exceptions to the GALL program and finds that the applicant has demonstrated that the effects

of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB during the period of extended operation, as required by 10 CFR

54.21 (a)(3). The staff also reviewed the UFSAR supplement for this AMP and finds that it

provides an adequate summary description of the program, as required by 10 CFR 54.21(d).

3.3.2.3.3 Fire Protection Program (B.1.18)

Summary of Technical Information. Appendix B, Section B.1.1 8 identifies the AMP for the FP

components within the scope of license renewal. The AMP for FP SSCs includes the

inspection, surveillance testing and maintenance for monitoring and controlling the effects of

aging. This section addresses the consistency of the program described in Appendix B.1.18

with Section XL.M26 of NUREG-1 801 and identifies exceptions and enhancements to its

specific requirements. This section also discusses operating experience with the FP SSCs at

the plants.

Staff Evaluation. The staff reviewed LRA Appendix B.1.18 to determine whether there is

reasonable assurance that the AMP activities are adequate to maintain the intended functions

of the FP SSCs for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The

staff's review was conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1 800) and

is described as below.

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LRA Appendix B, Section B.1.18, "Fire Protection," states that, "With enhancements the FPP is

consistent with the ten elements of aging management program XL.M26, "Fire Protection,"

specified in NUREG-1 801 with following exceptions...." In order for the staff to evaluate the

adequacy of the applicant's FP AMP and reach a conclusion that it is consistent with NUREG1801, the staff requested, in a letter dated August 4,2003, that the applicant follow the

guidelines provided in NUREG-1801 for FP AMP. NUREG-1801 contains the staff's generic

evaluation of the existing plant program and documents the technical basis for determining

where existing programs are adequate without modification and where existing programs

should be augmented for the period of extended operation. The frequencies identified in

Appendix B, Section B.1.18 exceed those committed to in the applicant's FP program. The

staff also requested that the applicant clarify if the plant FP programs include surveillance

requirements consistent with regulatory guidelines, and if the activities defined in B.1.18 are in

addition to the inspections provided under the FP program.

In a letter dated October 3,2003, the applicant responded that after the enhancements

discussed in Appendix B, Section B.1.18, Subsection, "Enhancements," are implemented, the

Dresden and Quad Cities FPP will be consistent with the ten element program described in

NUREG-1 801, XL.M26, "Fire Protection." However, after the enhancements are implemented,

the following exceptions will exist:

(1) NUREG-1 801, XI.M26, Element 4 states that a visual inspection of fire barrier walls,

ceilings, and floors is to be performed at least once every refueling outage to ensure timely

detection of concrete cracking, spalling, and loss of material before there is a loss of

intended function. The Dresden and Quad Cities FPP requires inspection of concrete fire

barrier walls, ceilings, and floors once every five years, which exceeds the stated frequency

of NUREG-1 801, XL.M26. This inspection interval, which is in excess of NUREG-1 801

guidance, has been justified for the following reasons:

* Station FPP inspections and other similar station inspections have not found any

significant aging effect that requires extensive corrective action for any concrete

structure within the scope of license renewal. Typically, concrete cracks that have been

observed have been attributed to normal concrete shrinkage occurring during

construction and are non-active.

* The environment surrounding Dresden and Quad Cities is non-aggressive for concrete.

* Industry guidance contained in ACI 349.3R-96, "Evaluation of Existing Nuclear SafetyRelated Concrete Structures," indicates that a five-year inspection frequency for

concrete components is adequate for timely identification and correction of degraded

conditions prior to a loss of intended function.

* The FPP has provisions to allow for the number of components monitored and the

frequency of inspections to be adjusted, to ensure the level of effort is commensurate

with the existing degradation mechanisms that are identified.

The staff reviewed the applicant's response. On the basis of the justification provided, the staff

agrees that the 5-year frequency is adequate for managing the aging effects of these concrete

barriers.

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(2) XI.M26, Element 4 states that VT-1 or equivalent penetration seal inspections, and VT-3 or

equivalent fire door inspections, are to be performed. Personnel performing seal and fire

door inspections at Dresden and Quad Cities are not qualified to American Society for

Nondestructive Testing (ASNT) requirements. However, personnel performing these

inspections are trained and experienced in FPP requirements. The quality of the fire barrier

penetration seal and fire door inspections are equivalent to the VT-1 and VT-3 inspections

as is evidenced by the history of identifying conditions requiring maintenance, repair or

replacement.

The staff reviewed the applicant's response and concurs that on the basis of the training

provided and the absence of the need for special tools or equipment, the qualifications

established for these inspectors are adequate.

(3) GALL AMP XI.M26, Element 3 states that fire doors are visually inspected at least once bimonthly for holes in the skin of the door and that clearances are also checked at least once

bimonthly as part of an inspection program. It also states that function tests of fire doors

are performed daily, weekly, or monthly (plant-specific) to verify the operability of automatic

hold-open, release, closing mechanisms, and latches. The Dresden and Quad Cities FP

program provides for an in-depth inspection for condition and operability of fire doors once

per operating cycle, which exceeds the stated frequency of NUREG-1 801, XL.M26.

Dresden checks fire door clearances as part of their operating cycle inspection. Quad

Cities does not check door clearances as part of their operating cycle inspection, but does

check fire door clearances after maintenance has been performed on a fire door. This

inspection interval in excess of NUREG-1 801 is justified because the fire doors most likely

to experience excessive wear are those that are subject to the most frequent use. Most

frequently used doors, such as those in normal and high-traffic areas, are additionally

monitored by normal plant operation during periodic fire marshal tours, operator rounds, and

security patrols.

The combination of in-depth inspections and monitoring by personnel performing tours, rounds

and patrols has been effective in identifying degraded doors and prompting the applicant to

take corrective action as necessary. Door degradation is due to wear and physical damage.

No instance of door assembly loss of material due to corrosion has been identified.

The staff reviewed the applicant's response. The staff concurs that the frequency of checking

doors for aging management concerns each operating cycle is adequate. However, the staff

does not agree with the applicant's position that door clearances do not need to be monitored at

Quad Cities as part of the inspection program. During the conference call dated November 3,

2003, with applicant, staff stated that the NRC does not agree that door clearances do not need

to be monitored at Quad Cities as part of the inspection program. In a letter dated

November 20, 2003, the applicant stated that, Quad Cities will include the checking of fire door

clearances as a routine part of the operating cycle inspection activities. This will be

implemented prior to the extended period of operation. This is part Commitment #18 in

Appendix A of this SER. A review was performed of the associated UFSAR supplement

(A.1.18) and the AMP description found in section B.1.18 of the LRA. It was determined that no

changes were required as a result of this change in commitment.

The staff reviewed the applicant's response and agrees that the Quad Cities AMP will include

the checking of fire door clearances as a routine part of the operating cycle inspection activities.

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(4) GALL AMP XL.M26, Element 4'states that a periodic functiori test and visual inspection

performed at least once every six months detects degradation of the Halon and C02 fire

suppression systems before the loss of the component's intended function. The Quad

Cities and Dresden Halon and C02 fire suppression systems are currently tested and

inspected every 18 months. However, the Technical Requirements Manual permits a

testing frequency of once every two years. Either of these frequencies exceeds the stated

frequency of NUREG-1 801, XLM26, but is considered sufficient to ensure system

availability and operability based on station operating history that indicates no occurrence of

aging-related events having adversely affected system operation.

The staff reviewed the applicant's response and concurs that on the basis of plant experience,

the 1 8-month frequency is adequate for aging management considerations.

(5) GALL AMP XL.M26, Element 6 states that any signs of corrosion and mechanical damage of

the Halon or C02 fire suppression system are not acceptable. The Dresden and Quad

Cities program requires that signs of aging degradation on the external surfaces of the

Halon or CO2 fire suppression systems be evaluated and corrective action be taken as

required. Although this method could result in minor corrosion or mechanical damage being

evaluated as acceptable, this approach provides reasonable assurance that corrective

actions appropriate to the severity of the observed degradation will be implemented prior to

a loss of the system or component's intended functions.

The staff reviewed the applicants response. The response provides evaluation method or

criteria for the acceptance of discovered corrosion. During the conference call dated

November 3, 2003, with the applicant, staff stated that the NRC does agree with the response

that the Dresden and Quad Cities AMP requires that signs of aging degradation on the external

surfaces of the Halon or C02 fire suppression systems be evaluated and corrective actions be

taken as required. Further, staff stated that without definitive criteria, NRC staff cannot

evaluate the adequacy of the aging degradation of Halon or C02 fire suppression systems

components corrosion or mechanical damage. In a letter dated November 20, 2003, the

applicant stated that, "The License Renewal Application, Appendix B, Section B.1.18,"

paragraph 5 of 'Description" should have read as follows:

The program will provide for aging management of external surfaces of Dresden and Quad Cities

carbon dioxide system components and Dresden Halon system components for corrosion and

mechanical damage through periodic operability tests based on NFPA codes and visual

inspections. Tests and Inspections are implemented through predefined tasks and procedures.'

In Section B.1.18, the second bullet under "Enhancements" should have read as follows:

The program will provide for inspection for corrosion and mechanical damage on external surfaces

of piping and components for the Dresden and Quad Cities carbon dioxide systems and the

Dresden Halon system.

The applicant will examine C02 piping and component external surfaces for indications of

corrosion degradation, mechanical damage or leakage. Inspection criteria for corrosion

degradation included in the inspection procedures are flaking or peeling paint (if painted), rust

scale, rust stains on painted surfaces, or leakage. Inspection criteria for C02 leakage included

in the inspection procedures include visible vapor, hissing, or surface condensation. Halon

piping and component external surfaces are examined for indications of corrosion degradation,

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utilizing the same criteria as for C02, and for indications of mechanical damage. When

indications of corrosion, mechanical damage or leakage are found, work supervisors and unit

supervisors are notified. Any identified indications of corrosion; mechanical damage or leakage

are evaluated by Engineering to determine if corrective actions are needed. The evaluations are

performed using Condition Reports, in accordance with Exelon procedures. As required, work

requests are initiated to perform the work to correct the degraded or inoperable conditions".

This is part of Commitment #18 of Appendix A of this SER.

The staff reviewed the applicant's response and agrees with the proposed AMP to manage the

aging degradation on the external surfaces of the Halon or CO2 fire suppression systems.

(6) GALL AMP XL.M26, Element 5 states that the performance of the fire pump is monitored

during the periodic test to detect any degradation in the fuel supply lines and that periodic

testing provides data (e.g., pressure) necessary for trending. The Dresden and Quad

Cities diesel-driven fire pump test results and the Dresden isolation condenser diesel-driven

makeup pump test results are not trended. Instead, in the event the predetermined

acceptance criteria are not met, an engineering evaluation is conducted to determine the

operability of the pump and the need for corrective action. This method is justified, given

that there have been no reports of a loss of function of the Dresden or Quad Cities dieseldriven fire pumps as a result of the inability of the fuel oil system to deliver fuel to the engine

and there have been no reports of a loss of material or flow blockage of the Dresden

isolation condenser makeup pump fuel oil subsystem.

The staff has reviewed the applicant's response, and on the basis of the plant's experience,

agrees with the applicant's testing methodology. This is part of Commitment #18 of Appendix A

of this SER.

The activities described in the Dresden and Quad Cities LRA, Appendix B, Section B.1.18

comprise the Dresden and Quad Cities FP program. Other than what is identified above, the

Dresden and Quad Cities FP program surveillance requirements are consistent with the

regulatory guidelines stated in NUREG-1 801, XL.M26, "Fire Protection."

Conclusions. On the basis of its review and audit of the applicant's program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. In addition, the staff has reviewed the

exceptions to the GALL program and finds that the applicant has demonstrated that the effects

of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and finds that it

provides an adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.3.2.3.4 Fire Water System (B.1.19)

Summary of Technical Information. Appendix B, Section B.1.19 identifies the AMP for the fire

water system components within the scope of license renewal. The fire water system AMP

provided for managing the loss of material and biofouling aging effects on the intended

functions of the water-based FP components within the scope of license renewal. The program

included inspection, surveillance testing and maintenance activities. This section addresses the

consistency of B.1.19 with Section XL.M27 of NUREG-1 801 and identifies exceptions and

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enhancements to its specific requirements. This section also discusses operating experience

with the fire water system at Dresden and Quad Cities.

Staff Evaluation. The staff reviewed LRA Appendix B.1.19 to determine whether there is

reasonable assurance that the AMP activities are adequate to maintain the intended functions

of the fire water system SSCs for the period of extended operation, as required by 10 CFR

54.21 (a)(1)(a)(3). The staff's review was conducted in accordance with Section 2.3 of the SRPLR (NUREG-1 800) and is described as below.

LRA Appendix B, Section B.1.19, "Fire Water System," states that, "With enhancements the fire

water system aging management program is consistent with the ten elements of aging

management program XI.M27, 'Fire Water System," specified in NUREG-1 801 with the

following exceptions...." In order for the staff to evaluate the adequacy of the applicant's FP

AMP and reach a conclusion that it is consistent with NUREG-1 801, the staff requested, in a

letter dated August 4, 2003, that the applicant follow the guidelines provided in NUREG-1 801

and the interim staff guidance for FP AMP [Staff Guidance (ISG)-04, "Aging Management of

Fire Protection Systems for License Renewal," (ADAMS Accession ML022260137, dated

December 3, 2002]. NUREG-1 801 contains the staff's generic evaluation of the existing plant

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

adequate without modification and where existing programs should be augmented for the

period of extended operation.

In a letter dated October 3,2003, the applicant responded with the following information. Part 1

of this response compares the Dresden and Quad Cities fire water system program against the

NUREG-1801, XI.M27 program and identifies where exceptions still exist. Included in Part 1 is

a discussion of how Dresden and Quad Cities are addressing ISG-04. Part 2 of the response

discusses the Dresden and Quad Cities underground loop flow testing.

(1) The applicant concluded in the Dresden and Quad Cities LRA, Appendix B, Section B.1.19,

that the fire water system program, after the enhancements discussed in Appendix B,

Section B.1.19, Subsection, "Enhancements," are implemented, will be consistent with the

ten-element program described in NUREG-1801, XL.M27, with certain exceptions. Although

not stated in the LRA, after the enhancements are implemented, the fire water system

program will be also be consistent with the NRC staff recommendations for fire water

systems as provided in ISG-04.

Exelon evaluated the Dresden and Quad Cities fire water system program against the attributes

of the ten elements of NUREG-1801, XI.M27 and identified that after the enhancements are

implemented, the following exceptions will still exist:

NUREG-1 801, XI.M27, Element 3 states that 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. Flow tests at the maximum

design flow are not practicable for Dresden and Quad Cities. Instead, the Dresden and

Quad Cities flow tests analyze the system hydraulic resistance. Dresden measures

underground piping pressure drops at given flows for selected segments of underground

fire mains and compares them to pre-calculated allowable pressure drops for the same

segments at the given flows. The measured pressure drop must be equal to or less

than the allowable. The measured results are also compared with those of previous

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tests to identify adverse trends. Quad Cities takes pressure measurements and

calculates the friction loss coefficients ("C" factor) for the various sections of the

underground fire mains. The calculated "C" factor must be equal to or greater than 80

for all piping tested. The calculated results are compared with those of previous tests to

identify adverse trends. A low "Cn factor (Quad Cities method) or a large pressure drop

(Dresden method) may be indicative of either fouling or leakage of the underground fire

mains.

(b) NUREG-1 801, XL.M27, "Program Description," states that the AMP (XI.M27) applies to

water-based FP systems that are tested in accordance with the applicable National Fire

Protection Association (NFPA) codes and standards.

The Dresden and Quad Cities fire water systems may not in all cases be tested in

accordance with NFPA codes, but in these cases, technical justifications for the

deviations are documented. NFPA codes were used in the design of active FP systems

(i.e., fire suppression and detection systems). Similarly, inspection and periodic testing

is performed in accordance with corporate and station procedures developed using

NFPA codes as guidance. Corporate Procedure ER-AA-610, "Performance Based

Evaluations for Fire Protection," ensures that performance-based evaluations that result

in surveillance frequencies that exceed those specified in site-specific NFPA codes of

record serve as the deviation justification. Where code deviations are required or

desirable, they are made under the intent of the code and documented in the NFPA

Code Deviation Report at each site in accordance with CC-AA-21 1, "Fire Protection

Program." Revision to the NFPA Code Deviation Report is necessary unless the report

has previously addressed the deviation.

(c) Interim staff guidance ISG-04 was issued on December 3, 2002. Included as part of

ISG-04 is an amended ten-element AMP, XL.M27, for the fire water system. Applicant

evaluated the Dresden and Quad Cities fire water system program against the staff

recommendations for fire water systems included in ISG-04 with the following

conclusions:

* In Element 3 of the amended XL.M27, the staff provides for the option of performing

wall thickness evaluations in lieu of testing at maximum design flow. The flow

testing discussed in (1)(a) is not performed at maximum design flow, but Dresden

and Quad Cities will perform wall thickness measurements.

* In Element 4 of the amended XL.M27, the staff recommends that the applicant

perform a baseline pipe wall thickness evaluation of the FP piping using a nonintrusive means of evaluating wall thickness, such as volumetric inspection, to detect

general corrosion before the current license term expires. The staff also

recommends that the applicant perform pipe wall thickness evaluations at plantspecific intervals during the period of extended operation. As an alternative to nonintrusive testing, the amended XL.M27 allows for a visual inspection of the internal

surface of the FP piping upon each entry to the system for routine or corrective

maintenance as long as it can be demonstrated that inspections are performed on a

representative number of locations on a reasonable basis.

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Dresden and Quad Cities will perform periodic non-inirusive FP piping wall thickness

measurements. These non-intrusive inspections will be conducted prior to the end

of the current term and repeated on a frequency not exceeding every 10 years.

Element 4 of the amended XL.M27 also states that if the environmental and material

conditions that exist on the interior surfaces of the below-grade FP piping are similar

to the conditions that exist within the above-grade piping, the results of the

inspections of the above-grade FP piping can be extrapolated to evaluate the

condition of below-grade piping.

The below-grade fire mains at both Dresden and Quad Cities comprise uncoated

carbon steel. The internal environment of the below-grade fire mains at both

Dresden and Quad Cities is "raw water," the same as NUREG-1 801 Reference

VII.G.6-a. Therefore, the results of the inspections of above-grade FP uncoated

carbon steel piping with a raw water environment can be extrapolated to evaluate to

the condition of the below-grade fire mains.

In Element 4 of the amended Xl.M27, the staff recommends, in accordance with

NFPA 25, that sprinkler head testing be performed at year 50 of the sprinkler system

service life, not year 50 of plant operation, with subsequent sprinkler head testing

every 10 years thereafter. Representative samples of Dresden and Quad Cities

sprinkler heads will be submitted to a testing laboratory prior to being in service 50

years. This testing will be repeated on a frequency not exceeding every 10 years.

The staff reviewed the applicant's response. On the basis of the justification provided, the staff

concurs that the aging of fire water system components will be adequately managed by the

AMP. In a letter dated August 4, 2003, the staff requested that the applicant clarify the flow

rates and testing frequencies of the underground loop flow tests and describe the plant

procedure for this testing.

(2) In a letter dated October 3, 2003, the applicant responded with additional details regarding

frequency and method of flow testing. Flow testing is conducted at five-year intervals at

Dresden and Quad Cities. As stated in Section (1)(a) of the applicant's response, tests are

not performed at the maximum design flow. By themselves, the absolute values of the

flows achieved during testing at both Dresden and Quad Cities provide no indication of the

condition of the underground fire mains. Utilizing the Dresden test procedure, test

conditions are established to provide flow rates within a pre-determined range

corresponding to a table of pre-calculated allowable pressure drops vs. flows. For the cross

tie flow test, these pre-determined flows range from 2,500 gpm to 3,500 gpm. For the yard

loop flow test, these pre-determined flows range from 900 gpm to 1,300 gpm.

The Quad Cities test procedure methodology ("C" factor) employs the installation of four

underwriter's playpipes on each of the three pipe segments to be tested. Sequential tests

are performed on each segment with one, two, three, and four playpipes flowing. Total

flows and "C" factors are calculated for each combination of flowing playpipes. For each

pipe segment, the "C" factors for each separate flow scenario are compared and the most

appropriate one is chosen. Since more accurate "C" factors are obtained when calculated

for higher flows, it is most likely that the one calculated for four flowing playpipes will be

chosen. During the last flow test performed at Quad Cities, the highest calculated flows for

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each of the three segments, each with four playpipes flowing, were 2,296 gpm, 2,562 gpm,

and 2,547 gpm.

The staff reviewed the applicant's response and on the basis of the additional technical data,

concurs that the frequency and method of testing adequately addresses NUREG-1 801, XL.M27,

Element 3.

Conclusions. On the basis of its review and audit of the applicant's program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. In addition, the staff has reviewed the

exceptions to the GALL program and finds that the applicant has demonstrated that the effects

of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3). The staff also reviewed the UFSAR Supplement for this AMP and finds that it

provides an adequate summary description of the program, as required by 10 CFR 54.21 (d).

Fire Protection Portions of Table 3.3-3 - Staff Evaluation Table for Dresden and Quad

Cities Auxiliary System Components Evaluated In the GALL Report

Component Group Aging EffectlMechanism AMP in GALL AMP in LRA Staff Evaluation

Report

Components in Loss material, due to Fire Protection B.1.1 8 - Fire Exception taken to

Gaseous Fire galvanic, general, pitting, Protection GALL on inspection

Suppression and crevice corrosion Program frequency of 18

System months under current

licensing basis rather

than six months as

recommended in Gall

(See Section B.1.18)

Components in Loss of material due to Fire Protection B.1.18 - Fire Exception taken to

Diesel Fire Pump general, pitting, and Protection GALL on trending of

Fuel System crevice corrosion, MIC, Program test results. (See

and biofouling Section B.1.18)

Components Doors Loss of material due to Fire Protection B.1.18 - Fire Exceptions taken to

and Barrier wear; hardening and Protection GALL on fire door at a

Penetration Seals shrinkage due to Program frequency of every

weathering operating cycle under

the current licensing

basis rather than the

bimonthly frequency

recommended in

GALL (See Section

B.1.18)

Components in Loss of material due to Fire Water System B.1.19 - Fire Consistent with

Water-Based Fire general pitting, crevice Water System GALLJISG (See

Protection and galvanic corrosion, Section B.1.19)

MIC, biofouling

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Component Group Aging Effect/Mechanism AMP In GALL AMP in LRA Staff Evaluation __ Report

Fire Baniers, Walls, Concrete cracking and Fire Protection and B.1.18 - Fire Exceptions taken to

Ceilings and Floors spalling due to freeze- Structures Protection Gall on concrete fire

in Fire Protection thaw, aggressive Monitoring Program banier inspection

chemical attack, and frequency of every five

reaction with aggregates; years under ACI

loss of material due to 349.3R-96. concrete

corrosion of embedded structures (See

steel Section B.1.18)

3.3.2.3.5 Fuel Oil Chemistry (B.1.21)

Summary of Technical Information in the Application. The applicant's Fuel Oil Chemistry

program is discussed in LRA Section B.1.21, "Fuel Oil Chemistry." The applicant states that

with enhancements, the program is consistent with the ten elements of aging management

program XL.M30, "Fuel Oil Chemistry," specified in NUREG-1 801 with exceptions. The

following enhancements and exceptions are identified in the LRA:

Enhancements

* The fuel oil chemistry program will provide for inspection of the fuel oil storage tank interiors

for corrosion during the regularly scheduled tank cleaning and the performance of

engineering evaluations in the event corrosion of the tank interiors is found. The applicant

stated that the enhancement is scheduled for implementation at Dresden and Quad Cities

prior to the period of extended operation.

Exceptions

* Corrosion mitigation activities are not performed for the Quad Cities Unit 1 underground fuel

oil storage tank because it is constructed of fiberglass.

* The Dresden and Quad Cities programs use ASTM D2709 as specified by ASTM D975 for

analysis of grades 1-D and 2-D fuel used at the stations.

* The Dresden and Quad Cities programs use ASTM D5452 as the preferred method of

analysis.

* Dresden and Quad Cities particulate tests utilize filters with a pore size of 0.8 pm instead of

3.0 pm because 0.8 pm filters provide conservative results. The applicant stated that the

use of 0.8 pm filters is consistent with use of ASTM D5452.

* Quad Cities does not add stabilizers because grade 1 -D low sulfur fuel oil is used and

stored fuel is periodically sampled and analyzed for quality. Dresden and Quad Cities do

not add corrosion inhibitors because fuel oil storage tank bottoms are periodically sampled

and analyzed for corrosion products in accordance with ASTM D4057 and ASTM D2709.

Dresden and Quad Cities employ sample techniques and particulate contamination

detection methods that identify fuel degradation or the presence of corrosion products at an

early stage.

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* Dresden and Quad Cities emergency diesel generator do not have the capability of being

sampled. As an alternative, Dresden and Quad Cities sample for water and sediment from

the bottom of the associated storage tanks quarterly and particulate from the fuel oil

transfer pump discharge line on a monthly basis in accordance with approved procedures.

The applicant does not perform multilevel sampling of other fuel oil day tanks (isolation

condenser makeup pump [Dresden only], fire pump, and station blackout) because the

tanks are small and experience a high turnover of fuel due to routine diesel engine

operations. Additionally, ASTM D4057, Table 4, "Spot Sampling Requirements," indicates

that multilevel sampling is not required for tanks with a capacity less than 42,000 gallons.

The fuel oil storage tanks and day tanks at Dresden and Quad Cities are 15,000 gallons or - smaller.

* At Dresden, the results of analysis of new fuel oil are reviewed for acceptability, but are not

trended. In the event the quantitative oil acceptance criteria in plant procedures are

approached or exceeded the fuel oil is restored to within limits or an action request or

condition report is initiated.

In LRA Section B.1.21 and UFSAR A.1.21, the applicant describes the fuel oil chemistry aging

management program as an existing aging management program that provides for preventive'

activities that manage the aging effects of loss of material and buildup of deposits in license

renewal components that are exposed to fuel oil. More specifically, the Fuel Oil Chemistry

program is credited together with the one-time inspection for managing the following aging

effects during the period of extended operation:

* loss of material due to general, pitting, crevice corrosion, MIC and biofouling

* buildup of deposits.

The applicant's operating experience includes a small number of events where plugging of

drain lines in fuel oil system low points was caused by sediment buildup. The applicant

determined that these events did not affect the ability of the associated diesel generator or fire

pump to perform its intended functions. In addition, Quad Cities experienced plugging of both

fuel filters on one diesel generator in 1998 for an indeterminate reason. The applicant states

that program activities assure that contaminant levels are maintained at acceptable levels in

fuel oil for systems within the scope of license renewal. The applicant credits biocide added to

the fuel oil storage tanks during each new fuel delivery and fuel oil sampling and analysis in

accordance with procedures. The acceptance criteria for analysis contained in the Technical

Specifications are based on the requirements of ASTM D975. The applicant also periodically

cleans and inspects diesel fuel oil storage tanks for evidence of internal corrosion.

In Section B.1.21 of the LRA, the applicant concludes that the fuel oil chemistry aging

management program provides reasonable assurance that the loss of material aging effects

are adequately managed so that the intended functions of components exposed to fuel oil

within the scope of license renewal are maintained during the period of extended operation.

Staff Evaluation. In LRA Section B.1.21, "Fuel Oil Chemistry," the applicant describes its AMP

to manage aging effects for loss of material and buildup of deposits in license renewal

components that are exposed to fuel oil. The LRA states that with enhancements the program

is consistent with the ten elements of aging management program XLI.M30, 'Fuel Oil

Chemistry," specified in NUREG-1801 with exceptions. The staff confirmed the applicant's

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claim of consistency during the AMR inspection. The staff revie'wed the UFSAR supplement to

determine whether it provides an adequate description of the revised program. The staff also

reviewed the exception and its justification to determine whether the AMP, with the exception,

remains adequate to manage the aging effects for which it is credited. Finally, the staff

determined whether the applicant properly applied the GALL program to its facility.

During its review, the staff determined that additional information was needed to complete its

review. By letter dated August 4, 2003, the staff requested, in RAI B.1.21, the applicant to

provide the following additional information:

For the second exception item, concerning the application of ASTM standards D1796 and

D2709, the staff identified that, based on a review of both standards, D2709 is appropriate for

D975 Grades 1 D and 2D fuel oil. Per D2709, D1796 is appropriate for higher viscosity fuel oil.

Therefore, the staff requested the applicant to provide a basis for the statement in the LRA,

UNUREG-1 801 indicates that ASTM D1 796 standard should be used to analyze fuel oil for water

and sediment,' and indicate whether this item constitutes an exception to GALL, or only a

clarification. In its response dated October 3,2003 the applicant stated that the second

exception should be deleted from the LRA aging management program B.1.21 (Fuel Oil

Chemistry). On the basis of its review, the staff finds the applicant's response acceptable

because the applicant acknowledged that the second exception quoted in the LRA should be

deleted from the LRA aging management program B.1.21 Fuel Oil Chemistry.

For the third exception item, concerning the use ASTM D5452 as the preferred method of

analysis the applicant was requested to clarify the origin of the fuel oil samples to be analyzed

and provide technical basis for the use of ASTM D5452 as the preferred method of analysis for

fuel oil content analysis. In its response dated October 3, 2003 the applicant stated that bottom

samples for particulates are collected and ASTM D5452 produces more accurate and

repeatable results than using a field monitor as described in ASTM D2276. The applicant also

stated that the tests methods for particulate contamination per ASTM D5452 is referenced by

ASTM D2276 for situations where it is not possible to take field monitor samples. On the basis

of its review, the staff finds that the applicant's response acceptable because there is

reasonable assurance that laboratory sample preparation and testing per ASTM D5452

produces more accurate and repeatable test results than using a field monitor as described in

ASTM D2276 by line sampling.

For the fifth exception item, concerning the use of periodic sampling in lieu of adding stabilizers

and corrosion inhibitors to diesel fuel oil, the applicant was requested to justify that the periodic

sampling is representative. In its response dated October 3, 2003, the applicant clarified that

bottom samples are collected from the underground fuel oil storage tank in accordance with

Dresden and Quad Cities fuel oil sampling procedures. The applicant stated that Quad Cities

and Dresden fuel oil inspection procedures meet the requirements of ASTM D4057 and ASTM

D2709. Underground storage tank fuel oil quality testing (water, sediment and bacteria) is

performed quarterly while particulate contamination (evidence for corrosion products) is

performed on a monthly basis. Samples taken at or near the bottom of the tanks provide early

detection for contamination since any water, sediment or particulates would settle towards the

tank bottom. The applicant concluded that these samples provide the 'worse case' indication

for identifying contamination. On the basis of its review, the staff finds the applicant's response

acceptable because there is reasonable assurance that samples taken at or near the bottom of

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the tanks provide early detection for contamination since any water, sediment or particulates

would settle towards the tank bottom.

For the sixth exception item, concerning the inability to directly sample the emergency diesel

generator fuel oil day tanks the applicant was requested to provide justification as to why the

day tanks are not sampled. In its response dated October 3, 2003, the applicant stated that the

diesel fuel oil day tanks do not have provisions for taking direct fuel samples. The applicant

identified that monthly underground storage tank sampling, periodic transfer pump discharge

line sampling, and monthly drainage of accumulated water from the day tanks have proven

effective in maintaining quality fuel oil to the diesel engines. In addition, the applicant stated

that neither station has an operating history of diesel engine in-operability attributed to

contaminated fuel. The applicant also stated that, Dresden (as part of the Dresden Diesel

Generator Surveillance Tests) meets the guidance in Regulatory Guide 1.137 and EPRI NP6314 by removing any accumulated water from the day tanks on a monthly basis or following

engine operation (greater than or equal to one hour) via the day tank drains. Quad Cities (as

part of the Quad Cities Diesel Generator Surveillance Tests) meets the guidance in Regulatory

Guide 1.137 and EPRI NP-6314 by removing any accumulated water from the day tanks on a

monthly basis or following engine operation (greater than or equal to one hour) by draining the

day tank to the underground fuel oil storage tank. Sampling of the underground fuel oil storage

tank is then used to detect the presence of water. On the basis of its review, the staff finds the

applicant's response acceptable because the applicant's alternative method to sample the day

tanks provides reasonable assurance that contaminated fuel in the day tanks will be detected

and there is no prior history of diesel engine in-operability attributed to contaminated fuel.

In the last exception, the applicant states that, at Dresden, the results of analysis of new fuel oil

are reviewed for acceptability, but are not trended. The applicant was requested address how

the timely detection of the conditions conducive to corrosion will be taken before the

quantitative oil criteria is approached or exceeded. The applicant response dated October 3,

2003, stated that new fuel oil analysis results are not trended but are reviewed for acceptability,

applies to the receipt of new fuel oil deliveries only. The applicant identified that oil samples of

existing fuel oil are taken quarterly and the test results are evaluated and trended. On the

basis of its review, the staff finds the applicant's response acceptable because the applicant

has clarified that the statement, "new fuel oil analysis results are not trended but are reviewed

for acceptability," applies to the receipt of new fuel oil deliveries only.

LRA AMP B.1.21 indicates that the diesel fuel oil storage tanks are periodically cleaned and

inspected for evidence of internal corrosion and that an enhancement will provide for inspection

of the fuel oil storage tank interiors. Section 3.3.1.1.8 also indicates that UT examination of the

lower portion will be performed. The applicant was requested to provide information that

provides more specific UT locations, the inspection interval and operating history. In its

response dated October 3, 2003, the applicant specified that an UT examination of the lower

portion of one carbon steel underground fuel oil storage tank and one day tank at each facility

will be performed prior to the period of extended operation and specific UT locations will be

defined at that time. The results of the UT's will be evaluated, corrective action if required

taken and the need for further UT's will be assessed. The applicant further stated that the

draining, cleaning and inspection of the underground fuel oil storage tank interiors is conducted

at ten (10) year intervals. The applicant identified that, to date, no tank wall aging degradation

has been identified. On the basis of its review, the staff finds the applicant's response

acceptable because the applicant has specified that UT examination of the lower portion of one

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carbon steel underground fuel bil storage tank and one day tank at each facility will be

performed prior to the period of extended operation and the applicant has committed to the

draining, cleaning and inspecting the underground fuel oil storage tank interiors at ten (10) year

intervals. Specific UT locations will be defined later. This is Commitment #21 in Appendix A of

this SER.

The UFSAR supplement does not include criteria for fuel monitoring identified in LRA AMP

B.1.21, such as specific ASTM standards. For example, specific ASTM standards are identified

in NUREG-1 800 Table 3.3-2. The applicant was requested to submit a revised UFSAR

supplement which includes specific ASTM standards applied in AMP B.1.21. In its response

dated October 3, 2003, the applicant submitted a revised UFSAR supplement to include

specific ASTM standards. On the basis of its review, the staff finds the applicant's response

acceptable because the applicant has revised the UFSAR supplement A.1.21 Fuel Oil

Chemistry to reflect consistency between the AMP and the UFSAR.

LRA AMP B.1.21 identifies operating experience which includes plugging of fuel filters and drain

lines. This operating experience suggests that the fuel oil chemistry program was not effective

in preventing or detecting contamination and corrosion products at an early stage. The

applicant was requested to indicate what corrective actions have been implemented to prevent

recurrence of these events. In addition, the applicant was requested to indicate if filters and

strainer elements in the fuel oil system are periodically inspected to further assess the

effectiveness of the fuel oil chemistry program. In its response dated October 3, 2003, the

applicant considered the flow blockage events to be isolated incidents and concluded that

system testing confirms the adequacy of the fuel oil inspection and testing in maintaining

system functions. In addition, as part of the diesel surveillance testing, the applicant identified

that fuel oil supply pressure and fuel oil filter discharge pressure are recorded and trended thus

providing indication of the performance of the fuel filters and strainers. The applicant stated

that readings outside the nominal range are brought to the attention of the System Engineer for

evaluation. On the basis of its review, the staff finds the applicant's response acceptable

because the system testing and operating history provide reasonable assurance that the fuel oil

inspection and testing practices are effective in maintaining system functions.

The staff finds the applicant's response to RAI B.1.21 provided sufficient technical justification

to show that the program, with exceptions and enhancements, will adequately manage the

aging effects for which the program is credited. All technical concerns associated with RAI

B.1.21 are considered resolved.

The applicant committed to revise UFSAR Supplement, Section A.1.2.1, as described in its

response to RAI B.1.21 part (g). The staff reviewed this revised UFSAR supplement and found

that the description of the Fuel Oil Chemistry program is consistent with Section B.1.21 of the

LRA. The staff finds that the information provided in the UFSAR supplement provides an

adequate summary of the program activities as required by 10 CFR 54.21 (d).

Conclusions. On the basis of its review and audit of the applicants program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. In addition, the staff has reviewed the

exceptions to the GALL program and finds that the applicant has demonstrated that the effects

of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB during the period of extended operation, as required by 1 0 CFR

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54.21 (a)(3). The staff also reviewed the UFSAR supplement for this AMP and finds that it

provides an adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.3.2.3.6 Boraflex Monitoring (B.1.36)

Summary of Technical Information in the Application. The applicant's Boraflex monitoring

program is discussed in LRA Section B.1.36, "Boraflex Monitoring (Quad Cities Only)." The

applicant stated that the program is consistent with the GALL Program XL.M22 'Boraflex

Monitoring," with no deviations. The applicant stated that its AMP is based on EPRI TR108761, "A Synopsis of the Technology Developed to Address the Boraflex Degradation Issue."

The Boraflex Monitoring program is only applicable to Quad Cities because Dresden utilizes

Boral as the neutron absorbing material in the spent fuel racks rather than Boraflex.

boraflex degrades when exposed to chemically-treated oxygenated water and gamma radiation.

The degradation results in a loss of boron carbide and a reduction in the neutron-absorbing

capacity of the Boraflex. This AMP is credited with managing the degradation.

Under "Operating Experience," the stated that past inspections under the Boraflex Monitoring

program have been effective at determining boron loss. The applicant stated that, to date, a

boron loss of approximately one percent has been identified and trended, and that a review of

the program resulted in updating the RACKLIFE program every two years to be consistent with

the maintenance rule requirements.

The applicant concludes that the Quad Cities Boraflex monitoring program provides reasonable

assurance that the aging effects are adequately managed so that the 5% subcriticality margin in

the spent fuel pool will be maintained during the period of extended operation.

Staff Evaluation. In LRA Section B.1.36, 'Boraflex Monitoring (Quad Cities Only)," the applicant

described its AMP to manage the effects of aging on Boraflex. The LRA stated that this AMP is

consistent with the GALL AMP XL.M22 "Boraflex Monitoring,' with no exceptions. The staff

confirmed the applicant's claim of consistency during the AMR inspection. In addition, for the

Quad Cities plant, the staff determined whether the applicant properly applied the GALL

program to its facility. The staff also reviewed the UFSAR supplement to determine whether it

provides an adequate description of the program.

The Boraflex monitoring AMP consists of (1) neutron attenuation testing (blackness testing) to

determine gap formation, (2) sampling for the presence of silica in the spent fuel pool (which

accompanies the loss of boron carbide), and (3) analysis of criticality to assure that the required

5% subcriticality margin is maintained. This program is implemented in response to Generic

Letter 96-04, uBoraflex Degradation in Spent Fuel Pool Storage Racks." The Boraflex

monitoring activities are based on the maintenance rule and on EPRI TR-1 08761, "A Synopsis

of the Technology Developed to Address the Boraflex Degradation Issue."

The staff noted that GALL AMP XI.M22 states that trending of the results from the silica

analysis in the spent fuel pool water using the EPRI RACKLIFE predictive code (or its

equivalent) is performed on a monthly, quarterly, or annual basis (depending on the Boraflex

panel condition). However, in Section B.1.36 of the LRA, the applicant stated that the

evaluation is performed every two years. By RAI B.1.36, the staff asked the applicant to clarify

this statement and provide the technical basis for this apparent divergence from the guidelines

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in the GALL Report. In its response dated October 3, 2003, the 'apblicant stated that the silica

levels in each spent fuel pool are measured by Quad Cities' chemistry department on a weekly

basis and this weekly data is subsequently used as an input into the EPRI RACKLIFE program.

The applicant further stated that RACKLIFE has previously been run in conjunction with the

units' outage schedules (once every two years), which is within the guidance of the RACKLIFE

manual, "Guidance and Recommended Procedures for Maintaining and Using RACKLIFE

Version 1.10," published by EPRI in April 2002. However, since Quad Cities must move spent

fuel from one pool to another to make room for refueling outage activities on either unit, and

since RACKLIFE is updated whenever fuel is moved, the actual update frequency for

RACKLIFE for each spent fuel pool is approximately three times every two years. The applicant

changed the AMP to state that the evaluation is performed on an annual basis to reflect this

and to ensure compliance with GALL XI.M22. On the basis of its review, the staff finds that the

applicant's response to RAI B.1.36 adequate and acceptable because the applicant has verified

that the silica level measurements and the evaluation are performed on a frequency consistent

with GALL AMP XI.M22.

The staff reviewed the UFSAR supplement in LRA Appendix A.1.36 and found that the

description of the Boraflex monitoring is consistent with Section B.1.36 of the LRA. The staff

finds that the information provided in the UFSAR supplement provides an adequate summary of

the program activities as required by 10 CFR 54.21 (d).

Conclusions. On the basis of its review and audit of the applicant's program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. Since the GALL program is acceptable to the

staff, the applicant has demonstrated that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB during the period of

extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR

supplement for this AMP and finds that it provides an adequate summary description of the

program, as required by 10 CFR 54.21 (d).

3.3.2.3.7 Periodic Inspection of Plant Heating System (B.2.8)

Summary of Technical Information in the Application

The applicant's Periodic Inspection of Plant Heating System program is discussed in the

applicant's response to RAI B.1.23, dated March 25, 2004. This program inspects selected

components in the Dresden and Quad Cities Plant Heating System exposed to an environment

of saturated steam and condensate once before the end of the current operating term and

periodically at intervals of approximately every 5 years during the period of extended operation.

The program will include inspections for cracking, loss of material, or other evidence of aging

for plant heating system components that are within the scope of license renewal. The program

is not based on a GALL report program; therefore, the applicant summarized the program in

terms of the 10-element program as described in Branch Technical Position, RLSP-1 in

Appendix A of the SRP-LR.

The applicant concluded that the Periodic Inspection of Plant Heating System program provides

assurance that plant heating system components are routinely inspected for deterioration and

leakage, and will adequately manage the components aging effects. The applicant stated that

the program provides reasonable assurance that intended functions are maintained consistent

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with the current licensing basis during the period of extended operation. The staff compared

the program against BTP RLSB-1. This issue was identified as Confirmatory Item B.1.23-2.5.

Staff Evaluation

By letter dated March 25, 2004, the applicant described its program to manage loss of material,

cracking, and leakage in selected plant heating system components for Dresden and Quad

Cities exposed to an environment of saturated steam and condensate. The staff reviewed this

program using the guidance in Branch Technical Position RLSB-1 in Appendix A of the SRP-LR

and focused on how the program manages aging effects through the effective incorporation of

the following 10 elements: program scope, preventive actions, parameters monitored or

inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective

actions, confirmation process, administrative controls, and operating experience. The applicant

indicated that the corrective actions, confirmation process, and administrative controls are part

of the site-controlled Quality Assurance Program. The staff's evaluation of the Quality

Assurance Program is provided separately in Section 3.0.4 of this SER. The remaining seven

elements are discussed below. The staff also reviewed the UFSAR supplements for Dresden

and Quad Cities to determine whether they provide an adequate description of the program.

[Program Scope] The program will manage age related degradation of plant heating system

components such as filter/strainer housings, piping and fittings, pump casings, sight glasses,

tanks, thermowells, traps, tubing, and valves. The staff finds that the scope is acceptable

because it includes those components that rely on the program for aging management.

[Preventive or Mitigative Actions] The plant heating system periodic inspections do not provide

any preventative actions. The inspections provide for condition monitoring to detect

degradation prior to a loss of function. Preventative or mitigative actions are not needed for this

condition monitoring program; therefore, the staff finds this acceptable.

[Parameters Monitored or Inspected] Visual inspections will be performed on a representative

sample of brass or bronze valves, carbon steel piping and fittings, cast iron filter housings,

pump casings and valves, and stainless steel thermowells and tubing used in the plant heating

systems to determine if aging degradation is occurring. The components are inspected to

ensure they are free of cracking, loss of material, and leakage. The inspection will consist of a

visual inspection on the internal surface of components for the presence of general, crevice,

galvanic, and pitting corrosion. The staff concludes that the applicant is inspecting the

appropriate parameters to identify the aging effects; therefore, the staff finds this acceptable.

[Detection of Aging Effects] The plant heating inspections are performed a periodic intervals,

and they detect aging prior to the equipment leaking so as to prevent spatial interaction with

safety-related equipment. Inspections will be performed in accordance with ASME Code

requirements and certified NDE examiners will conduct a VT-3 visual examination. The staff

finds this acceptable because the inspections will identify the aging effects managed by this

program.

[Monitoring and Trending] The condition of the components used in plant heating systems are

monitored at intervals of approximately every 5 years, but not trended. Components are

replaced if damage or unacceptable leakage is detected. Operating experience states that

leaks were identified and corrected in a timely manner and did not result in a loss of function of

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any safety-related component. Staff finds that monitoring of these components periodically

every 5 years is adequate to identify aging degradation; therefore staff finds this acceptable .

[Acceptance Criteria] The applicant stated that components are inspected for cracking, loss of

material, and leakage. The components are replaced if a degraded condition is found.

Inspections will be performed in accordance with ASME Code requirements and corrective

actions state that evaluations are performed for inspection results that do not satisfy

established criteria. The staff finds that the applicant's proposal to perform inspections in

accordance with ASME Code requirements and use of engineering evaluations of degradation

components will provide acceptance criteria against which the need for corrective actions will be

evaluated; therefore, staff finds this acceptable.

[Operating Experience] The applicant stated that Dresden and Quad Cities have experienced

leaks in the plant heating systems, but that these leaks were identified and corrected in a timely

manner and did not result in a loss of function of any safety-related system, structures, or

components. The staff notes that the plant heating system is in scope of license renewal due to

the potential for spatial interactions. The staff finds that the operating experience of timely

correction of system leaks plus the additional periodic visual inspections supports the

applicant's conclusion that the program will be effective in managing aging of the components

in the scope of this program; therefore, the staff finds this acceptable.

Therefore Confirmatory Item B.1.23-2.5 is closed.

Conclusion

On the basis of its review of the applicant's program, the staff finds that the program adequately

addresses the ten program elements defined in Branch Technical Position RLSB-1 in Appendix

A.1 of the SRP-LR, and that the program will adequately manage the aging effects for which it

is credited. The staff also reviewed the UFSAR supplement (Dresden and Quad Cities) for this

aging management program and finds that it provides an adequate summary description of the

program, as required by 10 CFR 54.21 (d).

Therefore, on the basis of its review, the staff finds that the applicant has demonstrated that the

effects of aging will be adequately managed by the Periodic Inspection of Plant Heating System

program so that the intended functions will be maintained consistent with the CLB for the period

of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.4 Aging Management Review of Auxiliary Systems

The following sections provide the results of the staff's evaluation of the adequacy of aging

management for components in each of the auxiliary systems.

3.3.2.4.1 Refueling Equipment System

Summary of Technical Information in the Application. The description of the refueling

equipment can be found in Section 2.3.3.1.1 of this SER. The passive, long-lived components

in this system that are subject to an AMR are identified in LRA Table 2.3.3-1. The components,

aging effects, and AMPs are provided in LRA Table 3.3-2.

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Aging Effects

Table 2.3.3.1.1 of the LRA lists individual system components within the scope of license

renewal and subject to an AMR. The component groups in this category in the refueling

equipment system listed by the applicant in the LRA are cranes, including bridge and trolleys,

and the rail system in the load handling system; fuel grapples/structural support; fuel pool

gates/pressure boundary; and fuel preparation machines/structural support.

The LRA identified the following applicable aging effects for the refueling equipment:

* Carbon steel components are identified as being subject to loss of material due to general

corrosion and wear from exposure to air at 100 percent relative humidity and a temperature

of 49 0C (120 OF).

* Stainless steel components are identified as being subject to loss of material due to pitting

and crevice corrosion from exposure to chemically treated oxygenated water.

* Aluminum components are identified as being subject to loss of material due to general and

pitting corrosion from exposure to chemically treated oxygenated water.

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the

refueling equipment:

* Water Chemistry Program (B.1.2)

* Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling

Systems Program (B.1.15)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the refueling equipment system will

be adequately managed by these AMPs during the period of extended operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects and the AMPs credited for managing the aging effects in refueling

equipment. The staff also reviewed the applicable UFSAR Supplements for the AMPs to

ensure that the program descriptions adequately describe the AMPs.

Aging Effects

The staff reviewed the information in Section 2.3.3.1 and Tables 2.3.3-1 and 3.3-2 in the LRA.

During its review, the staff determined that additional information was needed.

Table 3.3-2, Reference No. 3.3.2.74 in the LRA identifies the loss of material due to pitting

corrosion for stainless steel components in a chemically treated oxygenated water environment.

It does not, however, identify crack initiation and growth due to SCC as a plausible aging

effect/mechanism even though the same environmental conditions generally exist for pitting

corrosion as for SCC. By letter dated August 4, 2003, the staff requested, in RAI 3.3.2.4.1, the

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applicant to provide a justification for excluding crack initiation and growth due to SCC as an

aging effect/mechanism that requires management for the period of extended operation.

In its response dated October 3, 2003, the applicant stated that the cracking aging effect is

discussed in EPRI 1003056, "Non-Class 1 Mechanical Implementation Guideline and

Mechanical Tools, Revision 3," Appendix A, Section 3.2.2, uStress Corrosion Cracking (SCC) of

Stainless Steel in Fuel Storage and Handling Equipment." The applicant further stated that this

aging effect has not been detected by industry experience or by actual site operating

experience. SCC tendency increases with temperature applications greater than 60 'C

(140 'F) and the introduction of chlorides (in excess of permissible limits). This is the

uppermost limit for long-term operating temperature in the spent fuel pool (because higher

operating temperatures are detrimental to fuel pool cooling system demineralizer resin).

The applicant concluded that as such, crack initiation and growth due to SCC was not

considered a credible aging effect/mechanism.

On the basis of its review, the staff finds the applicant's response acceptable because the

applicant has shown that this cracking aging effect has not been detected by industry

experience or by actual site operating experience and that the uppermost limit for long-term

operating temperature in the spent fuel pool is 60 'C (140 'F).

Metals and alloys that are in contact with different, more cathodic metals or alloys in the

presence of an electrolyte fluid may be subject to the aging effect of loss of material from

galvanic corrosion. Many systems/components of the auxiliary systems described by various

items in Table 3.3-2 of the LRA have materiaVenvironment combinations to which loss of

material from galvanic corrosion may be an applicable aging effect/mechanism. However, the

applicant does not include loss of material due to galvanic corrosion as an aging

effect/mechanism that requires management for the period of extended operation. By letter

dated August 4, 2003, the staff issued RAI 3.3-1 pertaining to this issue. The staff's evaluation

of the applicant's response is documented in Section 3.3.2.5.1 of this SER.

The aging effects identified in the LRA for the refueling equipment system are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible the aging effects were identified and that the aging effects listed are appropriate

for the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the refueling equipment system.

* Water Chemistry Program (Section 3.0.3.2)

* Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling

Systems Program (Section 3.3.2.3.1)

The Water Chemistry Program is credited with managing the aging effects of several

components in different structures and systems and is, therefore, considered a common AMP.

The staff's evaluation of this AMP is discussed in Section 3.0.3.2 of this SER.

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The Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling

Systems Program is only credited with managing the aging effects of the refueling equipment

system components. The staff has evaluated this AMP and found it to be acceptable for

managing the aging effects identified for this system. The staff's evaluation of this AMP is

discussed in Section 3.3.2.3.1 of this SER.

After evaluating the applicant's AMR for each of the components in the refueling equipment

system, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects for this system. For those components identified in Table

3.3-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by the

GALL Report. For the components identified in LRA Table 3.3-2, the staff verified that the

applicant credited AMPs that are appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the refueling

equipment system will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.2 Shutdown Cooling System (Dresden Only)

Summary of Technical Information in the ADolication. The description of the shutdown cooling

system (Dresden only) can be found in Section 2.3.3.2 of this SER. The passive, long-lived

components in this system that are subject to an AMR are identified in LRA Table 2.3.3-2. The

components, aging effects, and AMPs are provided in LRA Tables 3.1-1, 3.3-1, and 3.3-2.

Aging Effects

Table 2.3.3-2 of the LRA lists individual system components within the scope of license renewal

and subject to an AMR. The components include closure bolting, dampeners, filters/strainers,

heat exchangers (heat exchanger components), NSR vents or drains, piping, piping and fitting

pumps, restricting orifices, sight glasses, thermowells, and valves.

Stainless steel components in an air, moisture, and humidity environment experience no aging

effects. Copper-nickel heat exchanger components exposed to reactor coolant water are

subject to the aging effects of fatigue and cracking due to SCC. Carbon steel heat exchanger

components exposed to reactor coolant water or closed-cycle cooling water are subject to the

aging effects of loss of material due to general, galvanic, pitting, crevice, flow-accelerated, and

microbiologically influenced corrosion and wear. Stainless steel heat exchanger components

exposed to reactor coolant water or closed-cycle cooling water are subject to the aging effects

of fatigue and cracking due to SCC. Heat exchanger components are also subject to the aging

effect of loss of heat transfer function due to buildup of deposit and fouling. Carbon steel,

stainless steel, brass, or bronze components of the NSR drains, piping, and valves exposed to

air, moisture, and leaking fluid environments are subject to the aging effect of loss of material

due to corrosion. Carbon steel components exposed to containment nitrogen experience no

aging effects. Stainless steel components exposed to a saturated air environment are subject

to loss of material due to pitting and crevice corrosion. Stainless steel components exposed to

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air, moisture, and humidity or containment nitrogen environments experience no aging effects.

Sight glass in a wet gas environiment experiences no aging effects. Several carbon steel and

stainless steel components are also subject to fatigue.

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the

shutdown cooling system (Dresden only):

* Water Chemistry Program (B.1.2)

* BWR Stress Corrosion Cracking Program (B.1.7)

* Flow-Accelerated Corrosion Program (B.1.1 1)

* Bolting Integrity Program (B.1.12)

* Closed-Cycle Cooling Water System Program (B.1.14)

* Compressed Air Monitoring Program (B.1.16)

* One-Time Inspection Program (B.1.23)

* Structures Monitoring Program (B.1.30)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the shutdown cooling system will be

adequately managed by these AMPs during the period of extended operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, on

components in the shutdown cooling system. The staff also reviewed the applicable UFSAR

Supplements for the AMPs to ensure that the program descriptions adequately describe the

AMPs.

Aging Effects

The staff reviewed the information in Section 2.3.3.2, Table 2.3.3-2, and Tables 3.3-1, 3.3-2,

and 3.1-1 in the LRA. During its review, the staff determined that additional information was

needed.

Metals and alloys that are in contact with different, more cathodic metals or alloys in the

presence of an electrolyte fluid may be subject to the aging effect of loss of material from

galvanic corrosion. Many systems/components of the auxiliary systems described by various

items in Table 3.3-2 of the LRA have materiaVenvironment combinations to which loss of

material from galvanic corrosion may be an applicable aging effect/mechanism. However, the

applicant does not include loss of material due to galvanic corrosion as an aging

effect/mechanism that requires management for the period of extended operation. By letter

dated August 4, 2003, the staff issued RAI 3.3-1 pertaining to this issue. The staff's evaluation

of the applicant's response is documented in Section 3.3.2.5.1 of this SER.

The description in item 3.3.2.130 of Table 3.3-2 lists loss of material/corrosion as an aging

effect/mechanism for carbon steel, stainless steel, brass, or bronze components in an

environment of air, moisture, humidity and leaking fluid. However, the LRA does not

specifically identify which type of corrosion is responsible for the loss of material. The type of

corrosion is important because it determines the susceptible locations to be inspected. By letter

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dated August 4, 2003, the staff requested, in RAI 3.3-2, the applicant to provide a specific

description of the types of corrosion responsible for the aging effect of loss of material for the

relevant components, as well as the criteria for selecting these samples, including susceptible

locations for inspections. The staff's evaluation of the applicant's response is documented in

Section 3.3.2.5.2 of this SER.

Carbon steel, stainless steel, brass, and bronze components exposed to moist gas (moist

nitrogen) or a moist air environment may experience the aging effect of loss of material due to

general (for carbon steel only), pitting, and crevice corrosion (for both carbon steel and

stainless steel) when pollutants such as oxygen, SO2, NOx, or CO are present in the moist air,

particularly when the humidity is greater than 60 percent. However, in Table 3.3-2, the

applicant concluded that no aging effects were identified for the external surfaces of the carbon

steel and stainless steel piping and fittings, accumulators, dampeners, filters/strainers, flow

elements, pumps, orifices, rupture discs, tanks, tubing, and valves exposed to either the

containment nitrogen gas environment or an air, moisture, and humidity environment because

these components are not subject to any viable aging mechanism in the absence of aggressive

chemical species. By letter dated August 4, 2003, the staff issued RAI 3.3-3 requesting the

applicant to provide information to justify the conclusions in Table 3.3-2, Reference Nos.

3.3.2.27 and 3.3.2.40, as to whether pollutants such as oxygen, NOX, SO2 or CO are present,

and if so, to what extent, in the containment gas or air, moisture, and humidity environments.

The staff's evaluation of the applicant's response is documented in Section 3.3.2.5.3 of this

SER.

Aluminum and aluminum alloys components may experience general, pitting, and crevice

corrosion when exposed to moisture and humidity environments, especially with the presence

of contaminants and water (condensation from moist air). However, AMR Reference No.

3.3.2.126 of Table 3.3-2 of the LRA only identifies loss of material due to general and pitting

corrosion as a plausible aging effect for aluminum components exposed to moist air. In Table

3.3-2, Reference No. 3.3.2.21 of the LRA, the applicant concluded that there is no aging effect

on aluminum components of the air handlers heating/cooling system exposed to an air,

moisture, and humidity environment. By letter dated August 4, 2003, the staff requested, in RAI

3.3-4, the applicant to (1) explain the different conclusions on aging effects described above,

(2) provide the technical basis for not including loss of material due to crevice corrosion as an

applicable aging effect, and (3) clarify if there is any condensate on the aluminum fins of the

cooling coils. The staff's evaluation of the applicant's response is documented in Section

3.3.2.5.4 of this SER.

In LRA Table 3.3-2, the applicant indicated that the stainless steel valves in the shutdown

cooling system are exposed to saturated air and are subject to the aging effect of loss of

material due to pitting and crevice corrosion. The staff finds that valves are the only component

type that are identified as exposed to a saturated air environment in the shutdown cooling

system. By letter dated August 4, 2003, the staff requested, in RAI 3.3.2.4.2, the applicant to

provide clarification as to whether there are any other associated components, such as piping,

pipe fittings, tubing, and tube fittings, in the shutdown cooling system that may be exposed to

the same environment and hence subject to the same aging effects. If so, the staff asked the

applicant to specify the applicable AMPs.

In its response dated October 3, 2003, the applicant stated that valves are the only component

type that was identified as exposed to a saturated air internal environment in the shutdown

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cooling system. The reason for this is that the shutdown cooling valves in this group are 2-

1 099-X1 11 A & B for Dresden Unit 2 and 3-1 099-X1 11 A & B for Dresden Unit 3. These valves

are utilized when local leak rate testing of the shutdown cooling system primary containment

penetrations X-1 1 1A and B is conducted. The penetrations are shown on boundary diagrams

LR-DRE-M-32 (coordinate C-9) and LR-DRE-M-363 (coordinate C-9), but the level of detail of

this diagram does not include the valves. There are piping and fittings connecting these valves

to the penetrations. These piping and fittings are included in LRA Table 2.3.2-3 under

component group, Isolation Barriers (including piping, tubing, valves and vacuum breakers),"

and the component intended function of "Pressure Boundary." The Aging Management

Reference is 3.2.2.52. Valves 2(3)-1 099-X11 1 A & B should have been included in LRA Section

2.3.2.3, "Containment Isolation Components and Primary Containment Piping System," in Table

2.3.2-3, under the component group, "Isolation Barriers (including piping, tubing, valves and

vacuum breakers)," along with the other test valves utilized for local leak rate testing of

containment penetrations.

On the basis of its review, the staff finds the applicant's response acceptable because the

components exposed to saturated air connecting to these valves are included and reviewed in

LRA Table 2.3.2-3 under component group, "Isolation Barriers (including piping, tubing, valves

and vacuum breakers)," and the Aging Management Reference is 3.2.2.52. The staff considers

the issues related to RAI 3.3.2.4.2 to be resolved.

The aging effects identified in the LRA for the shutdown cooling system (Dresden only) are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible the aging effects were identified and that the aging effects listed

are appropriate for the combination of materials and environments specified.

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the

shutdown cooling system (Dresden only).

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* Closed-Cycle Cooling Water System Program (Section 3.0.3.7)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* Structures Monitoring Program (Section 3.0.3.14)

These AMPs are credited for managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. The staff's evaluation of these

AMPs is documented in Sections 3.0.3.2, 3.0.3.3, 3.0.3.4, 3.0.3.5, 3.0.3.7, 3.0.3.8, 3.0.3.10,

and 3.0.3.14, respectively, of this SER.

After evaluating the applicant's AMR for each of the components in the shutdown cooling

system, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects for this system. For those components identified in

Tables 3.1-1 and 3.3-1 of the LRA, the staff verified that the applicant credited the AMPs

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recommended by the GALL Report. For the components identified in LRA Table 3.3-2, the staff

verified that the applicant credited AMPs that are appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the shutdown

cooling system will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.3 Control Rod Drive Hydraulic System

Summary of Technical Information in the ApDlication. The description of the control rod drive

hydraulic system can be found in Section 2.3.3.3 of this SER. The passive, long-lived

components in this system that are subject to an AMR are identified in LRA Table 2.3.3-3. The

components, aging effects, and AMPs are provided in LRA Tables 3.1-2, 3.3-1, and 3.3-2.

Aging Effects

Components of the control rod drive hydraulic system are described in Section 2.3.3.3 of the

LRA as being within the scope of license renewal and subject to an AMR. Table 2.3.3-3 lists

individual components of the system including accumulators, closure bolting, dampeners,

filters/strainers, flow elements, NSR vents or drains, piping and fitting, piping and fitting

(attached supports), pumps, restricting orifices, rupture discs, tanks, tubing, and valves.

Stainless steel components exposed to the dry gas environment experience no aging effects.

Stainless steel accumulators, dampeners (Quad Cities only), filters/strainers, flow elements

(Dresden only), piping and fittings (includes dampeners and tubing), pumps (Dresden only),

restricting orifices (Dresden only), rupture discs, tanks (includes accumulators), tubing, and

valves exposed to an air, moisture, and humidity environment experience no aging effects.

Carbon steel, stainless steel, brass, or bronze NSR vents or drains, piping, and valves exposed

to an air, moisture, and humidity environment or leaking fluid are subject to the aging effect of

loss of material due to corrosion. Stainless steel piping and fittings (includes dampeners and

tubing) exposed to containment nitrogen experience no aging effects. Stainless steel

filters/strainers, piping and fittings (includes dampeners and tubing), tanks, and valves exposed

to oxygenated water up to 288 0

C (550 OF) are subject to the aging effects of loss of material

due to pitting and crevice corrosion and cracking due to SCC. Stainless steel and carbon steel

piping and fittings (includes dampeners and tubing) and valves exposed to saturated air are

subject to the aging effect of loss of material due to general (carbon steel only), crevice, and

pitting corrosion. Stainless steel and carbon steel piping and fittings, tanks, and valves

exposed to wet gas are subject to the aging effect of loss of material due to general (carbon

steel only), pitting, and crevice corrosion. Stainless steel tubing and rupture discs exposed to

dry gas experience no aging effects. Copper, brass, or bronze tubing and valves exposed to

saturated air are subject to the aging effect of loss of material due to pitting and crevice

corrosion. Brass or bronze valves exposed to an environment of air, moisture, and humidity

less than 100 0C (212 OF) experience no aging effects.

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Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the control

rod drive hydraulic system:

* Water Chemistry Program (B.1.2)

* Bolting Integrity Program (B.1.12)

* Compressed Air Monitoring Program (B.1.16)

* BWR Stress Corrosion Cracking Program (B.1.7)

* One-Time Inspection Program (B.1.23)

* Structures Monitoring Program (B.1.30)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the control rod drive hydraulic

system will be adequately managed by these AMPs during the period of extended operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, on

components in the control rod drive hydraulic system. The staff also reviewed the applicable

UFSAR Supplements for the AMPs to ensure that the program descriptions adequately

describe the AMPs.

Aging Effects

The staff reviewed the information in Section 2.3.3.3, Table 2.3.3-3, and Tables 3.3-1, 3.3-2,

and 3.1-2 in the LRA. During its review, the staff determined that additional information was

needed.

Metals and alloys that are in contact with different, more cathodic metals or alloys in the

presence of an electrolyte fluid may be subject to the aging effect of loss of material from

galvanic corrosion. Many systems/components of the auxiliary systems described by various

items in Table 3.3-2 of the LRA have materiaVenvironment combinations to which loss of

material from galvanic corrosion may be an applicable aging effect/mechanism. However, the

applicant does not include loss of material due to galvanic corrosion as an aging

effect/mechanism that requires management for the period of extended operation. By letter

dated August 4, 2003, the staff issued RAI 3.3-1 pertaining to this issue. The staff's evaluation

of the applicant's response is documented in Section 3.3.2.5.1 of this SER.

The description in item 3.3.2.130 of Table 3.3-2 lists loss of material/corrosion as an aging

effect/mechanism for carbon steel, stainless steel, brass, or bronze components in an

environment of air, moisture, and humidity or leaking fluid. However, the LRA does not

specifically identify which type of corrosion is responsible for the loss of material. The type of

corrosion is important because it determines the susceptible locations to be inspected. By letter

dated August 4, 2003, the staff requested, in RAI 3.3-2, the applicant to provide a specific

description of the types of corrosion responsible for the aging effect of loss of material for the

relevant components, as well as the criteria for selecting these samples, including susceptible

locations for inspections. The staff's evaluation of the applicant's response is documented in

Section 3.3.2.5.2 of this SER.

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Carbon steel, stainless steel, brass, and bronze components exposed to a moist gas (moist

nitrogen) or moist air environment may experience the aging effect of loss of material due to

general (for carbon steel only), pitting, and crevice corrosion (for both carbon steel and

stainless steel) when pollutants such as oxygen, SO2, NO,, or CO are present in the moist air,

particularly when the humidity is greater than 60 percent. However, in Table 3.3-2, the

applicant concluded that no aging effects are identified for the external surfaces of the carbon

steel and stainless steel piping and fittings, accumulators, dampeners, filters/strainers, flow

elements, pumps, orifices, rupture discs, tanks, tubing, and valves exposed to either a

containment nitrogen gas environment or an air, moisture, and humidity environment because

these components are not subject to any viable aging mechanism in the absence of aggressive

chemical species. By letter dated August 4, 2003, the staff issued RAI 3.3-3 requesting the

applicant to provide information to justify the conclusions in Table 3.3-2, Reference Nos.

3.3.2.27 and 3.3.2.40 as to whether pollutants such as oxygen, NO,, SO2 or CO are present,

and if so, to what extent, in the containment gas or air, moisture, and humidity environments.

The staff's evaluation of the applicant's response is documented in Section 3.3.2.5.3 of this

SER.

Aluminum and aluminum alloys components may experience general, pitting, and crevice

corrosion when exposed to moisture and humidity environments, especially with the presence

of contaminants and water (condensation from moist air). However, AMR Reference No.

3.3.2.126 of Table 3.3-2 of the LRA only identifies loss of material due to general and pitting

corrosion as a plausible aging effect for aluminum components exposed to moist air. In Table

3.3-2, Reference No. 3.3.2.21 of the LRA, the applicant concluded that there are no aging

effects on aluminum components of the air handlers heating/cooling system exposed to an air,

moisture, and humidity environment. By letter dated August 4, 2003, the staff requested, in RAI

3.3-4, the applicant to (1) explain the different conclusions on aging effects described above,

(2) provide the technical basis for not including loss of material due to crevice corrosion as an

applicable aging effect, and (3) clarify if there is any condensate on the aluminum fins of the

cooling coils. The staff's evaluation of the applicant's response is documented in Section

3.3.2.5.4 of this SER.

In LRA Table 3.3-2, the applicant concluded that no aging effects were identified for the

external surfaces of copper, brass, or bronze components in the control rod drive hydraulic

system exposed to the moisture and humidity air environment because, "The plant indoor

environment is not an aggressive wetted environment conducive to promoting aging

degradation of brass or bronze (3.3-2, Ref No 3.3.2.23) or copper (3.3.2.34) components." The

staff finds that this conclusion may not be justified because copper and copper alloy

components exposed to a moist air environment may experience the aging effect of loss of

material due to pitting and crevice corrosion, especially when the humidity is at 60 percent or

higher and/or with the presence of pollutants such as oxygen, SO2, NO,, and NH4. By letter

dated August 4, 2003, the staff requested, in RAI 3.3.2.4.3, the applicant to provide its technical

basis (including the level of humidity and the level of pollutants) for this conclusion.

In its response dated October 3, 2003, the applicant stated that copper, brass, and bronze

materials are used in the indoor (air, moisture, and humidity less than 100 'C (212 'F) )

ambient environment for various system piping and tubing. This environment, specified for

Aging Management References 3.3.2.23 and 3.3.2.34, is the same as NUREG-1801,

References V.E.1-b, VII.I.1-b, and VIII.H.1-b. EPRI 1003056, "Non-Class 1 Mechanical

Implementation Guideline and Mechanical Tools, Revision 3," Appendix E, conservatively

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concludes that the indoor ambient environment is an aggressive environment for copper and

copper alloy components if subjected to periodic wetting. However, for the specific indoor

environment being considered, periodic wetting of the external surfaces would be rare. In

addition, M.G. Fontana and N.D. Greene in "Corrosion Engineering," Second Edition, McGrawHill, New York, 1978, state that copper and copper alloys are specifically chosen for their

ambient condition corrosion resistance. Additionally, other than one instance of copper/brass

corrosion found at the Quad Cities station, there has been no operating experience related to

corrosion of copper, brass, or bronze components in an indoor, ambient environment at either

the Quad Cities or Dresden stations. This one example at the Quad Cities station was due to

leakage from the sodium hypochlorite system piping joints in the area of an instrument rack.

The use of the sodium hypochlorite system has since been terminated, and the system has

been removed. Therefore, copper, brass, and bronze components located in an environment of

air, moisture, and humidity less than 100 0C (212 OF) will not require aging management.

The staff reviewed the applicant's response to the issues raised in RAI 3.3.2.4.3. On the basis

of its review, the staff finds that the applicant's response to RAI 3.3.2.4.3 does not adequately

address the questions in the RAI.

While reference to "Corrosion Engineering" is correct, new research results reveal that

pollutants and humidity play an important role in accelerating corrosion on low-alloy materials.

In Corrosion, Understanding the Basics (2000), edited by J.R. Davis, pp. 207 - 210, the author

specifically states that copper and copper alloy components exposed to a moist air environment

will experience the aging effect of loss of material due to pitting and crevice corrosion,

especially when the humidity is at 60 percent or higher and/or with the presence of pollutants

such as oxygen, SO2, NO., and NH4.

Further, the applicant did not provide an answer pertaining to the second part of the question in

RAI 3.3.2.4.3 (i.e., the humidity and pollutant levels). Although the applicant indicated that

periodic wetting is rare for these components, the response did not completely rule out the

possibility of periodic wetting, especially for the extended period of operation. By e-mail dated

November 14, 2003, the applicant was requested to provide (1) further clarification on how

often the periodic wetting and drying could occur on the relevant components and (2) the

technical basis for the conclusion that copper, brass, and bronze components located in an

environment of air, moisture, and humidity less than 100 OC (212 0F) do not require aging

management.

In its response dated December 17, 2003, the applicant stated that the following is the basis for

the assessment that periodic wetting (either continuously wetted or alternately wetting and

drying) of the external surfaces of copper and copper alloys is rare for an indoor (air, moisture

and humidity less than 100 'C (212 0F)) ambient environment.

* The internal fluids for systems containing copper and copper alloy piping and components

are predominately either saturated air or dry gas. The internal fluids for copper and copper

alloy piping and components in the control rod drive hydraulic system are only saturated air

or dry gas. Therefore, leakage at a joint in one of these systems would not result in wetting

of the affected component.

* Copper and copper alloy piping and components are typically not insulated because the

fluids are predominately either saturated air or dry gas. For those cases in which the fluid is

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I

other than saturated or dry air, the fluid in contact with the copper and copper alloy piping

and components is not of a temperature that would cause condensation on the component.

Therefore, wetting from contaminated insulation or condensation is not a consideration.

* Leakage from other systems onto the control rod drive hydraulic system copper and copper

alloy piping and components would be detected by normal operator rounds. Leaks would

not be allowed to persist, and wetting from leaks would not be long lasting or repetitive.

* The statements above are supported by the Quad Cities and Dresden station operation

experience. As stated in the original response to RAI 3.3.2.4-3, other than one instance of

copper/brass corrosion found at the Quad Cities station, there has been no operating

experience related to corrosion of copper, brass, or bronze components in an indoor

ambient environment at either the Quad Cities or Dresden Stations. This one example at

the Quad Cities station was due to leakage from sodium hypochlorite system piping joints in

the area of an instrument rack. The use of the sodium hypochlorite system has since been

terminated, and the system has been removed.

The staff reviewed the applicant's additional response to RAI 3.3.2.4.3 supplemental

information request for the control rod drive hydraulic system and finds it adequate and

acceptable because the applicant has indicated that (1) the wetting caused by leakage from

other systems will be detected and removed in a timely manner and the use of the sodium

hypochlorite system has already been terminated, and (2) the internal fluid for copper and

copper alloy piping and components in the control rod drive hydraulic system is only saturated

air or dry gas. The staff considers all issues related to RAI 3.3.2.4.3 to be closed.

The aging effects identified in the LRA for the control rod hydraulic system are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible the aging effects were identified and that the aging effects listed are appropriate

for the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the control rod hydraulic system:

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress Corrosion Cracking Program (Section 3.0.3.3)

* Bolting Integrity Program (Section 3.0.3.5)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* Structures Monitoring Program (Section 3.0.3.14)

* Periodic Inspection of Components Subject to Moist Environments (3.0.3.18)

As part of RAI B.1.23.2-6, the staff questioned the use of the one-time inspections to manage

aging for components in a moist air environment. In its response dated March 25, 2004, the

applicant credited the Periodic Inspection of Components Subject to Moist Environments

program to manage aging effects for stainless steel, carbon steel, cast iron, aluminum, copper,

and brass and bronze components exposed to moist air environments and subject to wetting.

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The staff's evaluation of the Periodic Inspection of Components Subject to Moist Environments

AMP is contained in SER section 3.0.3.18.

These AMPs are credited for managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. The staff's evaluation of these

AMPs is documented in Sections 3.0.3.2, 3.0.3.3, 3.0.3.5, 3.0.3.8, 3.0.3.10, and 3.0.3.14,

respectively, of this SER.

After evaluating the applicant's AMR for each of the components in the control rod drive

hydraulic system, the staff evaluated the AMPs listed above to determine if they are appropriate

for managing the identified aging effects for this system. For those components identified in

Table 3.3-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by

the GALL Report. For the components identified in LRA Tables 3.1-2 and 3.3-2, the staff

verified that the applicant credited AMPs that are appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the control rod

hydraulic system will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.4 Reactor Water Cleanup System

Summary of Technical Information in the Application. The description of the reactor water

cleanup system can be found in Section 2.3.3.4 of this SER. The passive, long-lived

components in this system that are subject to an AMR are identified in LRA Tables 2.3.3-4.

The components, aging effects, and AMPs are provided in LRA Tables 3.1-1, 3.3-1, and 3.3-2.

Aging Effects

Table 2.3.3-4 of the LRA lists individual components that are within the scope of license

renewal and subject to AMR. The components include closure bolting, NSR vents or drains,

piping and valves, other piping and fittings and valves, and sight glasses.

The LRA identifies that low-alloy steel, carbon steel, stainless steel, brass, and bronze in an air,

moisture, and humidity environment or leaking fluid are subject to loss of material due to

general corrosion/corrosion. Low-alloy steel, carbon steel, CASS, and stainless steel in air with

metal temperatures up to 288 0C (550 OF) or in reactor coolant water or steam, as well as in

oxygenated water, are subject to cumulative fatigue damage due to fatigue. Low-alloy steel,

stainless steel, and CASS in an air, moisture, humidity and leaking fluid environment, or in

288 OC (550 0F) reactor coolant water or steam, as well as in an oxygenated water

environment, are subject to crack initiation and growth due to SCC and IGSCC. Carbon steel

and stainless steel in oxygenated water are also subject to loss of material from pitting and

crevice corrosion. CASS in 288 OC (550 0F) reactor coolant water is subject to loss of fracture

toughness due to thermal aging embrittlement. The applicant stated that glass in wet gas is not

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subject to any aging effect. The LRA does not identify any aging effect for stainless steel

components in moist air less than 100 CC (212 OF) or in a containment nitrogen environment.

Aging Management Programs

The LRA credits the following AMPs with managing the identified aging effects for the reactor

water cleanup system:

* Bolting Integrity Program (B.1.12)

* One-Time Inspection Program (B.1.23)

* Water Chemistry Program (B.1.2)

* BWR Stress Corrosion Cracking Program (B.1.7)

* BWR Reactor Water Cleanup System Program (B.1.17)

* ASME Section Xl Inservice Inspection, Subsections IWB, IWC, and IWD Program (B.1.1)

* Structures Monitoring Program (B.1.30)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the reactor water cleanup system

will be adequately managed by these AMPs during the period of extended operation.

The closure bolting, piping and fittings, and valves are also covered by TLAAs to address

fatigue. TLAAs of applicable components are described in Section 4.3 of the LRA.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, in the

components of the reactor water cleanup system. The staff also reviewed the applicable

UFSAR Supplements for the AMPs to ensure that the program descriptions adequately

describe the AMPs.

Aging Effects

The staff reviewed the information in Tables 2.3.3-4, 3.1-1, 3.3-1, and 3.3-2 for the reactor

water cleanup system. During its review, the staff determined that additional information was

needed.

For the environment of moist air, the applicant stated, in Table 3.3-2, page 3-141 of the LRA,

that loss of material due to pitting and crevice corrosion for stainless steel components is an

applicable aging effect and that the One-Time Inspection Program (B.1.23) is the applicable

AMP. However, in the environment of air, moisture, and humidity less than 100 0C (212 OF),

stainless steel components are claimed by the applicant, in Table 3.3-2, page 3-96 of the LRA,

to have no applicable aging effect. By letter dated August 4, 2003, the staff requested, in RAI

3.3.2.4.4, the applicant to provide the following additional information:

(a) Explain the difference between the environment of moist air and air, moisture, and humidity

less than 100 0C (212 OF), as stated in Table 3.3-2, page 3-141 and page 3-96,

respectively, of the LRA, and justify the different conclusions drawn in terms of the

combination of components/materials/environment/applicable aging effect.

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(b) In NUREG-1801 (Volume Ili Chapter VII, Section E4), carbon steel components in auxiliary

systems, such as piping and fittings and pump casings, in an oxygenated water

environment are addressed. The applicable aging effects are loss of material and fatigue.

For loss of material, the recommended AMP is Chapter XL.M2, 'Water Chemistry,"

augmented by verification of the effectiveness of the Chemistry Control Program. NUREG1801 suggests that for these cases, the detection of aging effects is to be further evaluated.

In Table 3.3-2 (page 3-116, item 3.3.3-140) of the LRA, the applicant stated that NUREG1801 does not address carbon steel components in an oxygenated water environment.

Clarify this statement based on the above information provided by NUREG-1 801.

In its response dated October 3, 2003, to part (a) of the RAI, the applicant stated that the

environment of moist air (identified in LRA Table 3.3-2, page 3-141) and the environment of air,

moisture, and humidity less than 100 0C (212 OF) (identified in LRA Table 3.3-2, page 3-96) are

the same. The only difference is in how they are described, which is verbatim with NUREG1801, Volume II, Chapter VIl, for the respective systems. For example, NUREG-1801, Volume

II, Chapter VII, Items F1.1-a and H2.2-a, are aligned with the control room ventilation and the

emergency diesel generator systems, respectively. Item Fl.1-a identifies the environment as

"Warm, moist air," while Item H2.2-a identifies the environment as 'Moist air."

The applicant clarified that the subject Aging Management Reference (3.3.2.291) identified on

page 3-141 of the LRA and those Aging Management References (3.3.2.37, 3.3.2.38, and

3.3.2.40) on page 3-96 are associated with internal environments and external environments,

respectively.

The applicant further stated that Aging Management Reference 3.3.2.291 of LRA Table 3.3-2 is

associated with components made of stainless steel with an indoor ambient internal

environment. It specifically addressed components in the emergency diesel generator and

SBO diesel generator air start systems. The "Non-Class 1 Mechanical Implementation

Guideline and Mechanical Tools, Revision 3," EPRI 1003056, Appendix D, was utilized to

perform the AMR for these components. It specifically identifies loss of material due pitting and

crevice corrosion as the aging effect/mechanism.

The applicant further clarified that Aging Management References 3.3.2.37 and 3.3.2.38 of LRA

Table 3.3-2 are associated with components made of ductile iron and malleable iron,

respectively, with indoor ambient external environments. EPRI 1003056, Appendix E, was

utilized to perform the AMR for these components although it does not specifically address the

associated material types. However, it does address gray cast iron, which is considered to be

less corrosion resistant than ductile iron and malleable iron. Therefore, the conclusions of EPRI

1003056, Appendix E, for gray cast iron should bound those for the subject material types.

EPRI 1003056, Appendix E, conservatively considers an indoor ambient environment to be

aggressively corrosive. Since the indoor ambient environment is only marginally corrosive, a

determination was made that it was unnecessary to manage the aging of ductile iron and

malleable iron components in this environment.

Finally, the applicant stated that Aging Management Reference 3.3.2.40 of LRA Table 3.3-2 is

associated with components made of stainless steel in an indoor ambient external environment.

EPRI 1003056, Appendix E, was utilized to perform the AMR for these components. EPRI

1003056, Appendix E, indicates that stainless steel materials are not subject to any viable aging

mechanism in the absence of aggressive chemical species. The affected components are not

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subject to any aggressive chemical species. Therefore, the applicant concluded that it was

unnecessary to manage the aging of stainless steel components in this environment.

On the basis of its review, the staff finds the applicant's response to part (a) of RAI 3.3.2.4.4

acceptable because (1) the applicant documented that the environment of moist air (identified

in LRA Table 3.3-2, page 3-141) and the environment of air, moisture, and humidity less than

100 0C (212 'F) (identified in LRA Table 3.3-2, page 3-96) are the same, and (2) the applicant

verified that the affected stainless steel components with an indoor ambient external

environment described in Table 3.3-2, page 3-96, of the LRA are not subject to any aggressive

chemical species and therefore it is unnecessary to manage the aging of stainless steel

components in this environment. This is consistent with the recommendations of "Non-Class 1

Mechanical Implementation Guideline and Mechanical Tools, Revision 3," EPRI 1003056,

Appendix E.

In its response dated October 3, 2003, to part (b) of the RAI, the applicant stated that the

statement in Aging Management Reference 3.3.2-140 (identified as 3.3.3-140 in the RAI) of

LRA Table 3.3-2, indicating that NUREG-1 801 does not address carbon steel components in an

oxygenated water environment, is in reference to carbon steel piping and fittings in the reactor

water cleanup system. The cited NUREG-1801 section (Volume II, Chapter VII, Section E4)

addresses carbon steel components in the shutdown cooling system. The NUREG-1801

section corresponding to the reactor water cleanup system is Volume II, Chapter VII, Section

E3, which does not address carbon steel piping and fittings. However, the applicant clarified

that Aging Management Reference 3.3.2-140 of LRA Table 3.3-2 should have stated that

NUREG-1 801 does not address carbon steel piping and fittings in an oxygenated water

environment for the reactor water cleanup system.

The staff finds the applicant's response to part (b) of RAI 3.3.2.4.4 acceptable because the

applicant clarified that Aging Management Reference 3.3.2-140 of LRA Table 3.3-2 should have

stated that NUREG-1 801 does not address carbon steel piping and fittings in an oxygenated

water environment for the reactor water cleanup system. The staff considers the issues related

to RAI 3.3.2.4.4 part (a) and part (b) to be closed.

The aging effects identified in the LRA for the reactor water cleanup system are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible the aging effects were identified and that the aging effects listed are appropriate

for the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the reactor water cleanup system:

* Bolting Integrity Program (Section 3.0.3.5)

* One-Time Inspection Program (Section 3.0.3.10)

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress Corrosion Cracking Program (Section 3.0.3.3)

* BWR Reactor Water Cleanup System Program (3.3.2.3.2)

* ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program (Section

3.0.3.1)

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* Structures Monitoring Program (3.0.3.14)

These AMPs, other than the BWR Reactor Water Cleanup System Program (B.1.17), are

credited for managing the aging effects of components in several structures and systems and,

therefore, are considered common AMPs. These AMPs are evaluated in Sections 3.0.3.5,

3.0.3.10, 3.0.3.2, 3.0.3.3, and 3.0.3.1, respectively, of this SER.

The staff has evaluated the system-specific AMP, BWR Reactor Water Cleanup System

Program, in Section 3.3.2.3.2 of this SER and found it to be acceptable for managing the aging

effects identified for this system.

After evaluating the applicant's AMR for each of the components in the reactor water cleanup

system, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects for this system. For those components identified in

Tables 3.1-1 and 3.3-1 of the LRA, the staff verified that the applicant credited the AMPs

recommended by the GALL Report. For the components identified in LRA Table 3.3-2, the staff

verified that the applicant credited AMPs that are appropriate for the identified aging effects.

The fatigue of the reactor water cleanup system components is addressed in the TLAA in

Section 4.3.3, "Reactor Coolant Pressure Boundary Piping and Component Fatigue Analysis,"

and Section 4.3.4, "Effects of Reactor Coolant Environment on Fatigue Life of Components and

Piping (Generic Safety Issue 1 90)," of the LRA. This TLAA is evaluated in Section 4.3 of this

SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the reactor water

cleanup system will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff concludes that the applicant has adequately

identified the aging effects, and the AMPs credited for managing the aging effects, for the

reactor water cleanup system so that the intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff

also reviewed the applicable UFSAR Supplement program descriptions and concludes that the

UFSAR Supplement provides an adequate program description of the AMPs credited for

managing aging in the reactor water cleanup system, as required by 10 CFR 54.21 (d).

3.3.2.4.5 Fire Protection System

The applicant described its FP AMP in Sections B.1.18, Fire Protection, and B.1.19, Fire Water

System, of the LRA. The applicant credits the FPP with managing the aging of FP system

components that are within the scope of license renewal and subject to an AMR.

Summary of Technical Information in the Application. Table 2.3.3-5 in Section 2.3.3.2 of the

LRA identifies component groups and provides aging management references in Tables 3.3.1

and 3.3.2 for GALL (NUREG-1 801) and non-GALL items respectively.

Staff Evaluation. The staff reviewed Sections 3.3, Appendix B.1.18, and Appendix B.1.19 of the

LRA to determine whether the applicant had demonstrated the effects of aging for the FP

system will be adequately managed during the period of extended operations. The staff's

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review was conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1 800) and is

described below.

Chapter XL.M26 of NUREG-1801 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 protection seals, fire barrier walls, ceilings, and floors, and periodic

visual inspection and functional tests of fire-rated doors to ensure that their operability is

maintained. The diesel-driven fire pump inspection program requires that the pump be

periodically tested to ensure that the fuel supply line can perform its intended function. The

AMP also includes periodic inspection and testing of the Halon/CO2 fire suppression system.

Chapter XL.M27 of NUREG-1 801 applies to water-based FP systems that consist of sprinklers,

nozzles, fittings, valves, hydrants, hose stations, stand pipes, water storage tanks, and aboveground and underground piping and components that are tested in accordance with the

applicable codes and standards of the National Fire Protection Association (NFPA). Such

testing assures the minimum functionality of the systems. Also, these systems are normally

maintained at the required operating pressure and are monitored such that loss of system

pressure is immediately detected and corrective actions will be initiated.

The review of Section 3.3 of the LRA included an examination of Tables 3.3.1 and 3.3.2. LRA

Tables 3.3-1 and 3.3-2 do not identify any aging effects on FP buried piping, fittings and tanks.

However, these components are exposed to soil and groundwater environment, and are

subject to general, pitting and crevice corrosion, and microbiological influenced corrosion (MIC)

that may result in loss of material. In a letter dated August 4, 2003, the staff requested

clarification regarding Tables 3.3-1 and 3.3-2. In RAI 3.3.2.4.5-1.a, the staff requested that the

applicant provide justification for not identifying any aging effect/mechanism for FP SSCs.

In a letter dated October 3, 2003, the applicant responded that FP buried piping and fittings that

are exposed to soil and groundwater environment are addressed in LRA Section 2.3.3.5, Table

2.3.3-5, under component group "Piping and Fittings (includes flex hose, hose reels, hoses,

nozzles, tubing, sprinklers, and gaskets of buried fire mains)." These components are subject

to pitting and crevice corrosion and MIC that may result in loss of material. The aging

management results for this component group are provided in LRA Table 3.3-2 (Aging

Management References 3.3.2.33, 3.3.2.131, and 3.3.2.154). There are no tanks in the FP

system that are exposed to soil and groundwater environment (buried tank). These

components are evaluated for loss of material (pitting, crevice corrosion, selective leaching and

MIC), and changes in material properties (elastomer degradation and loss of resiliency) aging

effects/mechanisms. The staff reviewed the applicant's response and concurs that the FP

piping can be adequately addressed under the component group "Piping and Fittings" and

aging management references 3.3.2.33, 3.3.2.131, and 3.3.1.154.

The staff requested in RAI 3.3.2.4.5-1.b that the applicant provide justification for not

identifying any aging effect/mechanism for fire hose stations, which are exposed to a warm and

moist environment and are subject so pitting and corrosion that may result in loss of material.

In a letter dated October 3, 2003, the applicant responded that fire hose stations are addressed 3

in LRA Section 2.3.3.5, Table 2.3.3-5 under the component group "Piping and Fittings (includes

flex hose, hose reels, hoses, nozzles, tubing, sprinklers, and gaskets of buried fire mains)".

NUREG 1801 considers fire hose station as a piping component in the Fire Water System

AMP, B13.19 (NUREG-1 801 XL.M27). The aging management results of the carbon steel

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components that are exposed to warm and moist air environment are provided in aging

management reference 3.3.2.144, Table 3.3-2, under the component group "Piping and

Fittings". These components are subject to general pitting and crevice corrosion, which may

result in loss of material. The staff reviewed applicant's response and concurs that hose

stations can be adequately addressed under component group "Piping and Fittings" and aging

management references 3.3.2.144.

The line items with reference numbers, 3.3.2.138, 3.3.2.212, and 3.3.2.234 of LRA Table 3.3.2

state that the piping and nozzles components of the CO2 system do not require an AMP, citing

a dry gas atmosphere. However, these component types are exposed to a warm and moist

environment in the turbine building, and are subject to pitting and corrosion that may result in

loss of material. In a letter dated August 4, 2003, the staff requested, in RAI 3.3.2.4.5-1c, that

the applicant provide justification for not identifying any aging effect/mechanism for Halon/CO2

total flooding fire suppression systems components including nozzles, valves, piping, fittings,

tubing, hose stations, and tanks, as these component types are exposed to a warm and moist

environment in the turbine building, and are subject to pitting and corrosion that may result in

loss of material. In a letter dated October 3, 2003, the applicant responded that dry gas

atmosphere is an internal environment of the Halon/CO2 fire suppression systems and is

associated with aging reference numbers, 3.3.2.138, 3.3.2.212, and 3.3.2.234 on Table 3.3-2.

That table provides aging management results for the internal dry gas environment. Aging

management reference 3.3.1.5 in Table 3.3.1 provides the aging management results of

external surfaces for carbon steel components that are subject to pitting and corrosion, which

may result in loss of material. The aging management results for the external surfaces of brass

and bronze components are provided in aging management reference 3.3.2.23 in Table 3.3.2.

The staff reviewed the applicant's response. Although aging management reference 3.3.1.5.on

Table 3.3.1 does not specifically list either Halon or C02 fire suppression systems, including

these systems in this aspect of the AMP is acceptable.

The line item with reference number 3.3.2.62 of LRA Table 3.3-2 states that cementitious fire

proofing does not require an AMP, because a "non-aggressive," vibration free plant indoor

environment is not conducive to promoting aging of cementitious fireproofing. However,

industry experience, including previous experience at the Dresden Nuclear Power Station, has

shown that deterioration of the steel under the coating may cause the cementitious material to

become separated from the steel, and in some cases fall off. In a letter dated August 4, 2003,

the applicant was requested to provide justification for not having an AMP that will assure its

integrity of the cementitious fire proofing.

In a response dated October 3, 2003, the applicant agreed that upon review of aging

management reference 3.3.2.62, that cementitious fire proofing requires aging management

due to separation caused by deterioration of the structural steel under the coating. The

structural steel coatings are currently inspected as part of AMP, B.1.18, "Fire Protection". This

also applies to aging management reference 3.3.2.63, for ceramic fiber fire wrap. Both LRA

aging management references 3.3.2.62 and 3.3.2.63 should have read as follows:

Ref No Compone Material Environment Aging Effect/ Aging Management Discussion

nt Group Mechanism Program

3.3.2.62 Fire Cementitious Indoor Separation/ Fire Protection NUREG-1801 does

Proofing Fire Proofing deterioration (B.1.18) not address

I__ of steel I _ _ cementitious

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Ref No Compone Material Environment Aging Effect/ Aging Management Discussion

nt Group Mechanism Program

fireproofing in an

indoor

environment.

3.3.2.63 Fire Wrap Ceramic Indoor Separation/ Fire Protection NUREG-1801 does

Fiber deterioration (B.1.18) not address

of steel ceramic fiber fire

wrap in an indoor

environment.

LRA Section A.1.1 8 on Page A-8 (Dresden, Units 2 and 3) of the LRA should have read as

follows:

The fire protection aging management program 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 wraps and fire proofing; fire barrier walls,

ceilings, and floors; flood barrier penetration seals that also serve as fire barrier seals; and periodic

visual inspection and functional tests of fire rated doors to ensure that their operability is

maintained. The program includes surveillance tests of fuel oil systems for the diesel-driven fire

pumps and isolation condenser diesel-driven makeup pumps to ensure that the fuel supply lines

can perform intended functions. The program also includes visual inspections and periodic

operability tests of Halon and CO2 fire suppression systems based on NFPA codes.

Prior to the period of extended operation, the program will be revised to include:

* Inspection of oil spill barriers

* Inspection of external surfaces of the Halon and the C02 fire suppression system

* Periodic capacity tests of the isolation condenser makeup pumps

* Specific fuel supply leak inspection criteria for fire pumps and isolation condenser makeup

pumps during tests

* Specific inspection criteria for fire doors

* Inspection frequencies for fire doors and spill barriers

This is part of Commitment #18 of Appendix A in this SER.

LRA Section A.1.18 on Page A-32 (Quad Cities, Units 1 and 2) of the LRA should have read as

follows:

The fire protection 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 wraps and fire proofingi fire barrier walls, ceilings, and floors;

flood barrier penetration seals that also serve as fire barrier seals; and periodic visual inspection

and functional tests of fire rated doors to ensure that their operability is maintained. The

program includes surveillance tests of fuel oil systems for the diesel-driven fire pumps to ensure

that the fuel supply line can perform intended functions. The program also includes visual

inspections and periodic operability tests of the carbon dioxide fire suppression system based

on NFPA codes.

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;

Prior to the period of extended operation, the program will be revised to include:

* Inspection of oil spill barriers

* Inspection of external surfaces of the C02 fire suppression system

* Specific fuel supply leak inspection criteria for fire pumps

* Specific inspection criteria for fire doors

This is part of Commitment #18 of Appendix A in this SER.

LRA Section B.1.1 8 program description paragraph 3 on Page B-38 of the LRA should have

read as follows:

The program provides for visual Inspection of fire barrier penetration seals, fire wraps, fire

proofing, and flood barrier penetration seals that also serve as fire barrier seals for signs of

degradation, such as damage, holes, cracking, and loss of material, through periodic inspection,

surveillance and maintenance activities. The Inspections are implemented through station

procedures. Flood barrier penetration seal inspections are part of the structures monitoring

program.

The staff reviewed the applicants response. The staff finds the inclusion of fire proofing into the

AMP acceptable as proposed by the applicant because the AMP as revised will effectively

manage the aging effects of the fire proofing and fire wraps.

The aging effects identified in the LRA for the FP system are consistent with industry operating

experience for the materials and environments listed. The staff finds that all the plausible the

aging effects were identified and that the aging effects listed are appropriate for the

combination of materials and environments specified.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the FP system

will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.5A Fire Water System

Summary of Technical Information. Appendix B, Section B.1.19 identifies the AMP for the fire

water system components within the scope of license renewal. The fire water system AMP

provided for managing the loss of material and biofouling aging effects on the intended

functions of the water-based FP components within the scope of license renewal. The program

included inspection, surveillance testing and maintenance activities. This section addresses the

consistency of B.1.1 9 with Section XL.M27 of NUREG-1 801 and identifies exceptions and

enhancements to its specific requirements. This section also discusses operating experience

with the fire water system at Dresden and Quad Cities.

Staff Evaluation. The staff reviewed LRA Appendix B.1.1 9 to determine whether there is

reasonable assurance that the AMP activities are adequate to maintain the intended functions

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of the fire water system SSCs for the period of extended operation, as required by 10 CFR

54.21 (a)(1)(a)(3). The staff's review was conducted in accordance with Section 2.3 of the SRPLR (NUREG-1800) and is described as below.

LRA Appendix B, Section B.1.19, "Fire Water System," states that, "With enhancements the fire

water system aging management program is consistent with the ten elements of aging

management program XI.M27, "Fire Water System," specified in NUREG-1 801 with the

following exceptions...." In order for the staff to evaluate the adequacy of the applicant's FP

AMP and reach a conclusion that it is consistent with NUREG-1 801, the staff requested, in a

letter dated August 4, 2003, that the applicant follow the guidelines provided in NUREG-1 801

and the interim staff guidance for FP AMP [Staff Guidance (ISG)-04, "Aging Management of

Fire Protection Systems for License Renewal," (ADAMS Accession # ML022260137), dated

December 3, 2002]. NUREG-1 801 contains the staff's generic evaluation of the existing plant

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

adequate without modification and where existing programs should be augmented for the

period of extended operation.

In a letter dated October 3, 2003, the applicant responded with the following information. Part 1

of this response compares the Dresden and Quad Cities fire water system program against the

NUREG-1 801, XI.M27 program and identifies where exceptions still exist. Included in Part 1 is

a discussion of how Dresden and Quad Cities are addressing ISG-04. Part 2 of the response

discusses the Dresden and Quad Cities underground loop flow testing.

(1) The applicant concluded in the Dresden and Quad Cities LRA, Appendix B, Section B.1.19,

that the fire water system program, after the enhancements discussed in Appendix B,

Section B.1.19, Subsection, "Enhancements," are implemented, will be consistent with the

ten-element program described in NUREG-1801, XI.M27, with certain exceptions. Although

not stated in the LRA, after the enhancements are implemented, the fire water system

program will be also be consistent with the NRC staff recommendations for fire water

systems as provided in ISG-04.

Exelon evaluated the Dresden and Quad Cities fire water system program against the attributes

of the ten elements of NUREG-1 801, XI.M27 and identified that after the enhancements are

implemented, the following exceptions will still exist:

* NUREG-1 801, XI.M27, Element 3 states that 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. Flow tests at the maximum design

flow are not practicable for Dresden and Quad Cities. Instead, the Dresden and Quad

Cities flow tests analyze the system hydraulic resistance. Dresden measures underground

piping pressure drops at given flows for selected segments of underground fire mains and

compares them to pre-calculated allowable pressure drops for the same segments at the

given flows. The measured pressure drop must be equal to or less than the allowable. The

measured results are also compared with those of previous tests to identify adverse trends.

Quad Cities takes pressure measurements and calculates the friction loss coefficients ("C"

factor) for the various sections of the underground fire mains. The calculated "C" factor

must be equal to or greater than 80 for all piping tested. The calculated results are

compared with those of previous tests to identify adverse trends. A low "C" factor (Quad

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Cities method) or a large pressure drop (Dresden method) may be indicative of either

fouling or leakage of the underground fire mains.

(b) NUREG-1 801, XI.M27, "Program Description," states that the AMP (XI.M27) applies to

water-based FP systems that are tested in accordance with the applicable National Fire

Protection Association (NFPA) codes and standards.

The Dresden and Quad Cities fire water systems may not in all cases be tested in

accordance with NFPA codes, but in these cases, technical justifications for the

deviations are documented. NFPA codes were used in the design of active FP systems

(i.e., fire suppression and detection systems). Similarly, inspection and periodic testing

is performed in accordance with corporate and station procedures developed using

NFPA codes as guidance. Corporate Procedure ER-AA-610, 'Performance Based

Evaluations for Fire Protection," ensures that performance-based evaluations that result

in surveillance frequencies that exceed those specified in site-specific NFPA codes of

record serve as the deviation justification. Where code deviations are required or

desirable, they are made under the intent of the code and documented in the NFPA

Code Deviation Report at each site in accordance with CC-AA-21 1, "Fire Protection

Program." Revision to the NFPA Code Deviation Report is necessary unless the report

has previously addressed the deviation.

(c) Interim staff guidance ISG-04 was issued on December 3, 2002. Included as part of

ISG-04 is an amended ten-element AMP, XL.M27, for the fire water system. Applicant

evaluated the Dresden and Quad Cities fire water system program against the staff

recommendations for fire water systems included in ISG-04 with the following

conclusions:

* In Element 3 of the amended XL.M27, the staff provides for the option of performing

wall thickness evaluations in lieu of testing at maximum design flow. The flow

testing discussed in (1 )(a) is not performed at maximum design flow, but Dresden

and Quad Cities will perform wall thickness measurements.

* In Element 4 of the amended XL.M27, the staff recommends that the applicant

perform a baseline pipe wall thickness evaluation of the FP piping using a nonintrusive means of evaluating wall thickness, such as volumetric inspection, to detect

general corrosion before the current license term expires. The staff also

recommends that the applicant perform pipe wall thickness evaluations at plantspecific intervals during the period of extended operation. As an alternative to nonintrusive testing, the amended XL.M27 allows for a visual inspection of the internal

surface of the FP piping upon each entry to the system for routine or corrective

maintenance as long as it can be demonstrated that inspections are performed on a

representative number of locations on a reasonable basis.

Dresden and Quad Cities will perform periodic non-intrusive FP piping wall thickness

measurements. These non-intrusive inspections will be conducted prior to the end

of the current term and repeated on a frequency not exceeding every 10 years. This

is part of Commitment #19 of Appendix A of this SER.

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I

Element 4 of the amended XL.M27 also states that if the environmental and material

conditions that exist on the interior surfaces of the below-grade FP piping are similar

to the conditions that exist within the above-grade piping, the results of the

inspections of the above-grade FP piping can be extrapolated to evaluate the

condition of below-grade piping.

The below-grade fire mains at both Dresden and Quad Cities comprise uncoated

carbon steel. The internal environment of the below-grade fire mains at both

Dresden and Quad Cities is "raw water," the same as NUREG-1 801 Reference

VII.G.6-a. Therefore, the results of the inspections of above-grade FP uncoated

carbon steel piping with a raw water environment can be extrapolated to evaluate to

the condition of the below-grade fire mains.

In Element 4 of the amended XL.M27, the staff recommends, in accordance with

NFPA 25, that sprinkler head testing be performed at year 50 of the sprinkler system

service life, not year 50 of plant operation, with subsequent sprinkler head testing

every 10 years thereafter. Representative samples of Dresden and Quad Cities

sprinkler heads will be submitted to a testing laboratory prior to being in service 50

years. This testing will be repeated on a frequency not exceeding every 10 years.

This is part of Commitment #19 of Appendix A of this SER.

The staff reviewed the applicant's response. On the basis of the justification provided, the staff

concurs that the aging of fire water system components will be adequately managed by the

AMP. In a letter dated August 4, 2003, the staff requested that the applicant clarify the flow

rates and testing frequencies of the underground loop flow tests and describe the plant

procedure for this testing.

(2) In a letter dated October 3, 2003, the applicant responded with additional details regarding

frequency and method of flow testing. Flow testing is conducted at five-year intervals at

Dresden and Quad Cities. As stated in Section (1)(a) of the applicant's response, tests are

not performed at the maximum design flow. By themselves, the absolute values of the

flows achieved during testing at both Dresden and Quad Cities provide no indication of the

condition of the underground fire mains. Utilizing the Dresden test procedure, test

conditions are established to provide flow rates within a pre-determined range

corresponding to a table of pre-calculated allowable pressure drops vs. flows. For the cross

tie flow test, these pre-determined flows range from 2,500 gpm to 3,500 gpm. For the yard

loop flow test, these pre-determined flows range from 900 gpm to 1,300 gpm.

The Quad Cities test procedure methodology ("C" factor) employs the installation of four

underwriter's playpipes on each of the three pipe segments to be tested. Sequential tests are

performed on each segment with one, two, three, and four playpipes flowing. Total flows and

"C" factors are calculated for each combination of flowing playpipes. For each pipe segment,

the "C" factors for each separate flow scenario are compared and the most appropriate one is

chosen. Since more accurate "C" factors are obtained when calculated for higher flows, it is

most likely that the one calculated for four flowing playpipes will be chosen. During the last flow

test performed at Quad Cities, the highest calculated flows for each of the three segments,

each with four playpipes flowing, were 2,296 gpm, 2,562 gpm, and 2,547 gpm.

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The staff reviewed the applicant's response-and on the basis of the additional technical data,

concurs that the frequency and fiethod of testing adequately addresses NUREG-1 801, XL.M27,

Element 3.

The aging effects identified in the LRA for the fire water system are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the fire water

system will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that

the effects of aging will be adequately managed so that the intended functions will be

maintained consistent with the current licensing basis for the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

3.3.2.4.6 Emergency Diesel Generator and Auxiliaries System

Summary of Technical Information in the Application. The description of the emergency diesel

generator and auxiliaries system can be found in Section 2.3.3.6 of this SER. The passive,

long-lived components in this system that are subject to an AMR are identified in LRA Table

2.3.3-6. The components, aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-

2.

Aging Effects

Components of the emergency diesel generator and auxiliaries system are described in Section

2.3.3.6 of the LRA as being within the scope of license renewal and subject to an AMR. Table

2.3.3-6 of the LRA lists individual components of the system, including piping, tubings, ducts,

hinges, latches, pumps, valves, heat exchangers, coolers, filters/strainers, restricting orifices,

tanks, vessels, closure bolting, doors, equipment frames, flexible hoses, flex collars, lubricators,

mufflers, tanks, sight glasses, thermowells, air accumulator vessels, debris screens, NSR vents

or drains, and turbochargers.

Carbon steel in outdoor ambient conditions is subject to loss of material due to general, pitting,

and crevice corrosion. High-strength, low-alloy steel in outdoor ambient conditions is subject to

loss of material due to general corrosion and wear. 'Cast iron exposed to indoor moist and

humid air is subject to loss of material due to general, pitting, and crevice corrosion. No aging

effect islidentified for stainless steel, aluminum, brass, bronze, and copper exposed to indoor

moist and humid air. Stainless steel, aluminum, brass, bronze, cast iron, and copper exposed

to an internal environment of moist air are subject to loss of material due to pitting, crevice,

and/or general corrosion. Elastomer seals exposed to an internal environment of moist air or

saturated air are subject to hardening and loss of strength due to elastomer degradation. Cast

iron exposed to an internal environment of hot diesel engine exhaust gases is subject to loss of

material due to general, pitting, and crevice corrosion. Brass, bronze, cast iron, and copper

exposed to chemically treated demineralized water are subject to loss of material due to

general, pitting, and crevice corrosion, MIC, and/or select leaching. Carbon steel, stainless

steel, brass, and bronze exposed to chemically treated demineralized water are subject to

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cracking due to SCC. Carbon steel and cast iron exposed to lubricating oil are subject to loss

of material due to general, pitting, and crevice corrosion. No aging effect is identified for brass

or bronze in dry air.

Aging Management Programs

The following AMPs are utilized to manage aging effects in the emergency diesel generator and

auxiliaries system:

* Bolting Integrity Program (B.1.12)

* Open-Cycle Cooling Water System Program (B.1.13)

* Closed-Cycle Cooling Water System Program (B.1.14)

* One-Time Inspection Program (B.1.23)

* Selective Leaching of Materials Program (B.1.24)

* Structures Monitoring Program (B.t.30)

* Compressed Air Monitoring Program (B.1.16)

* Lube Oil Monitoring Program (B.2.5)

* Fuel Oil Chemistry Program (B.1.21)

* Periodic Inspection of Ventilation System Elastomers Program (B.2.3)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the emergency diesel generator

and auxiliaries system will be adequately managed by these AMPs during the period of

extended operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, in the

emergency diesel generator and auxiliaries system. The staff also reviewed the applicable

UFSAR Supplements for the AMPs to ensure that the program descriptions adequately

describe the AMPs.

Aging Effects

The staff reviewed the information in Section 2.3.3.6 and Tables 2.3.3-6, 3.3-1, and 3.3-2 in the

LRA. During its review, the staff determined that additional information was needed.

The description in item 3.3.2.130 of Table 3.3-2 lists loss of material/corrosion as an aging

effect/mechanism for carbon steel, stainless steel, brass, or bronze components in an

environment of air, moisture, humidity, and leaking fluid. However, the LRA does not

specifically identify which type of corrosion is responsible for the loss of material. The type of

corrosion is important because it determines the susceptible locations to be inspected. By letter

dated August 4, 2003, the staff requested, in RAI 3.3-2, the applicant to provide a specific

description of the types of corrosion responsible for the aging effect of loss of material for the

relevant components, as well as the criteria for selecting these samples, including susceptible

locations for inspections. The staff's evaluation of the applicant's response is documented in

Section 3.3.2.5.2 of this SER.

In LRA Table 3.3-2, Reference No. 3.3.2.18, the applicant stated that high-strength, low-alloy

steel closure bolting components in outdoor ambient conditions are subject to the aging effect

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of loss of material due to general corrosion and wear. However, the applicant did not include

crack initiation and growth due to SCC or other mechanisms as an applicable aging

effect/mechanism. By letter dated August 4, 2003, the staff requested, in RAI 3.3-5, the

applicant to provide its technical basis for not including this aging effect/mechanism. The staff's

evaluation of the applicant's response is documented in Section 3.3.2.5.5 of this SER.

The applicant uses the Bolting Integrity Program (B.1.12) to manage general corrosion on

external surfaces of many auxiliary system nonbolting components. The staff notes that the

Bolting Integrity Program description states, "The program consists of visual inspections for

external surface degradation that may be caused by loss of material or cracking of the bolting,

or by an adverse environment." This suggests that only the bolting material will be inspected for

aging degradation. By letter dated August 4, 2003, the staff requested, in RAI 3.3-9, the

applicant to explain (including the acceptance criteria and inspection interval) how the Bolting

Integrity Program is used to manage general corrosion on external surfaces of nonbolting

components, such as piping, valves, mufflers, and others. The staff's evaluation of the

applicant's response is documented in Section 3.3.2.5.9 of this SER.

In Table 2.3.3-6, page 2-119 of the LRA, Aging Management Reference 3.3.1.7 refers to piping

and fittings (and attached support) and valves (and attached support). In Table 3.3-1, page 3-

74 of the LRA, Aging Management Reference 3.3.1.7 credits the Fuel Oil Chemistry and OneTime Inspection Programs for managing the aging effects of the fuel oil tank and day tank. On

the other hand, the "Tanks" group in Table 2.3.3-6 does not include Aging Management

Reference 3.3.1.7 that links to the Fuel Oil Chemistry Program and the One-Time Inspection

Program for managing the aging effects of the fuel oil tank and day tank. By letter dated

August 4, 2003, the staff requested, in RAI 3.3.2.4.6(a), the applicant to provide clarification of

the discrepancy.

In its response dated October 3, 2003, the applicant stated that the piping, fittings, and valves

referred to in Aging Management Reference 3.3.1.7 belong to the diesel fuel oil system and

diesel fuel oil tanks, as shown in Table 3.3-1 in the 'Components Evaluated" column. The

diesel fuel oil system is discussed in LRA Section 2.3.3.13, Table 2.3.3-13 (page 2-140). The

'Tanks" group shown in LRA Table 2.3.3-6 (page 2-119) includes the diesel generator cooling

water expansion tanks that are managed by the Closed-Cycle Cooling Water System Program.

On the basis of its review, the staff finds the applicant's response acceptable because the

applicant has clarified that the "Tanks" group in Table 2.3.3-6 includes the diesel generator

cooling water expansion tanks that are managed by the Closed-Cycle Cooling Water System

Program. The piping, fittings, and valves referred to in Aging Management Reference 3.3.1.7

belong to the diesel fuel oil system that is managed by the Fuel Oil Chemistry and One-Time

Inspection Programs. This is part of Commitment #23 of Appendix A of this SER.

Cracking is identified as an aging effect of brass or bronze valves exposed to chemically

treated demineralized water in Aging Management Reference 3.3.2.258, Table 2.3.3-6, of the

LRA. Loss of material is, however, not identified as an aging effect. By letter dated August 4,

2003, the staff requested, in RAI 3.3.2.4.6(b), the applicant to provide justification for not

identifying loss of material as an aging effect for brass or bronze valves exposed to chemically

treated demineralized water.

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In its response dated October 3, 2003, the applicant agreed with the staff that loss of material

applies for brass or bronze in a (nitrite) treated water environment. An Aging Management

Reference similar to 3.3.2.134 should have been added in LRA Table 2.3.3-6 for the valves

component group. The applicant has identified the Closed-Cycle Cooling Water System

Program (B.1.14) and Selective Leaching of Materials Program (B.1.24) for managing the aging

effect of loss of material in these components.

On the basis of its review, the staff finds the applicant's response acceptable because the

applicant stated that loss of material is an applicable aging effect for brass or bronze valves

exposed to chemically treated demineralized water. The applicant also committed the ClosedCycle Cooling Water System Program (B.1.14) and the Selective Leaching of Materials

Program (B.1.24) for managing loss of material for these components. The staff considers all

issues related to RAI 3.3.2.4.6(a) and (b) to be closed.

The aging effects identified in the LRA for the emergency diesel generator and auxiliaries

system are consistent with industry operating experience for the materials and environments

listed. The staff finds that all the plausible the aging effects were identified and that the aging

effects listed are appropriate for the combination of materials and environments specified.

Aging Management Programs

The applicant credited the following AMPs for managing the aging effects in the emergency

diesel generator and auxiliaries system:

* Bolting Integrity Program (Section 3.0.3.5)

* Open-Cycle Cooling Water System Program (Section 3.0.3.6)

* Closed-Cycle Cooling Water System Program (Section 3.0.3.7)

* One-Time Inspection Program (Section 3.0.3.10)

* Selective Leaching of Materials Program (Section 3.0.3.11)

* Structures Monitoring Program (Section 3.0.3.14)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* Lube Oil Monitoring Program (Section 3.0.3.16)

* Fuel Oil Chemistry Program (Section 3.3.2.3.5)

* Periodic Inspection of Ventilation System Elastomers Program (Section 3.0.3.17)

* Periodic Inspection of Components Subject to Moist Environments (3.0.3.18)

As part of RAI B.1 .23.2-6, the staff questioned the use of the one-time inspections to manage

aging for components in a moist air environment. In its response dated March 25, 2004, the

applicant credited the Periodic Inspection of Components Subject to Moist Environments

program to manage aging effects for stainless steel, carbon steel, cast iron, aluminum, copper,

and brass and bronze components exposed to moist air environments and subject to wetting.

The staff's evaluation of the Periodic Inspection of Components Subject to Moist Environments

AMP is contained in SER section 3.0.3.18.

The Bolting Integrity Program, Open-Cycle Cooling Water System Program, Closed-Cycle

Cooling Water System Program, One-Time Inspection Program, Selective Leaching of

Materials Program, Structures Monitoring Program, Compressed Air Monitoring Program, Lube

Oil Monitoring Program, and Periodic Inspection of Ventilation System Elastomers Program are

credited with managing the aging effects of several components in different structures and

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systems and are, therefore, considered common AMPs. The staff's evaluation of these AMPs

is documented in Sections 3.0.3.5, 3.0.3.6, 3.0.3.7, 3.0.3.10, 3.0.3.11, 3.0.3.14, 3.0.3.8,

3.0.3.16, and 3.0.3.17, respectively, of this SER.

The Fuel Oil Chemistry Program is a system-specific AMP. The staff's evaluation of this AMP

is documented in Section 3.3.2.3.5 of this SER.

After evaluating the applicant's AMR for each of the components in the emergency diesel

generator and auxiliaries system, the staff evaluated the AMPs listed above to determine if they

are appropriate for managing the identified aging effects for this system. For those

components identified in Table 3.3-1 of the LRA, the staff verified that the applicant credited the

AMPs recommended by the GALL Report. For the components identified in LRA Table 3.3-2,

the staff verified that the applicant credited AMPs that are appropriate for the identified aging

effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the emergency

diesel generator and auxiliaries system will effectively manage or monitor the aging effects

identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.7 HVAC-Main Control Room

Summary of Technical Information in the Application. The description of the HVAC-Main

Control Room can be found in Section 2.3.3.7 of this SER. The passive, long-lived components

in this system that are subject to an AMR are identified in LRA Table 2.3.3-7. The components,

aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

Aging Effects

Table 2.3.3-7 of the LRA lists individual system components within the scope of license renewal

and subject to AMR. The components include air handlers heating/cooling (CR HVAC),

dampeners, debris screens, diffusers, doors, duct fittings, hinges, latches, closure bolts,

equipment frames (includes dampers), duct, housings, silencers, filters/strainers, heat

exchangers, flow elements, flex collars, doors and dampener seals, housings and supports,

NSR vents or drains, piping and valves, piping and fittings, piping and fittings (attached support)

(Quad Cities only), seals, sight glasses, tubing, and valves.

Carbon steel components are identified as being subject to loss of material due to general,

pitting, and crevice corrosion and MIC [for duct (drip-pan) and piping for moisture drainage]

from exposure to warm, moist air. Copper-nickel, brass, bronze, stainless steel, and copper

components are identified as being subject to loss of material due to pitting and crevice

corrosion from exposure to warm, moist air. Neoprene and similar elastomers are identified as

being subject to hardening and loss of material due to wear from exposure to warm, moist air.

Neoprene is also identified as being subject to hardening and loss of strength and elastomer

degradation from exposure to warm, moist air. Exposure of aluminum-zinc alloy components to

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warm, moist air has no aging effect. Exposure of carbon steel, copper, brass, bronze, and

ductile iron components to dry gas has no aging effect. Copper tubes, tubesheets, and end

bells and aluminum fins are identified as being subject to cracking due to mechanical fatigue

from exposure to refrigerant on the tube side and warm, moist air on the shell side. Copper

tubes are also identified as being subject to buildup of deposits and fouling from exposure to

refrigerant on the tube side and warm, moist air on the shell side. Heat exchanger tubes made

from 90-10 copper-nickel and shells made from carbon steel are subject to cracking due to

mechanical fatigue and SCC and loss of material due to general, galvanic, pitting, and crevice

corrosion and MIC, erosion or flow-accelerated corrosion, and wear from exposure to raw water

on the tube side and refrigerant on the shell side. Heat exchanger tubes made from 90-10

copper-nickel are also subject to buildup of deposits and fouling from exposure to raw water on

the tube side and refrigerant on the shell side. Carbon steel, stainless steel, brass, or bronze

components are identified as being subject to loss of material due to corrosion from exposure to

air, moisture, humidity, and leaking fluid. Carbon steel pipes, fittings, and valves are identified

as being subject to loss of material due to general corrosion from exposure to raw, untreated

salt water or fresh water. Cast iron valves are identified as being subject to loss of material due

to general, pitting, crevice, and galvanic corrosion, erosion, and selective leaching, and MIC

flow blockage/biofouling, silting, and corrosion buildup from exposure to raw, untreated salt

water or fresh water. External surfaces of cast iron components are also identified as being

subject to loss of material due to pitting and crevice corrosion from exposure to air, moisture,

and humidity less than 100 'C (212 'F).

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the

HVAC-Main Control Room:

* Bolting Integrity Program (B.1.12)

* Open-Cycle Cooling Water System Program (B.1.13)

* Compressed Air Monitoring Program (B.1.16)

* One-Time Inspection Program (B.1.23)

* Selective Leaching of Materials Program (B.1.24)

* Periodic Inspection of Ventilation System Elastomers Program (B.2.3)

* Heat Exchanger Test and Inspection Activities Program (B.2.6)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the HVAC-Main Control Room will

be adequately managed by these AMPs during the period of extended operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, on

components in the HVAC-Main Control Room. The staff also reviewed the applicable UFSAR

Supplements for the AMPs to ensure that the program descriptions adequately describe the

AMPs.

Aging Effects

The staff reviewed the information in Section 2.3.3.7, Table 2.3.3-7, and Tables 3.3-1 and 3.3-2

in the LRA. During its review, the staff determined that additional information was needed.

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Metals and alloys that are in contact with different, more cathodic metals or alloys in the

presence of an electrolyte fluid mdy be subject to the aging effect of loss of material from

galvanic corrosion. Many systems/components of the auxiliary systems described by various

items in Table 3.3-2 of the LRA have material/environment combinations for which loss of

material from galvanic corrosion may be an applicable aging effect/mechanism. However, the

applicant does not include loss of material due to galvanic corrosion as an aging

effect/mechanism that requires management for the period of extended operation. By- letter

dated August 4, 2003, the staff issued RAI 3.3-1 pertaining to this issue. The staff's evaluation

of the applicant's response is documented in Section 3.3.2.5.1 of this SER.

The description in item 3.3.2.130 of Table 3.3-2 lists loss of material/corrosion as an aging

effect/mechanism for carbon steel, stainless steel, brass, or bronze components in an

environment of air, moisture, humidity, and leaking fluid. However, the LRA does not

specifically identify which type of corrosion is responsible for the loss of material. The type of

corrosion is important because it determines the susceptible locations to be inspected. By letter

dated August 4, 2003, the staff requested, in RAI 3.3-2, the applicant to provide a specific

description of the types of corrosion responsible for the aging effect of loss of material for the

relevant components, as well as the criteria for selecting these samples, including susceptible

locations for inspections. The staff's evaluation of the applicant's response is documented in

Section 3.3.2.5.2 of this SER.

By letter dated August 4, 2003, the staff requested, in RAI 3.3-7, the applicant to clarify which

specific AMP(s) is applicable for managing AMR item 3.3.1.5, "Specific Corrosion Mechanism,"

and to explain how the AMP(s) manages that corrosion mechanism for components in various

auxiliary systems. The staff's evaluation of the applicant's response is documented in Section

3.3.2.5.7 of this SER.

The applicant uses the Bolting Integrity Program (B.1.12) to manage general corrosion on

external surfaces of many auxiliary system nonbolting components. The staff notes that the

Bolting Integrity Program description states, "The program consists of visual inspections for

external surface degradation that may be caused by loss of material or cracking of the bolting,

or by an adverse environment." This suggests that only the bolting material will be inspected for

aging degradation. By letter dated August 4, 2003, the staff requested, in RAI 3.3-9, the

applicant to explain (including the acceptance criteria and inspection interval) how the Bolting

Integrity Program is used to manage general corrosion on external surfaces of non-bolting

components, such as piping, valves, mufflers, and others. The staff's evaluation of the

applicant's response is documented in Section 3.3.2.5.9 of this SER.

In the treated water environment of the HVAC-Main Control Room, the relevant conditions

could exist for crack initiation and growth due to SCC to occur in carbon steel components.

However, this aging effect/mechanism was only addressed for heat exchanger tubes in the

auxiliary systems AMR. The staff requested the applicant to provide justification for not

including crack initiation and growth due to SCC in carbon steel components, other than the

heat exchanger tubes, in a treated water environment. By letter dated August 4, 2003, the staff

issued RAI 3.3.2.4.7 pertaining to this issue.

In its response dated October 3, 2003, the applicant stated that, for carbon steel components,

SCC occurs only in nitrite treated water, per Appendix A of "Non-Class 1 Mechanical

Implementation Guideline and Mechanical Tools, Revision 3," EPRI 1003056. For the Dresden

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and Quad Cities stations, the emergency diesel generator jacket water, reactor building closedcycle cooling water system, and turbine building closed-cycle cooling water system utilize nitrite

treated water; therefore, these are subject to SCC and the resulting crack initiation and growth.

These aging mechanisms, aging effects, and required AMPs are shown for these systems in

LRA Section 3.3-Aging Management References 3.3.2.68 (flow elements), 3.3.2.77 or

3.3.2.117 (heat exchangers), 3.3.2.137 (piping and fittings), 3.3.2.174 (pumps), 3.3.2.211

(tanks), 3.3.2.233 (tubing), and 3.3.2.267 (valves). These reference numbers apply to the

following component groups for the abovementioned systems.

* emergency diesel generator jacket water (LRA Section 2.3.3.6), including piping and fittings,

pumps, tanks, tubing, and valves

* reactor building closed-cycle cooling water system (LRA Section 2.3.3.17), including flow

elements, heat exchangers (3.3.2.117 for Dresden heat exchangers and 3.3.2.77 for Quad

City heat exchangers), piping and fittings, pumps, tanks, tubing, and valves

* turbine building closed-cycle cooling water system (LRA Section 2.3.3.18), including piping

and fittings and valves

The heat exchanger tubes, including those of the control room HVAC coolers, for Dresden and

Quad Cities are not made of carbon steel. Additionally, the environment for the main control

room HVAC coolers is raw water, refrigerant, and warm, moist air. Therefore, the conditions

relevant to SCC do not exist.

On the basis of its review, the staff finds the applicant's response acceptable because the

applicant provided further clarifications on the AMR for these relevant components and the heat

exchanger tubes, including those of the control room HVAC coolers, for Dresden and Quad

Cities that are not made of carbon steel. The staff considers the issues related to RAI 3.3.2.4.7

to be resolved.

The aging effects identified in the LRA for the HVAC-Main Control Room are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible the aging effects were identified and that the aging effects listed are appropriate

for the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the HVAC-Main Control Room:

* Bolting Integrity Program (Section 3.0.3.5)

* Open-Cycle Cooling Water System Program (Section 3.0.3.6)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* Selective Leaching of Materials Program (Section 3.0.3.11)

* Heat Exchanger Test and Inspection Activities Program (Section 3.0.3.15)

* Periodic Inspection of Ventilation System Elastomers Program (Section 3.0.3.17)

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These AMPs are credited for managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. The staff's evaluation of these

AMPs is discussed in Sections 3.0.3.5, 3.0.3.6, 3.0.3.8, 3.0.3.10, 3.0.3.11, 3.0.3.15, and

3.0.3.17, respectively, of this SER.

After evaluating the applicant's AMR for each of the components in the HVAC-Main Control

Room, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects for this system. For those components identified in Table

3.3-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by the

GALL Report. For the components identified in LRA Table 3.3-2, the staff verified that the

applicant credited AMPs that are appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the

HVAC-Main Control Room will effectively manage or monitor the aging effects identified in the

LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.8 HVAC-Reactor Building

Summary of Technical Information in the Application. The description of the HVAC-Reactor

Building can be found in Section 2.3.3.8 of this SER. The passive, long-lived components inthis system that are subject to an AMR are identified in LRA Table 2.3.3-8. The components,

aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

Aging Effects

Table 2.3.3-28 of the LRA lists individual system components within the scope of license

renewal and subject to AMR. The components include doors, closure bolts, duct fittings,

equipment frames (including dampers, duct, housings, piping, and valves), hinges, latches,

tubing, and valves. Listed components particular only to Dresden include debris screens,

housing and supports, filters/strainers, piping and fittings, and seals.

Aluminum-zinc alloy components exposed to warm, moist air have no aging effect. Carbon steel

components exposed to warm, moist air are subject to the aging effect of loss of material due to

general, pitting, and crevice corrosion. Stainless steel components exposed to warm, moist air

or saturated air are subject to the aging effect of loss of material due to pitting and crevice

corrosion. Copper and copper alloys exposed to saturated air are subject to the aging effect of

loss of material due to pitting and crevice corrosion. Copper, copper alloys, and stainless steel

exposed to air, moisture, and humidity experience no aging effects.

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the

HVAC-Reactor Building:

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* Compressed Air Monitoring Program (B.1.16)

* One-Time Inspection Program (B.1.23)

* Periodic Inspection of Ventilation System Elastomers Program (B.2.3)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the HVAC-Reactor Building will be

adequately managed by these AMPs during the period of extended operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, on

components in the HVAC-Reactor Building. The staff also reviewed the applicable UFSAR

* Supplements for the AMPs to ensure that the program descriptions adequately describe the

AMPs.

Aging Effects

The staff reviewed the information in Section 2.3.3.8, Table 2.3.3-8, and Tables 3.3-1 and 3.3-2

in the LRA. During its review, the staff determined that additional information was needed.

The description in item 3.3.2.130 of Table 3.3-2 lists loss of materialcorrosion as an aging effect/mechanism for carbon steel, stainless steel, brass, or bronze components in an

environment of air, moisture, humidity, and leaking fluid. However, the LRA does not

specifically identify which type of corrosion is responsible for the loss of material. The type of

corrosion is important because it determines the susceptible locations to be inspected. By letter

dated August 4, 2003, the staff requested, in RAI 3.3-2, the applicant to provide a specific

description of the types of corrosion responsible for the aging effect of loss of material for the

relevant components, as well as the criteria for selecting these samples, including susceptible

locations for inspections. The staff's evaluation of the applicant's response is documented in

Section 3.3.2.5.2 of this SER.

Carbon steel, stainless steel, brass, and bronze components exposed to moist gas (moist

nitrogen) or a moist air environment may experience the aging effect of loss of material due to

general (for carbon steel only), pitting, and crevice corrosion (for both carbon steel and

stainless steel) when pollutants such as oxygen, SO2, NOx, or CO are present in the moist air,

particularly when the humidity is greater than 60 percent. However, in Table 3.3-2, the

applicant concluded that no aging effects were identified for the external surfaces of the carbon

steel and stainless steel piping and fittings, accumulators, dampeners, filters/strainers, flow

elements, pumps, orifices, rupture discs, tanks, tubing, and valves exposed to either the

containment nitrogen gas environment or the air, moisture, and humidity environment because

these components are not subject to any viable aging mechanism in the absence of aggressive

chemical species. By letter dated August 4, 2003, the staff issued RAI 3.3-3 requesting the

applicant to provide information to justify the conclusions in Table 3.3-2, Reference Nos.

3.3.2.27 and 3.3.2.40 as to whether pollutants such as oxygen, NOx, SO2, or CO are present,

and if so, to what extent, in the containment gas or air, moisture, and humidity environments.

The staff's evaluation of the applicant's response is documented in Section 3.3.2.5.3 of this

SER.

Aluminum and aluminum alloys components may experience general, pitting, and crevice

corrosion when exposed to moisture and humidity environments, especially with the presence

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of contaminants and water (condehsation from moist air). However, AMR Reference No.

3.3.2.126 of Table 3.3-2 of the LRA only identifies loss of material due to general and pitting

corrosion as a plausible aging effect for aluminum components exposed to moist air. In Table

3.3-2, Reference No. 3.3.2.21 of the LRA, the applicant concluded that there is no aging effect

on the aluminum components of the air handlers heating/cooling system exposed to an air,

moisture, and humidity environment. By letter dated August 4, 2003, the staff requested, in RAI

3.3-4, the applicant to (1) explain the different conclusions on aging effects described above,

(2) provide the technical basis for not including loss of material due to crevice corrosion as an

applicable aging effect, and (3) clarify if there is any condensate on the aluminum fins of the

cooling coils. The staff's evaluation of the applicant's response is documented in Section

3.3.2.5.4 of this SER.

Loss of material due to selective leaching may be an applicable aging effect for copper alloy

components exposed to a saturated air environment where water condensation on the surfaces

of these components may occur. However, in LRA Table 3.3-2, Reference No. 52, 242, and

262, loss of material due to selective leaching was not identified as an applicable aging effect

for copper alloy components in saturated air. By letter dated August 4, 2003, the staff issued

RAI 3.3.2.4.8 requesting the applicant to provide the technical basis for excluding this aging

effect from AMR.

In its response dated October 3, 2003, the applicant stated that the copper alloy materials of

Aging Management References 3.3.2.52, 3.3.2.242, and 3.3.2.262 are used in compressed gas

and ventilation systems at Dresden and Quad Cities. These are not installed in areas where

water would be expected to pool. For Aging Management References 3.3.2.52, 3.3.2.242, and

3.3.2.262, the susceptible materials, copper alloys, are not exposed to water for prolonged

periods and, therefore, selective leaching is not considered an aging mechanism for Dresden

and Quad Cities applications. The staff requested the applicant to provide clarification, with

justification, on how long is considered a prolonged period to support the conclusion that

selective leaching is not considered an applicable aging mechanism.

In its response dated December 17, 2003, the applicant stated that the copper alloy

components used in the reactor building HVAC system, and referenced in Aging Management

References 3.3.2.52, 3.3.2.242, and 3.3.2.262, contain air (instrument and process air) as their

process fluid. The applicable components are (1) tubing for instrumentation, (2) restricting

orifice (filter/strainer) for differential pressure instrument, and (3) tubing, manualcheck valves,

and solenoid valves for air-operated dampers and valves. These components are located in

the reactor building general areas where the relative humidity level is a maximumbof 90 percent.

Neither the internal process nor the external environments could cause wetting of these

components. The statement, "not exposed to water for prolonged periods," refers to the fact

that the only potential source of wetting would be exposure to leaks from other systems. Since

the HVAC controls are located in the reactor building general areas, these leaks would be

detected by operators during their rounds and corrected. Operator rounds in the reactor'

building are performed at least once per day, so the duration of wetting would at most be a few

days, assuming the leakage starts small. Therefore, the copper alloy components in the

reactor building HVAC are not subject to an aggressive wetted environment conducive to

promoting a loss of material due to selective leaching. The external environment AMR results

for these components are provided in LRA Reference Nos. 3.3.2.23 and 3.3.2.34.

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The staff finds the applicant's additional response to the RAI 3.3.2.4-8 supplemental information

request adequate and acceptable because the applicant has demonstrated that the occasions

in which the copper alloy components could come in contact with water are very rare and the

periods during which these components are wet, if any, are very limited (only a few days).

Therefore, no aging management is required for the copper alloy components in the

HVAC-Reactor Building.

The aging effects identified in the LRA for the HVAC-Reactor Building are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible the aging effects were identified and that the aging effects listed are appropriate

for the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the HVAC-Reactor Building.

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* Periodic Inspection of Ventilation System Elastomers Program (Section 3.0.3.17)

These AMPs are credited for managing the aging effects on components in several structures

and systems and, therefore, are considered common AMPs. The staff's evaluation of these

AMPs is documented in Sections 3.0.3.8, 3.0.3.10, and 3.0.3.17, respectively, of this SER.

After evaluating the applicant's AMR for each of the components in the HVAC-Reactor

Building, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects for this system. For those components identified in Table

3.3-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by the

GALL Report. For the components identified in LRA Table 3.3-2, the staff verified that the

applicant credited AMPs that are appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the

HVAC-Reactor Building will effectively manage or monitor the aging effects identified in the

LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.9 Emergency Core Cooling System Corner Room HVAC

Summary of Technical Information in the Application. The description of the ECCS corner room

HVAC can be found in Section 2.3.3.9 of this SER. The passive, long-lived components in this

system that are subject to an AMR are identified in LRA Table 2.3.3-9. The components, aging

effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

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Aging Effects

Table 2.3.3-9 of the LRA lists individual system components within the scope of license renewal

and subject to AMR. The components include air handlers heating/cooling (Aux & RW HVAC),

duct and fittings, access doors, closure bolting, and equipment frames.

The LRA identifies that copper, stainless steel, and carbon steel components exposed to a raw

water environment on one side and a warm, moist air environment on the other side are subject

to the aging effects of loss of material due to general (carbon steel), galvanic, pitting, crevice,

and microbiologically influenced corrosion, erosion or flow-accelerated corrosion, and wear.

Copper, stainless steel, and carbon steel components exposed to a raw water environment on

one side and a warm, moist air environment on the other side are subject to the aging effect of

cracking due to fatigue and SCC. Copper tubes exposed to a raw water environment are also

subject to the loss of heat transfer function aging effect due to buildup of deposit and fouling.

Aluminum fins exposed to a warm, moist air environment experience no aging effects.

Aluminum fins connected to copper tubes are subject to loss of material due to galvanic

corrosion.

Aging Management Programs

The following AMP is utilized to manage the identified aging effects in the ECCS corner room

HVAC:

* Open-Cycle Cooling Water System Program (B.1.13)

A description of this AMP is provided in Appendix B of the LRA. The applicant concluded that

the effects of aging associated with the components of the air handler components of the

ECCS corner room HVAC will be adequately managed by this AMP during the period of

extended operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMP credited for managing the aging effects, in the ECCS

corner room HVAC. The staff also reviewed the applicable UFSAR Supplements for the AMP

to ensure that the program descriptions adequately describe the AMP.

Aging Effects

The staff reviewed the information in Section 2.3.3.9, Table 2.3.3-9, and Tables 3.3-1 and 3.3-2

in the LRA. During its review, the staff determined that additional information was needed.

By letter dated August 4, 2003, the staff requested, in RAI 3.3-7, the applicant to clarify which

specific AMP(s) is applicable for managing AMR item 3.3.1.5, "Specific Corrosion Mechanism,"

and to explain how the AMP(s) manages that corrosion mechanism for components in various

systems, including the ECCS corner room HVAC system. The staff's evaluation of the

applicant's response is documented in Section 3.3.2.5.7 of this SER.

Normally, HVAC systems contain elastomer materials, but no elastomer materials are identified

in LRA Table 2.3.3-9. By letter dated August 4, 2003, the staff requested, in RAI 3.3.2.4.9, the

applicant to clarify if there are any elastomer components in the ECCS corner room HVAC. By

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letter dated October 3, 2003, the applicant responded that there is no ductwork attached to the

cooler and there are no flexible collars, damper or door gaskets, seals, or other soft parts

associated with the ECCS corner room HVAC system. This response is acceptable because it

clarifies that there are no elastomers in the ECCS corner room HVAC system.

The aging effects identified in the LRA for the ECCS comer room HVAC system are consistent

with industry operating experience for the materials and environments listed. The staff finds

that all the plausible the aging effects were identified and that the aging effects listed are

appropriate for the combination of materials and environments specified.

Aging Management Programs

The applicant credited the following AMP to manage the aging effects described above for the

ECCS corner room HVAC:

Open-Cycle Cooling Water System Program (Section 3.0.3.6)

This AMP is credited for managing the aging effects of components in several structures and

systems and, therefore, is considered a common AMP. The staff's evaluation of this AMP is

documented in Section 3.0.3.6 of this SER.

After evaluating the applicant's AMR for each of the components in the ECCS corner room

HVAC system, the staff evaluated the AMP listed above to determine if it is appropriate for

managing the identified aging effects. For those components identified in Table 3.3-1 of the

LRA, the staff verified that the applicant credited the AMP recommended by the GALL Report.

For the components identified in LRA Table 3.3-2, the staff verified that the applicant credited

an AMP that is appropriate for the identified aging effects.

The response to RAI 3.3-7 clarified that the Open-Cycle Cooling Water System Program is

used to manage external surfaces in the ECCS corner room HVAC system.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the ECCS corner

room HVAC system will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.10 Station Blackout Building HVAC

Summary of Technical Information in the Application. The description of the station blackout

building HVAC can be found in Section 2.3.3.10 of this SER. The passive, long-lived

components in this system that are subject to an AMR are identified in LRA Table 2.3.3-10.

The components, aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

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Aging Effects

Table 2.3.3.10 of the LRA lists individual system components within the scope of license

renewal and subject to an AMR. The components include air handlers heating/cooling (DGB

HVAC (Quad Cities only)), debris screens, duct fittings, hinges, latches, flow elements, and

tubing.

Carbon steel components are subject to loss of material due to general, pitting, and crevice

corrosion and MIC [for duct (drip-pan) and piping for moisture drainage] from exposure to

warm, moist air. Stainless steel and copper components are subject to loss of material due to

pitting and crevice corrosion from exposure to warm, moist air. Exposure of aluminum-zinc

alloy components to warm, moist air has no aging effect. Copper tubes and galvanized steel

end bells are identified as being subject to loss of material due to galvanic, pitting, and crevice

corrosion and wear from exposure to refrigerant on the tube side and warm, moist air on the

shell side. Copper tubes are also identified as being subject to buildup of deposits and fouling

from exposure to refrigerant on the tube side and warm, moist air on the shell side.

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the station

blackout building HVAC:

* Bolting Integrity Program (B.1.12)

* Open-Cycle Cooling Water System Program (B.1.13)

* One-Time Inspection-Ventilation System (B.1.23)

* Heat Exchanger Test and Inspection Activities Program (B.2.6)

* Periodic Inspection of Ventilation System Elastomers Program (B.2.3)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the air handler components of the

station blackout building HVAC will be adequately managed by these AMPs during the period of

extended operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, on

components in the station blackout building HVAC. The staff also reviewed the applicable

UFSAR Supplements for the AMPs to ensure that the program descriptions adequately

describe the AMPs.

Aging Effects

The staff reviewed the information in Section 2.3.3.10 and Tables 2.3.3-10, 3.3-1, and 3.3-2 in

the LRA. During its review, the staff determined that additional information was needed.

The description in item 3.3.2.130 of Table 3.3-2 lists loss of material/corrosion as an aging

effect/mechanism for carbon steel, stainless steel, brass, or bronze components in an

environment of air, moisture, humidity, and leaking fluid. However, the LRA does not

specifically identify which type of corrosion is responsible for the loss of material. The type of

corrosion is important because it determines the susceptible locations to be inspected. By letter

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dated August 4, 2003, the staff requested, in RAI 3.3-2, the applicant to provide a specific

description of the types of corrosion responsible for the aging effect of loss of material for the

relevant components, as well as the criteria for selecting these samples, including susceptible

locations for inspections. The staff's evaluation of the applicant's response is documented in

Section 3.3.2.5.2 of this SER.

Carbon steel, stainless steel, brass, and bronze components exposed to moist gas (moist

nitrogen) or a moist air environment may experience the aging effect of loss of material due to

general (for carbon steel only), pitting, and crevice corrosion (for both carbon steel and

stainless steel) when pollutants such as oxygen, SO2, NOR, or CO are present in the moist air,

particularly when the humidity is greater than 60 percent. However, in Table 3.3-2, the

applicant concluded that no aging effects were identified for the external surfaces of the carbon

steel and stainless steel piping and fittings, accumulators, dampeners, filters/strainers, flow

elements, pumps, orifices, rupture discs, tanks, tubing, and valves exposed to either the

containment nitrogen gas environment or the air, moisture, and humidity environment because

these components are not subject to any viable aging mechanism in the absence of aggressive

chemical species. By letter dated August 4, 2003, the staff issued RAI 3.3-3 requesting the

applicant to provide information to justify the conclusions in Table 3.3-2, Reference Nos.

3.3.2.27 and 3.3.2.40 as to whether pollutants such as oxygen, NO,, SO2.or CO are present,

and if so, to what extent, in the containment gas or air, moisture, and humidity environments.

The staff's evaluation of the applicant's response is documented in Section 3.3.2.5.3 of this

SER.

Aluminum and aluminum alloys components may experience general, pitting, and crevice

corrosion when exposed to moisture and humidity environments, especially with the presence

of contaminants and water (condensation from moist air). However, AMR Reference No.

3.3.2.126 of Table 3.3-2 of the LRA only identifies loss of material due to general and pitting

corrosion as a plausible aging effect for aluminum components exposed to moist air. In Table

3.3-2, Reference No. 3.3.2.21 of the LRA, the applicant concluded that there is no aging effect

on aluminum components of the air handlers heating/cooling system exposed to an air,

moisture, and humidity environment. By letter dated August 4, 2003, the staff requested, in RAI

3.3-4, the applicant to (1) explain the different conclusions on aging effects described above,

(2) provide the technical basis for not including loss of material due to crevice corrosion as an

applicable aging effect, and (3) clarify if there is any condensate on the aluminum fins of the

cooling coils. The staff's evaluation of the applicant's response is documented in Section

3.3.2.5.4 of this SER.

By letter dated August 4, 2003, the staff requested, in RAI 3.3-7, the applicant to clarify which

specific AMP(s) is applicable for managing AMR item 3.3.1.5, "Specific Corrosion Mechanism,"

and to explain how the AMP(s) manages that corrosion mechanism for components in various

auxiliary systems. The staff's evaluation of the applicant's response is documented in Section

3.3.2.5.7 of this SER.

The aging effects identified in the LRA for the station blackout building HVAC are consistent

with industry operating experience for the materials and environments listed. The staff finds

that all the plausible the aging effects were identified and that the aging effects listed are

appropriate for the combination of materials and environments specified.

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Aging Management Programs - -'

The applicant has credited the following AMPs to manage the aging effects described above for

the station blackout building HVAC:

* Bolting Integrity Program (Section 3.0.3.5)

* Open-Cycle Cooling Water System Program (Section 3.0.3.6)

* One-Time Inspection-Ventilation System Program (Section 3.0.3.10)

* Heat Exchanger Test and Inspection Activities Program (Section 3.0.3.15)

* Periodic Inspection of Ventilation System Elastomers Program (Section 3.0.3.17)

The Bolting Integrity, Open-Cycle Cooling Water System, One-Time Inspection-Ventilation'

System, Heat Exchanger Test and Inspection Activities, and Periodic Inspection of Ventilation

System Elastomers Programs are credited with managing the aging effects of several

components in different structures and systems and are, therefore, considered common AMPs.

The staff's evaluation of these AMPs is discussed in Sections 3.0.3.5, 3.0.3.6, 3.0.3.10,

3.0.3.15, and 3.0.3.17, respectively, of the SER.

After evaluating the applicant's AMR for each of the components in the station blackout building

HVAC, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects for this system. For those components identified in Table

3.3-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by the

GALL Report. For the components identified in LRA Table 3.3-2, the staff verified that the

applicant credited AMPs that are appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the station

blackout building HVAC will effectively manage or monitor the aging effects identified in the

LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.11 Station Blackout System (Diesel and Auxiliaries)

Summary of Technical Information in the Aoplication. The description of the station blackout

system (diesel and auxiliaries) can be found in Section 2.3.3.11 of this SER. The passive, longlived components in this system that are subject to an AMR are identified in LRA Table 2.3.3-

11. The components, aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

Aging Effects

Table 2.3.3-11 of the LRA lists individual system components within the scope of license

renewal and subject to an AMR. The components include air accumulators, closure bolting,

filters/strainers, flexible hoses, flow elements, heat exchangers (includes coolers and heat

exchangers), lubricators, mufflers, piping and fittings (includes heaters, orifices, and

thermowells), pumps, restricting orifices, sight glasses, thermowells, tubing, turbochargers, and

valves.

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High-strength, low-alloy steel closure bolting components exposed to outdoor ambient air are

subject to the aging effect of loss of material due to general corrosion and wear. Aluminum

components exposed to an air, moisture, and humidity environment experience no aging

effects. Aluminum components exposed to a moist air environment are subject to the aging

effect of loss of material due to general and pitting corrosion. Aluminum components exposed

to a diesel fuel oil environment are subject to the aging effect of loss of material due to general,

pitting, crevice, and microbiologically influenced corrosion.

Cast iron components exposed to a diesel fuel oil environment are subject to the aging effect of

loss of material due to general, pitting, crevice, and microbiologically influenced corrosion. Cast

iron components exposed to a lubricating oil environment are subject to the aging effect of loss

of material due to general, pitting, and crevice corrosion. Cast iron components exposed to a

moist air environment are subject to the aging effect of loss of material due to general, pitting,

and crevice corrosion. Cast iron components exposed to an air, moisture, and humidity

environment are subject to the aging effect of loss of material due to pitting and crevice

corrosion. Cast iron components exposed to a treated demineralized water less than 90 'C

(194 'F) environment are subject to the aging effect of loss of material due to general, galvanic,

pitting, crevice, and microbiologically influenced corrosion and selective leaching. Cast iron

components exposed to hot diesel engine gases containing moisture and particles are subject

to the aging effect of loss of material due to general, pitting, and crevice corrosion.

Carbon steel components exposed to lubricating oil (with contaminants and/or water) are

subject to the aging effect of loss of material due to general, pitting, crevice, and

microbiologically influenced corrosion. Carbon steel or cast steel components exposed to

Glycol-based cooling water are subject to the aging effects of loss of material due to general,

galvanic, pitting, crevice, and microbiologically influenced corrosion, erosion or flow-accelerated

corrosion, and wear and cracking due to mechanical fatigue. Carbon steel or cast steel

components exposed to outdoor ambient air are subject to the aging effect of loss of material

due to general, pitting, and crevice corrosion.

Stainless steel components exposed to chemically treated demineralized water less than 90 OC

(194 'F) are subject to the aging effect of cracking due to SCC and IGSCC. Stainless steel

components exposed to lubricating oil (with contaminants and/or water) or moist air are subject

to the aging effect of loss of material due to pitting and crevice corrosion. Stainless steel

components exposed to diesel fuel oil are subject to the aging effect of loss of material due to

pitting and crevice corrosion. Stainless steel components exposed to moist air are subject to the

aging effect of loss of material due to pitting and crevice corrosion. Stainless steel components

exposed to air, moisture, and humidity experience no aging effects.

Copper piping and fittings or copper alloy thermowell or heat exchanger tubes exposed to

Glycol-based cooling water are subject to the aging effects of loss of material due to general,

galvanic, pitting, crevice, and microbiologically influenced corrosion, erosion or flow-accelerated

corrosion, wear (except thermowell), cracking due to mechanical fatigue (except thermowell),

and selective leaching (copper alloy). Copper heat exchanger tubes exposed to Glycol-based

cooling water are also subject to the aging effect of loss of intended function due to buildup of

deposit/fouling. Copper alloy components exposed to diesel fuel oil or lubricating oil are subject

to the aging effect of loss of material due to general, crevice, and pitting corrosion. Copper or

copper alloy components exposed to an air, moisture, and humidity environment experience no

aging effects.

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Neoprene components exposed to dry gas or saturated air are subject to the aging effects of

hardening and loss of strength and elastomer degradation. Iron malleable components exposed

to chemically treated demineralized water environments are subject to the aging effects of loss

of material due to general, galvanic, pitting, crevice, and microbiologically induced corrosion

and selective leaching. Iron malleable components exposed to a lubricating oil environment are

subject to the aging effects of loss of material due to general, galvanic, pitting, and crevice

corrosion. Iron malleable components exposed to an air, moisture, and humidity environment

experience no aging effects. Glass components exposed to chemically treated demineralized

water or air, moisture, and humidity environments experience no aging effects.

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the station

blackout system (diesel and auxiliaries):

* Bolting Integrity Program (B.1.12)

* Closed-Cycle Cooling Water System Program (B.1.14)

* Fuel Oil Chemistry Program (B.1.21)

* One-Time Inspection-Compressed Gas Program (B.1.23)

* Selective Leaching of Materials Program (B.1.24)

* Buried Piping and Tanks Inspections Program (B.1.25)

* Structures Monitoring Program (B.1.30)

* Lube Oil Monitoring Activities Program (B.2.5)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the station blackout system (diesels

and auxiliaries) will be adequately managed by these AMPs during the period of extended

operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, in the station

blackout system (diesel and auxiliaries). The staff also reviewed the applicable UFSAR

Supplements for the AMPs to ensure that the program descriptions adequately describe the

AMPs.

Aging Effects

The staff reviewed the information in Section 2.3.3.11, Table 2.3.3-11, and Tables 3.3-1 and

3.3-2 in the LRA. During its review, the staff determined that additional information was

needed.

The description in item 3.3.2.130 of Table 3.3-2 lists loss of materialcorrosion as an aging

effect/mechanism for carbon steel, stainless steel, brass, or bronze components in an

environment of air, moisture, humidity, and leaking fluid. However, the LRA does not

specifically identify which type of corrosion is responsible for the loss of material. The type of

corrosion is important because it determines the susceptible locations to be inspected. By letter

dated August 4, 2003, the staff requested, in RAI 3.3-2, the applicant to provide a specific

description of the types of corrosion responsible for the aging effect of loss of material for the

relevant components, as well as the criteria for selecting these samples, including susceptible

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locations for inspections. The staff's evaluation of the applicant's response is documented in

Section 3.3.2.5.2 of this SER.

Carbon steel, stainless steel, brass, and bronze components exposed to moist gas (moist

nitrogen) or a moist air environment may experience the aging effect of loss of material due to

general (for carbon steel only), pitting, and crevice corrosion (for both carbon steel and

stainless steel) when pollutants such as oxygen, SO2, NO,, or CO are present in the moist air,

particularly when the humidity is greater than 60 percent. However, in Table 3.3-2, the

applicant concluded that no aging effects are identified for the external surfaces of the carbon

steel and stainless steel piping and fittings, accumulators, dampeners, filters/strainers, flow

elements, pumps, orifices, rupture discs, tanks, tubing, and valves exposed to either the

containment nitrogen gas environment or an air, moisture, and humidity environment because

these components are not subject to any viable aging mechanism in the absence of aggressive

chemical species. By letter dated August 4, 2003, the staff issued RAI 3.3-3 requesting the

applicant to provide information to justify the conclusions in Table 3.3-2, Reference Nos.

3.3.2.27 and 3.3.2.40 as to whether pollutants such as oxygen, NO,, SO2 or CO are present,

and if so, to what extent, in the containment gas or air, moisture, and humidity environments.

The staff's evaluation of the applicant's response is documented in Section 3.3.2.5.3 of this

SER.

Aluminum and aluminum alloys components may experience general, pitting, and crevice

corrosion when exposed to moisture and humidity environments, especially with the presence

of contaminants and water (condensation from moist air). However, AMR Reference No.

3.3.2.126 of Table 3.3-2 of the LRA only identifies loss of material due to general and pitting

corrosion as a plausible aging effect for aluminum components exposed to moist air. In Table

3.3-2, Reference No. 3.3.2.21 of the LRA, the applicant concluded that there is no aging effect

on the aluminum components of the air handlers heating/cooling system exposed to an air,

moisture, and humidity environment. By letter dated August 4, 2003, the staff requested, in RAI

3.3-4, the applicant to (1) explain the different conclusions on aging effects described above,

(2) provide the technical basis for not including loss of material due to crevice corrosion as an

applicable aging effect, and( 3) clarify if there is any condensate on the aluminum fins of the

cooling coils. The staff's evaluation of the applicant's response is documented in Section

3.3.2.5.4 of this SER.

In LRA Table 3.3-2, Reference No. 3.3.2.18, the applicant stated that high-strength, low-alloy

steel closure bolting components in the outdoor ambient conditions are subject to the aging

effect of loss of material due to general corrosion and wear. However, the applicant does not

include crack initiation and growth due to SCC or other mechanisms as an applicable aging

effect/mechanism. By letter dated August 4, 2003, the staff requested, in RAI 3.3-5, the

applicant to provide its technical basis for not including this aging effect/mechanism. The staff's

evaluation of the applicant's response is documented in Section 3.3.2.5.5 of this SER.

Loss of material due to selective leaching is a plausible aging effect for cast iron components in

a moist air and humidity environment, especially when there is water condensation on the

surfaces of these components. However, in LRA Table 3.3-2, Reference No. 55, loss of

material due to selective leaching was not identified as a plausible aging effect for cast iron

components in moist air. By letter dated August 4, 2003, the staff issued RAI 3.3.2.4.11 (a)

requesting the applicant to provide its technical basis for excluding this aging effect from the

AMR. In its response dated October 3, 2003 and Supplemental RAI 3.3.2.4.11 response dated

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December 22, 2003, the applicant stated that the cast iron material components in AMR

Reference No. 3.3.2.55 are not installed in areas where water or condensation would be

expected to pool or where there would be prolonged exposure to water; therefore, the applicant

concluded that selective leaching is not considered an aging mechanism for Dresden and Quad

Cities applications. Since the fuel oil strainers covered by AMR Reference No. 3.3.2.55 are not

installed in areas where water or condensation would pool or where there would be a prolonged

exposure to water, the staff concludes that it is unlikely for the strainers to experience selective

leaching. The staff also notes that these components will receive a one-time inspection for loss

of material and that this inspection would identify selective leaching if it were to occur.

Therefore, the staff finds the identification of aging effects and the aging management

acceptable for the strainers.

Loss of material due to pitting and crevice corrosion is a plausible aging effect on stainless steel

exposed to a chemically treated and demineralized water environment. However, in Table

2.3.3-11 of the LRA, the applicant did not identify any loss of material aging effect on the

stainless steel components exposed to a chemically treated and demineralized water

environment. By letter dated August 4, 2003, the staff issued RAI 3.3.2.4.11 (b) requesting the

applicant to provide its technical basis for excluding this applicable aging effect. In its response

dated October 3, 2003, the applicant concurred that stainless steel in a treated water

environment may be susceptible to loss of material due to pitting and crevice corrosion. The

applicant added aging management references to address this aging effect/mechanism for the

components in the station blackout system (diesels and auxiliaries), and the applicant credited

the Closed-Cycle Cooling Water System Program (B.1.14). Since the applicant has identified

loss of material due to pitting and crevice corrosion for the stainless steel components exposed

to chemically treated and demineralized water, and has identified an appropriate AMP to

manage this aging effect, the staff finds this acceptable.

The aging effects identified in the LRA for the station blackout system (diesels and auxiliaries)

are consistent with industry operating experience for the materials and environments listed.

The staff finds that all the plausible the aging effects were identified and that the aging effects

listed are appropriate for the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the station blackout system (diesels and auxiliaries):

* Bolting Integrity Program (Section 3.0.3.5)

* Closed-Cycle Cooling Water System Program (Section 3.0.3.7)

* One-Time Inspection-Compressed Gas Program (Section 3.0.3.10)

* Selective Leaching of Materials Program (Section 3.0.3.11)

* Buried Piping and Tanks Inspections Program (Section 3.0.3.12)

* Structures Monitoring Program (Section 3.0.3.14)

* Fuel Oil Chemistry Program (Section 3.3.2.3.5)

* Lube Oil Monitoring Activities Program (Section 3.0.3.16)

* Periodic Inspection of Components Subject to Moist Environments (3.0.3.18)

As part of RAI B.1.23.2-6, the staff questioned the use of the one-time inspections to manage

aging for components in a moist air environment. In its response dated March 25, 2004, the

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applicant credited the Periodic Inspection of Components Subject to Moist Environments

program to manage aging effects for stainless steel, carbon steel, cast iron, aluminum, copper,

and brass and bronze components exposed to moist air environments and subject to wetting.

The staff's evaluation of the Periodic Inspection of Components Subject to Moist Environments

AMP is contained in SER section 3.0.3.1 8.

These AMPs are credited for managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. The staff's evaluation of these

AMPs is documented in Sections 3.0.3.5, 3.0.3.7, 3.0.3.10, 3.0.3.11, 3.0.3.12, 3.0.3.14,

3.3.2.3.5, and 3.3.2.3.7, respectively, of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the station

blackout system (diesels and auxiliaries) will effectively manage or monitor the aging effects

identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.12 Diesel Generator Cooling Water System

Summary of Technical Information in the Application. The description of the diesel generator

cooling water system can be found in Section 2.3.3.12 of this SER. The passive, long-lived

components in this system that are subject to an AMR are identified in LRA Tables 2.3.3-12.

The components, aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

Aging Effects

Table 2.3.3-12 of the LRA lists individual system components that are within the scope of

license renewal and subject to AMR. The components include air handlers heating/cooling

(DGB HVAC), closure bolting, NSR vents or drains, piping and valves, orifice bodies, tubing,

pumps, thermowells, pulsation dampers, strainer screens, and strainer bodies.

The LRA identifies that copper, carbon steel, and aluminum components in open-cycle cooling

water and warm, moist air environments are subject to the aging effects of cracking from

mechanical fatigue and SCC, as well as loss of material from general, pitting, crevice, and

galvanic corrosion, MIC, erosion or flow-accelerated corrosion, and wear. Copper components

in a raw water environment are also subject to buildup of deposit from fouling. Loss of material

due to general corrosion and wear is an applicable aging effect for high-strength, low-alloy steel

components. The LRA identifies that carbon steel, stainless steel, brass, and bronze

components in an air, moisture, humidity, and leaking fluid environment are subject to loss of

material from general corrosion and pitting and crevice corrosion. Cast iron (lined or unlined)

components in raw water or fresh water environments are subject to loss of material from

selective leaching, general, pitting, crevice, and galvanic corrosion, erosion, and MIC.

Additional aging effects for cast iron components in the same environments include flow

blockage from biofouling, silting, and corrosion product buildup. The applicant identified flow

blockage from biofouling as the only applicable aging effect for titanium components in raw

water or fresh water environments. The LRA does not identify any aging effects for stainless

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steel components in an environment of air, moisture, and humidity less than 100 *C (212 OF) or

for titanium components in an air, moisture, humidity, and leaking fluid environment.

Aging Management Programs

The following AMPs are utilized to manage the aging effects in the diesel generator cooling

water system:

* Open-Cycle Cooling Water System Program (B.1.13)

* Bolting Integrity Program (B.1.12)

* One-Time Inspection Program (B.1.23)

* Selective Leaching of Materials Program (B.1.24)

* Buried Piping and Tanks Inspection Program (B.1.25)

* Structures Monitoring Program (B.1.30)

* Heat Exchanger Test and Inspection Activities Program (B.2.6)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the diesel generator cooling water

system will be adequately managed by these AMPs during the period of extended operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, in the

components of the diesel generator cooling water system. The staff also reviewed the

applicable UFSAR Supplements for the AMPs to ensure that the program descriptions

adequately describe the AMPs.

Aging Effects

The staff reviewed the information in Tables 2.3.3-12, 3.3-1, and 3.3-2 for the diesel generator

cooling water system. During its review, the staff determined that additional information was

needed.

The description in tem 3.3.2.130 of Table 3.3-2 lists loss of materialcorrosion as an aging

effect/mechanism for carbon steel, stainless steel, brass, or bronze components in an

environment of air, moisture, humidity, and leaking fluid. However, the LRA does not

specifically identify which type of corrosion is responsible for the loss of material. The type of

corrosion is important because it determines the susceptible locations to be inspected. By letter

dated August 4, 2003, the staff requested, in RAI 3.3-2, the applicant to provide a specific

description of the types of corrosion responsible for the aging effect of loss of material for the

relevant components, as well as the criteria for selecting these samples, including susceptible

locations for inspections. The staff's evaluation of the applicant's response is documented in

Section 3.3.2.5.2 of this SER.

Carbon steel, stainless steel, brass, and bronze components exposed to moist gas (moist

nitrogen) or a moist air environment may experience the aging effect of loss of material due to

general (for carbon steel only), pitting, and crevice corrosion (for both carbon steel and

stainless steel) when pollutants such as oxygen, SO2 , NO., or CO are present in the moist air,

particularly when the humidity is greater than 60 percent. However, in Table 3.3-2, the

applicant concluded that no aging effects were identified for the external surfaces of the carbon

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I

steel and stainless steel piping and fittings, accumulators, dampeners, filters/strainers, flow

elements, pumps, orifices, rupture discs, tanks, tubing, and valves exposed to either the

containment nitrogen gas environment or an air, moisture, and humidity environment because

these components "are not subject to any viable aging mechanism in the absence of

aggressive chemical species." By letter dated August 4, 2003, the staff issued RAI 3.3-3

requesting the applicant to provide information to justify the conclusions in Table 3.3-2,

Reference Nos. 3.3.2.27 and 3.3.2.40 as to whether pollutants such as oxygen, NOR, SO2.or

CO are present, and if so, to what extent, in the containment gas or air, moisture, and humidity

environments. The staff's evaluation of the applicant's response is documented in Section

3.3.2.5.3 of this SER.

In LRA Table 3.3-2, Reference No. 3.3.2.18, the applicant stated that high-strength, low-alloy

steel closure bolting components in the outdoor ambient conditions are subject to the aging

effect of loss of material due to general corrosion and wear. However, the applicant does not

include crack initiation and growth due to SCC or other mechanisms as an applicable aging

effect/mechanism. By letter dated August 4, 2003, the staff requested, in RAI 3.3-5, the

applicant to provide its technical basis for not including this aging effect/mechanism. The staff's

evaluation of the applicant's response is documented in Section 3.3.2.5.5 of this SER.

By letter dated August 4, 2003, the staff requested, in RAI 3.3-7, the applicant to clarify which

specific AMP(s) is applicable for managing AMR item 3.3.1.5, "Specific Corrosion Mechanism,"

and to explain how the AMP(s) manages that corrosion mechanism for components in various

systems, including the diesel generator cooling water system. The staff's evaluation of the

applicant's response is documented in Section 3.3.2.5.7 of this SER.

The staff identified that LRA Table 3.3-2, Reference No. 3.3.2.16 lists loss of material from

erosion or flow-accelerated corrosion as an applicable aging effect/mechanism. The OpenCycle Cooling Water System Program (B.1.13) is identified as the applicable AMP. By letter

dated August 4, 2003, the staff requested, in part (a) of RAI 3.3.2.4.12, the applicant to clarify

whether erosion or flow-accelerated corrosion is the applicable aging mechanism for

components in the diesel generator cooling water system identified in Table 2.3.3-12 in the

LRA. If erosion is the applicable aging mechanism, and not flow-accelerated corrosion, the

applicant was requested to state so explicitly in the LRA. Otherwise, the staff requested the

applicant to clarify how the Open-Cycle Cooling Water System Program (B.1 .13) will manage

the aging effect of loss of material due to flow-accelerated corrosion.

Furthermore, the staff identified that NUREG-1 800, Section 3.3.2.2.11, states that loss of

material due to general, pitting, and crevice corrosion and MIC could occur in the underground

piping and fittings in the open-cycle cooling water system. The Dresden UFSAR Section 9.5.5

states that the remaining part of the system's piping and valves traverse to and from the

missile-protected diesel and reactor buildings via a reinforced concrete tunnel that runs below

ground. By letter dated August 4, 2003, the staff requested, in part (b) of RAI 3.3.2.4.12, the

applicant to clarify if there is any underground piping in the diesel generator cooling water

system that is buried or inaccessible. If buried or inaccessible piping does exist, the staff

requested the applicant to explain how such piping will be managed for loss of material during

the period of extended operation.

In its response dated October 3, 2003, the applicant stated, with regard to part (a) of the RAI,

that Exelon has reviewed LRA Table 3.3-2, Aging Management Reference 3.3.2.16, for loss of

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material due to erosion or flow-accelerated corrosion as an applicable aging effect/mechanism.

Flow-accelerated corrosion is not the valid aging mechanism for heat exchangers in the scope

of license renewal since heat exchangers are operated within their design flow and operating

parameters. The applicant clarified that LRA Table 3.3-2, Aging Management Reference

3.3.2.16, should have only stated erosion as the aging mechanism, instead of erosion or flowaccelerated corrosion.

With regard to part (b) of the RAI, the applicant stated that the diesel generator cooling water

system piping traverses to the crib house from the missile-protected diesel and turbine buildings

via a reinforced concrete tunnel. However, the tunnel does not extend completely from the

turbine building to the crib house. Portions of the diesel generator cooling water piping do run

underground (buried) to the crib house. The applicant clarified that LRA Section 2.3.3.12,

Table 2.3.3-12, should have included buried piping Aging Management Reference 3.3.1.16

under "Piping and Fittings" with pressure boundary as the component intended function. LRA

Table 3.3-1, Aging Management Reference 3.3.1.16, discusses the aging management of

buried piping and fittings for loss of material due to general, pitting, and crevice corrosion and

MIC. Finally, the applicant stated that the Buried Piping and Tanks Inspection Program (B.1.25)

will manage the aging of the diesel generator cooling water system buried piping and piping

components.

The staff finds the applicant's response to RAI 3.3.2.4.12 acceptable because (1) the applicant

clarified that LRA Table 3.3-2, Aging Management Reference 3.3.2.16, should have stated only

erosion as the aging mechanism, instead of erosion or flow-accelerated corrosion, and (2) the

applicant clarified that LRA Section 2.3.3.12, Table 2.3.3-12, should have included buried piping

Aging Management Reference 3.3.1.16 under "Piping and Fittings" with pressure boundary as

the component intended function. In addition, the applicant stated that the Buried Piping and

Tanks Inspection Program (B.1.25) is the applicable AMP. The staff considers the issues

related to RAI 3.3.2.4.12 to be resolved.

The aging effects identified in the LRA for the diesel generator cooling water system are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible the aging effects were identified and that the aging effects listed

are appropriate for the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the diesel generator cooling water system:

* Open-Cycle Cooling Water System Program (Section 3.0.3.6)

* Bolting Integrity Program (Section 3.0.3.5)

* One-Time Inspection Program (Section 3.0.3.10)

* Selective Leaching of Materials Program (Section 3.0.3.1 1)

* Heat Exchanger Test and Inspection Activities Program (Section 3.0.3.16)

* Structures Monitoring Program (Section 3.0.3.14 )

* Buried Piping and Tanks Inspection Program (Section 3.0.3.12)

These AMPs are credited for managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. These AMPs are evaluated in

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Sections 3.0.3.6, 3.0.3.5, 3.0.3.10,3.0.3.11, 3.0.3.16, 3.0.3.14, and 3.0.3.12, respectively, of

this SER.

After evaluating the applicant's AMR for each of the components in the diesel generator cooling

water system, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects. For those components identified in Table 3.3-1 of the

LRA, the staff verified that the applicant credited the AMPs recommended by the GALL Report.

For the components identified in LRA Table 3.3-2, the staff verified that the applicant credited

AMPs that are appropriate for the identified aging effects.

The response to RAI 3.3-7 identified that the Heat Exchanger Testing and Inspection Program

(B.2.6), the Bolting Integrity Program (B.1.12), and the Structures Monitoring Program (B.1.30)

would be used to manage aging effects in the diesel generator cooling water system.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the diesel

generator cooling water system will effectively manage or monitor the aging effects identified in

the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.13 Diesel Fuel Oil System

Summary of Technical Information in the Application. The description of the diesel fuel oil

system can be found in Section 2.3.3.13 of this SER. The passive, long-lived components in

this system that are subject to an AMR are identified in LRA Table 2.3.3-13. The components,

aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

Aging Effects

Table 2.3.3-13 of the LRA lists individual system components within the scope of license

renewal and subject to AMR. The components include closure bolting, filters/strainers, flame

arresters, piping and fittings, piping and fittings (attached support), pumps, restricting orifices

(Quad Cities only), sight glasses, tanks, tubing, valves, and valves (attached support).

The LRA identifies that high-strength, low-alloy steel closure bolting components exposed to

outdoor ambient air are subject to the aging effect of loss of material due to general corrosion

and wear. Cast iron components exposed to an air, moisture, and humidity environment are

subject to the aging effect of loss of material due to pitting and crevice corrosion. Cast iron

components exposed to diesel fuel oil are subject to the aging effect of loss of material due to

general, pitting, crevice, and microbiologically influenced corrosion. Carbon steel components

exposed to diesel fuel oil are subject to the aging effect of loss of material due to general,

pitting, crevice, and microbiologically influenced corrosion. Carbon steel components exposed

to outdoor ambient air are subject to the aging effect of loss of material due to general, pitting,

and crevice corrosion. Carbon steel components exposed to lubricating oil (with contaminants

and/or water) are subject to the aging effect of loss of material due to general, pitting, crevice,

and microbiologically influenced corrosion. Carbon steel components exposed to soil and

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ground water are subject to the aging effect of loss of material due to general, pitting,- crevice,

and microbiologically influenced corrosion. Stainless steel components exposed to diesel fuel

oil are subject to the aging effect of loss of material due to pitting and crevice corrosion.

Stainless steel components exposed to air, moisture, and humidity experience no aging effects.

Glass components exposed to fuel oil or air, moisture, and humidity environments experience

no aging effects. Fiberglass components exposed to fuel oil are subject to loss of intended

function due to buildup of deposit and biofouling. Fiberglass components exposed to soil and

groundwater experience no aging effects. Brass or bronze components exposed to diesel fuel

oil are subject to the aging effect of loss of material due to general, pitting, and crevice

corrosion. Brass or bronze components exposed to air, moisture, and humidity experience no

aging effects.

Aging Management Programs

The following AMPs are utilized to manage aging effects in the diesel fuel oil system:

* Bolting Integrity Program (B.1.12)

* Fuel Oil Chemistry Program (B.1.21)

* One-Time Inspection Program (B.1.23)

* Buried Piping and Tanks Inspection Program (B.1.25)

* Structures Monitoring Program (B.1.30)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the diesel fuel oil system will be

adequately managed by these AMPs during the period of extended operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, in the diesel

fuel oil system. The staff also reviewed the applicable UFSAR Supplements for the AMPs to

ensure that the program descriptions adequately describe the AMPs.

Aging Effects

The staff reviewed the information in Section 2.3.3.13, Table 2.3.3-13, and Tables 3.3-1 and

3.3-2 in the LRA. During its review, the staff determined that additional information was

needed.

Metals and alloys that are in contact with different, more cathodic metals or alloys in the

presence of an electrolyte fluid may be subject to the aging effect of loss of material from

galvanic corrosion. Many systems/components of the auxiliary systems described by various

items in Table 3.3-2 of the LRA have material/environment combinations for which loss of

material from galvanic corrosion may be an applicable aging effect/mechanism. However, the

applicant did not include loss of material due to galvanic corrosion as an aging

effect/mechanism that requires management for the period of extended operation. By letter

dated August 4, 2003, the staff issued RAI 3.3-1 pertaining to this issue. The staff's evaluation

of the applicant's response is documented in Section 3.3.2.5.1 of this SER.

The description in item 3.3.2.130 of Table 3.3-2 lists loss of materialcorrosion as an aging

effect/mechanism for carbon steel, stainless steel, brass, or bronze components in an

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environment of air, moisture, humidity, and leaking fluid. However, the LRA does not

specifically identify which type of corrosion is responsible for the loss of material. The type of

corrosion is important because it determines the susceptible locations to be inspected. By letter

dated August 4, 2003, the staff requested, in RAI 3.3-2, the applicant to provide a specific

description of the types of corrosion responsible for the aging effect of loss of material for the

relevant components, as well as the criteria for selecting these samples, including susceptible

locations for inspections. The staff's evaluation of the applicant's response is documented in

Section 3.3.2.5.2 of this SER.

Aluminum and aluminum alloys components may experience general, pitting, and crevice

corrosion when exposed to moisture and humidity environments, especially with the presence

of contaminants and water (condensation from moist air). However, AMR Reference No.

3.3.2.126 of Table 3.3-2 of the LRA only identifies loss of material due to general and pitting

corrosion as a plausible aging effect for aluminum components exposed to moist air. In Table

3.3-2, Reference No. 3.3.2.21 of the LRA, the applicant concluded that there is no aging effect

on the aluminum components of the air handlers heating/cooling system exposed to an air,

moisture, and humidity environment. By letter dated August 4, 2003, the staff requested, in RAI

3.3-4, the applicant to (1) explain the different conclusions on aging effects described above,

(2) provide the technical basis for not including loss of material due to crevice corrosion as an

applicable aging effect, and (3) clarify if there is any condensate on the aluminum fins of the

cooling coils. The staff's evaluation of the applicant's response is documented in Section

3.3.2.5.4 of this SER.

By letter dated August 4, 2003, the staff requested, in RAI 3.3-7, the applicant to clarify which

specific AMP(s) is applicable for managing the AMR item 3.3.1.5, "Specific Corrosion

Mechanism," and to explain how the AMP(s) manages that corrosion mechanism for

components in various systems, including the diesel fuel oil system. The staff's evaluation of

the applicant's response is documented in Section 3.3.2.5.7 of this SER.

LRA Table 2.3.3-13 references items 3.3.1.5, 3.3.1.7, 3.3.2.29, and 3.3.2.139 for managing

piping and fittings. None of these AMR references include an AMP for buried piping in the

diesel fuel oil system. LRA AMP B.1.25 identifies a one-time visual inspection of the external

surface of a buried piping section, but the system is not identified. LRA Section 3.3.1.1.4

indicates that a buried section of fire mains is included in the Buried Piping and Tanks

Inspection Program. By letter dated August 4, 2003, the staff issued RAI 3.3.2.4.13 part (a) to

request the applicant to explain how buried piping in the diesel fuel oil system will be managed,

including a justification based on operating experience.

In its response dated October 3, 2003, the applicant stated that LRA Table 2.3.3-13, with a

component group of "Piping and Fittings," should have referred to Aging Management

Reference 3.3.1.16, which addresses NUREG-1801, Item VII.H1-.1-b, "Diesel Fuel Oil System

Underground Piping and Fittings," and addresses the aging effect of loss of material due to

general, pitting, and crevice corrosion and MIC.

The staff finds the applicant's response to part (a) adequate and acceptable because the

applicant identified the aging effects of the diesel fuel oil system underground piping and fittings

and appropriate AMPs.

The staff requested additional information to evaluate how the aging effects for filters and

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strainers are managed. Filters and strainers are included in Table 2.3.3-13 as passive

components with a filter function.- Table 3.3-1, Reference 3.3.1 .7,-identifies loss of material due

to general, pitting, and crevice corrosion, MIC, and biofouling as an aging effect for filters and

strainers in the diesel generator fuel oil system. The Fuel Oil Chemistry and One-Time

Inspection Programs are credited for managing the aging effect. In RAI 3.3.2.4.13 part (b), the

applicant was requested to explain how the Fuel Oil Chemistry and One-Time Inspection

Programs manage biofouling in the filter and strainer elements. The staff also asked the

applicant to clarify if filter elements are considered replaceable or long-lived, passive

components.

In its response dated October 3, 2003, the applicant stated that filter elements are replaced on

a frequent basis and are therefore not considered long lived. The response clarified that

biofouling is not considered an aging mechanism for strainers and is managed at its source

within the fuel oil storage tanks. Further, the aging management of filter/strainers was

evaluated in AMR Reference 3.3.1.7, with the NUREG-1 801 component of "Diesel fuel oil tanks

in diesel fuel oil system and emergency diesel generator system." The response identified that

the Fuel Oil Chemistry Program manages biofouling in the fuel oil tanks and includes the

following preventive actions:

* Periodic emergency and station blackout diesel generator, diesel driven fire pump, and

Dresden isolation condenser makeup pump fuel oil samples are analyzed for the presence

of water and particulates.

* Storage tank bottoms are periodically sampled for the presence of water.

* Fuel oil storage tank samples are routinely analyzed for biological growth.

* Samples of new fuel deliveries are analyzed for water, sediment, and the quality of the fuel

being delivered.

* A biocide is added to new fuel oil when the fuel is delivered.

* Water and particulates are removed from the fuel whenever the fuel oil analysis acceptance

criteria are approached or exceeded.

* Fuel oil storage tanks are periodically cleaned and inspected for evidence of internal

corrosion.

* During normal operations, fuel oil day tanks are filled from the bulk fuel oil storage tanks to

which the biocide has been added.

The staff finds the applicant's response to RAI 3.3.2.4.13 part (b) adequate and acceptable

because the applicant provided details on how the biofouling aging effect is managed by

various activities in the Fuel Oil Chemistry and the One-Time Inspection Programs. The Fuel

Oil Chemistry and the One-Time Inspection Programs are evaluated in Sections 3.3.2.3.5 and

3.0.3.10, respectively, of this SER.

The aging effects identified in the LRA for the diesel fuel oil system are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

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plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant credited the following AMPs to manage the aging effects described above for the

diesel fuel oil system:

* Bolting Integrity Program (Section 3.0.3.5)

* One-Time Inspection-Compressed Gas Program (Section 3.0.3.10)

* Buried Piping and Tanks Inspection Program (Section 3.0.3.12)

* Structures Monitoring Program (Section 3.0.3.14)

* Fuel Oil Chemistry Program (Section 3.3.2.3.5)

With the exception of the Fuel Oil Chemistry Program, these AMPs are credited for managing

the aging effects of components in several structures and systems and, therefore, are

considered common AMPs. The staff's evaluation of these AMPs is documented in Sections

3.0.3.5, 3.0.3.10, 3.0.3.12, and 3.0.3.14, respectively, of this SER. The Fuel Oil Chemistry

Program is evaluated in Section 3.3.2.3.5 of this SER.

After evaluating the applicant's AMR for each of the components in the diesel fuel oil system,

the staff evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects for this system. For those components identified in Table 3.3-1 of the

LRA, the staff verified that the applicant credited the AMPs recommended by the GALL Report.

For the components identified in LRA Table 3.3-2, the staff verified that the applicant credited

AMPs that are appropriate for the identified aging effects.

The response to RAI 3.3-7 clarified that the Bolting Integrity Program (B.1.12), the One-Time

Inspection Program (B.1.23), and the Structures Monitoring Program (B.1.30) are to be used to

manage aging effects in the diesel fuel oil system.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the diesel fuel oil

system will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.14 Process Sampling System

Summary of Technical Information in the Application. The description of the process sampling

system can be found in Section 2.3.3.14 of this SER. The passive, long-lived components in

this system that are subject to an AMR are identified in LRA Table 2.3.3-14. The components,

aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

Aging Effects

Table 2.3.3-14 of the LRA lists individual system components within the scope of license

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renewal and subject to an AMR. The components include piping and fittings, tubing, valves,

vents and drains, and closure bolting.

Carbon steel, stainless steel, brass, bronze, and low-alloy steel exposed to moist and humid air

and leaking fluid are subject to loss of material due to corrosion. Loss of material is identified

for carbon steel exposed to an external sheltered environment of moist and humid air. No

aging effect is identified for stainless steel, aluminum, brass, bronze, and copper exposed to an

external sheltered environment of moist and humid air. Carbon steel, stainless steel, brass,

bronze, and copper exposed to an internal environment of moist air are subject to loss of

material due to general, pitting, and crevice corrosion. Stainless steel exposed to saturated air

is subject to loss of material due to pitting and crevice corrosion. No aging effect is identified

for stainless steel in containment nitrogen. Carbon steel exposed to chemically treated

demineralized water is subject to loss of material due to general, pitting, and crevice corrosion.

Stainless steel exposed to chemically treated demineralized water is subject to cracking due to

SCC.

Aging Management Programs

The following AMPs are utilized to manage aging effects in the process sampling system:

* Bolting Integrity Program (B.1.12)

* Water Chemistry Program (B.1.2)

* One-Time Inspection Program (B.1.23)

* Compressed Air Monitoring Program (B.1.16)

* Structures Monitoring Program (B.1.30)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the process sampling system will be

adequately managed by these AMPs during the period of extended operation.

Staff Evaluation.

Aging Effects

The staff reviewed the information in Section 2.3.3.14 and Tables 2.3.3-14, 3.3-1, and 3.3-2 in

the LRA and finds the applicant's identification of the applicable aging effects of carbon steel,

stainless steel, brass, bronze, and low-alloy steel components acceptable. -In addition, the

applicant's conclusion that stainless steel components in a containment nitrogen environment

experience no aging effects is also acceptable.

The description in item 3.3.2.130 of Table 3.3-2 lists loss of material/corrosion as an aging

effect/mechanism for carbon steel, stainless steel, brass, or bronze components in an

environment of air, moisture, humidity, and leaking fluid. However, the LRA does not

specifically identify which type of corrosion is responsible for the loss of material. The type of

corrosion is important because it determines the susceptible locations to be inspected. By letter

dated August 4, 2003, the staff requested, in RAI 3.3-2, the applicant to provide a specific

description of the types of corrosion responsible for the aging effect of loss of material for the

relevant components, as well as the criteria for selecting these samples, including susceptible

locations for inspections. The staff's evaluation of the applicant's response is documented in

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Section 3.3.2.5.2 of this SER.

The aging effects identified in the LRA for the process sampling system are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible the aging effects were identified and that the aging effects listed are appropriate

for the combination of materials and environments specified.

Aging Management Programs

The applicant credited the following AMPs for managing the aging effects in the process

sampling system.

* Bolting Integrity Program (Section 3.0.3.5)

* Water Chemistry Program (Section 3.0.3.2)

* One-Time Inspection Program (Section 3.0.3.10)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* Structures Monitoring Program (Section 3.0.3.14)

The Bolting Integrity Program, Water Chemistry Program, One-Time Inspection Program, Compressed Air Monitoring Program, and Structures Monitoring Program are credited with

managing the aging effects of several components in different structures and systems and are,

therefore, considered common AMPs. The staff's evaluation of these AMPs is documented in

Sections 3.0.3.5, 3.0.3.2, 3.0.3.10, 3.0.3.8, and 3.0.3.14, respectively, of this SER.

After evaluating the applicant's AMR for each of the components in the process sampling

system, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects for this system. For those components identified in Table

3.3-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by the

GALL Report. For the components identified in LRA Table 3.3-2, the staff verified that the

applicant credited AMPs that are appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the process

sampling system will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.15 Carbon Dioxide System

Summary of Technical Information in the Application. The description of the carbon dioxide

system can be found in Section 2.3.3.15 of this SER. The passive, long-lived components in

this system that are subject to an AMR are identified in LRA Table 2.3.3-15. The components,

aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

Aging Effects

Table 2.3.3-15 of the LRA lists individual system components within the scope of license

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renewal and subject to an AMR. The components include closure bolting, piping and fittings

(including thermowells and nozzles), valves, tubing, and tanks.

The LRA identifies that carbon steel corhponents in sheltered environments are subject to loss

of material due to general, pitting, and crevice corrosion, and MIC. Loss of material due to

general corrosion, as well as crack initiation and growth/cyclic loading or SCC, are applicable

aging effects for high-strength, low-alloy steel components in an air, moisture, humidity, and

leaking fluid environment. The LRA identified no aging effect on carbon steel, brass, or bronze

components in a dry gas environment. No aging effect was identified for brass or bronze

components in an environment of air, moisture, and humidity less than 100 OC (212 OF).

Aging Management Programs

The following AMPs are utilized to manage aging effects in the carbon dioxide system:

* Bolting Integrity Program (B.1.12)

* Fire Protection Program (B.1.18)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the carbon dioxide system will be

adequately managed by these AMPs during the period of extended operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, in the

components of the carbon dioxide system. The staff also reviewed the applicable UFSAR

Supplements for the AMPs to ensure that the program descriptions adequately describe the

AMPs.

Aging Effects

The staff reviewed the information in Tables 2.3.3-15, 3.3-1, and 3.3-2 for the carbon dioxide

system. During its review, the staff determined that additional information was needed.

By letter dated August 4, 2003, the staff requested, in RAI 3.3-7, the applicant to clarify which

specific AMP(s) is applicable for managing AMR item 3.3.1.5, "Specific Corrosion Mechanism,"

and to explain how the AMP(s) manages that corrosion mechanism for components in various

systems, including the carbon dioxide system: The staff's evaluation of the applicant's response

is documented in Section 3.3.2.5.7 of this SER.

In item 3.3.2.260 of LRA Table 3.3-2, for the material/environment of brass or bronze/dry gas,

the applicant has listed no applicable aging effect. The staff identified that in the discussion

column the applicant explained that, "A moisture free gaseous environment (nitrogen) is not

conducive to promoting aging degradation of brass or bronze components." By letter dated

August 4, 2003, the staff requested, in part (a) of RAI 3.3.2.4.15, the applicant to clarify whether

dry carbon dioxide should be included in this discussion, or to explain the applicability of this

discussion to the carbon dioxide system.

The staff identified that in item 3.3.2.212 of LRA Table 3.3-2, the applicant identified an

environment of dry gas for the tank component of the carbon dioxide system. In Section

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2.3.3.15 of the LRA, the applicant described part of the Cardox unit as a liquid carbon dioxide

tank. The staff also requested, in part (a) of RAI 3.3.2.4.15, the applicant to resolve the

apparent discrepancy between a dry gas environment and liquid carbon dioxide.

The staff further identified that the applicant identified no aging effect for carbon steel, brass, or

bronze components in a dry gas environment. Dry carbon dioxide is not a degrading

environment for carbon steel, brass, or bronze components. But carbon steel components may

be sensitive to the presence of moisture in the carbon dioxide environment. Moisture may

induce corrosion and corrosion-erosion. The staff requested, in part (b) of RAI 3.3.2.4.15, the

applicant to clarify the degree of dryness of the carbon dioxide environment. The staff asked

the applicant to specify the activities in place to verify and maintain the degree of dryness of the

carbon dioxide environment necessary to minimize aging degradation of carbon steel

components during the period of subsequent operation, including after periods in which carbon

dioxide must be replenished or refilled.

In its response dated October 3, 2003, the applicant stated that for part (a) of the RAI

3.3.2.4.15, Aging Management Reference 3.3.2.260 of LRA Table 3.3-2 explicitly addresses a

nitrogen gaseous environment. This statement applies to dry gases in general, including dry

carbon dioxide (see EPRI 1003056, "Non-Class 1 Mechanical Implementation Guideline and

Mechanical Tools, Revision 3," Appendix D). The discussion column for Aging Management

Reference 3.3.2.260 of LRA Table 3.3-2 should not have included the parenthetical reference

to nitrogen in the second sentence. The applicant further stated that the discussion column of

Aging Management Reference 3.3.2.212 in LRA Table 3.3-2 identifies an environment of dry

gas for the tank component of the carbon dioxide system. The environment is further clarified

in that section as "dry gas (moisture free)," indicating that the environment is free of water.

LRA Section 2.3.3.15 (page 2-144) describes part of the Cardox unit as a liquid carbon dioxide

tank. The description in this section is correct because the carbon dioxide in the tank is

maintained in its pressurized liquid form. However, little or no moisture in the form of water is

contained in the tank. Therefore, the applicant concluded that there is no discrepancy between

the environments identified in Aging Management Reference 3.3.2.212 of LRA Table 3.3-2 and

LRA Section 2.3.3.15.

In the same response dated October 3, 2003, to part (b) of the RAI 3.3.2.4.15, the applicant

stated that the carbon dioxide environment at Dresden Station and Quad Cities Station is

associated with the Cardox system. The carbon dioxide environment in this system is dry

(anhydrous) carbon dioxide, which is at least 99.5 percent carbon dioxide. There are no

activities specifically involving quantifying tank moisture levels. However, the applicant

specified that tank moisture levels are maintained sufficiently low enough to preclude any

appreciable amount of corrosion or corrosion-erosion by (1) performing tank filling operations

with vendor assistance in accordance with vendor recommendations, (2) periodically monitoring

tank pressure and temperature and condition, limiting the possibility of undetected leaks, and

(3) periodically calibrating tank pressure and temperature instrumentation.

The staff finds the applicant's response to part (a) of RAI 3.3.2.4.15 acceptable because the

applicant agrees that the discussion column for Aging Management Reference 3.3.2.260 of

LRA Table 3.3-2 should not have included the parenthetical reference to nitrogen in the second

sentence. In addition, the applicant stated that there is little or no moisture in the form of water

contained in the tank. The staff also finds that the applicant's response to part (b) of RAI

3.3.2.4.15 acceptable because the applicant has specified the moisture level of the carbon

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dioxide and has shown that tank mhoisture levels are maintained sufficiently low enough to

preclude any appreciable amount of corrosion or corrosion-erosion by specific procedures. The

staff considers the issues related to RAI 3.3.2.4.15 to be resolved.

The aging effects identified in the LRA for the carbon dioxide system are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible the aging effects were identified and that the aging effects listed are appropriate

for the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the carbon dioxide system.

* Bolting Integrity Program (Section 3.0.3.5)

* Fire Protection Program (Section 3.3.2.3.3)

The Bolting Integrity Program is credited for managing the aging effects of components in

several structures and systems and, therefore, is considered a common AMP. This AMP is

evaluated in Section 3.0.3.5 of this SER. The Fire Protection Program is evaluated in Section

3.3.2.3.3 of this SER.

After evaluating the applicant's AMR for each of the components in the carbon dioxide system,

the staff evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects. For those components identified in Table 3.3-1 of the LRA, the staff

verified that the applicant credited the AMPs recommended by the GALL Report. For the

components identified in LRA Table 3.3-2, the staff verified that the applicant credited AMPs

that are appropriate for the identified aging effects.

The Fire Protection Program (B.1.18) is applicable to the carbon dioxide system since the

applicant stated in the AMP (page b-38 of the LRA) that, 'The program will provide for aging

management of external surfaces of Dresden and Quad Cities carbon dioxide system

components and Dresden halon system components for corrosion through periodic operability

tests based on NFPA codes and visual inspections. Testing and inspections are implemented

through predefined tasks and procedures." The applicant has also clarified the role of this AMP

for the carbon dioxide system in its response to RAI 3.3-7 which is evaluated in Section

3.3.2.5.7 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the carbon

dioxide system will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

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3.3.2.4.16 Service Water System

Summary of Technical Information in the Application. The description of the service water

system can be found in Section 2.3.3.16 of this SER. The passive, long-lived components in

this system that are subject to an AMR are identified in LRA Table 2.3.3-16. The components,

aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

Aging Effects

Table 2.3.3-16 of the LRA lists individual system components within the scope of license

renewal and subject to an AMR. The components include closure bolting, piping and fittings,

valves, orifice bodies, tubing, pumps and pump casings, strainer screens, and strainer bodies.

The LRA identifies the following applicable aging effects for the service water system.

The applicant identified in the LRA that carbon steel in outdoor ambient conditions is subject to

loss of material due to general, pitting, and crevice corrosion. Copper, brass, and bronze

components in saturated air are subject to loss of material due to pitting and crevice corrosion.

Loss of material due to general, pitting, crevice corrosion, MIC, and macroorganisms is an

I, applicable aging effect on high-strength, low-alloy steel components in raw water (submerged).

The LRA identifies that cast iron and carbon steel in an air, moisture, humidity, and leaking fluid

environment are subject to loss of material due to general corrosion and/or pitting and crevice

corrosion. Cast iron components in raw water, untreated salt water, or fresh water

environments are subject to loss of materials due to selective leaching, general, pitting, crevice,

I and galvanic corrosion, erosion, and MIC. Additional aging effects for cast iron components in

the same environments include flow blockage due to biofouling, silting, and corrosion product

buildup. The applicant identified flow blockage due to biofouling as the only applicable aging

effect for titanium components in raw water, untreated salt water, or fresh water environments.

The LRA identified no aging effects for stainless steel, brass, or bronze components in an

environment of air, moisture, and humidity less than 100 OC (212 0F) or for titanium

components in an air, moisture, humidity, and leaking fluid environment, as well as in raw

water, untreated salt water, or fresh water. The applicant identified no aging effects for copper

components in an environment of air, moisture, and humidity less than 100 OC (212 OF).

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the service

water system:

* Bolting Integrity Program (6.1.12)

* Open-Cycle Cooling Water System Program (B.1.13)

* * Closed-Cycle Cooling Water System Program (B.1.14)

* Compressed Air Monitoring Program (B.1.16)

* Fire Water System Program (B.1.19)

* One-Time Inspection Program (B.1.23)

* Selective Leaching of Materials Program (B.1.24)

* Buried Piping and Tanks Inspection Program (B.1.25)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the service water system will be

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adequately managed by these AMPs during the period of extended operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, in the

components of the service water system. The staff also reviewed the applicable UFSAR

Supplements for the AMPs to ensure that the program descriptions adequately describe the

AMPs.

Aging Effects

The staff reviewed the information in Tables 2.3.3-16, 3.3-1, and 3.3-2 for the service water

system. During its review, the staff determined that additional information was needed.

Aluminum and aluminum alloys components may experience general, pitting, and crevice

corrosion when exposed to moisture and humidity environments, especially with the presence

of contaminants and water (condensation from moist air). However, AMR Reference No.

3.3.2.126 of Table 3.3-2 of the LRA only identifies loss of material due to general and pitting

corrosion as a plausible aging effect for aluminum components exposed to moist air. In Table

3.3-2, Reference No. 3.3.2.21 of the LRA, the applicant concluded that there is no aging effect

on aluminum components of the air handlers heating/cooling system exposed to an air,

moisture, and humidity environment. By letter dated August 4, 2003, the staff requested, in RAI

3.3-4, the applicant to (1) explain the different conclusions on aging effects described above,

(2) provide the technical basis for not including loss of material due to crevice corrosion as an

applicable aging effect, and (3) clarify if there is any condensate on the aluminum fins of the

cooling coils. The staff's evaluation of the applicant's response is documented in Section

3.3.2.5.4 of this SER.

The AMR of this system specifies References 3.3.2.208 and 3.3.2.179 for cast iron components

in raw water. Reference 3.3.2.208 includes galvanic corrosion as a mechanism for loss of

material, but Reference 3.3.2.179 does not. In RAI 3.3.2.4.16, by letter dated August 4, 2003,

the staff asked the applicant to clarify whether the components covered by Reference 3.3.2.179

(pump casings) are also susceptible to galvanic corrosion and to provide the applicable AMP(s).

In its response dated October 3, 2003, the applicant stated that, according to EPRI 1003056,

"Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Revision 3,"

Appendix B, galvanic corrosion is an applicable aging mechanism for cast iron components that

are in contact with metals higher in the galvanic series. The applicant stated that Reference

3.3.2.208 is associated with cast iron strainer bodies in the Dresden CCSW and service water

systems. These strainer bodies are in raw water environments and are in contact with strainer

filters made of stainless steel, which is higher in the galvanic series than cast iron. Therefore,

the applicant concluded that galvanic corrosion is an applicable aging effect for the strainer

bodies. The applicant further stated that Reference 3.3.2.179 is associated with cast iron pump

casings in raw water environments in the Dresden CCSW and service water systems. These

pump casings are not in contact with any metals higher in the galvanic series; therefore, the

applicant concluded that galvanic corrosion is not an applicable aging mechanism. On the

basis of its review, since the pump casings are not in contact with metals higher in the galvanic

series, the staff agrees with the applicant's conclusion that there is no galvanic corrosion of the

pump casings. Therefore, the staff finds the applicant's response to RAI 3.3.2.4.16 acceptable.

The aging effects identified in the LRA for the service water system are consistent with industry

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operating experience for the materials and environments listed. The staff finds that all the

plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the service water system:

* Bolting Integrity Program (Section 3.0.3.5)

* Open-Cycle Cooling Water System Program (Section 3.0.3.6)

* Closed-Cycle Cooling Water System Program (Section 3.0.3.7)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* Fire Water System Program (Section 3.3.2.3.4)

* One-Time Inspection Program (Section 3.0.3.10)

* Selective Leaching of Materials Program (Section 3.0.3.11)

* Buried Piping and Tanks Inspection Program (Section 3.0.3.12)

These AMPs (with the exception of Fire Water System Program) are credited with managing

the aging effects of components in several structures and systems and, therefore, are

considered common AMPs. These common AMPs are evaluated in Sections 3.0.3.5, 3.0.3.6,

3.0.3.7, 3.0.3.8, 3.0.3.10, and 3.0.3.11, respectively, of this SER. The Fire Water System

Program (B.1.19) is evaluated in Section 3.3.2.3.4 of this SER.

The staff identified that loss of material due to galvanic corrosion is location dependent.

Adequate aging management may need to target susceptible locations for inspection and

testing. By letter dated August 4, 2003, the staff asked the applicant to clarify whether the

inspection and testing activities described in the Open-Cycle Cooling Water System Program

(B.1 .13) are targeted or opportunistic with respect to managing loss of material due to galvanic

corrosion (RAI B.1.13). In its responses dated October 3, 2003, and December 17, 2003, the

applicant stated that the Open-Cycle Cooling Water System Program manages galvanic

corrosion through periodic inspections of in-scope components, as appropriate. The in-scope

components include heat exchangers and strainer bodies. The applicant further stated that a

new surveillance for periodic inspection of the strainer in the CCSW supply line to the main

control room HVAC refrigeration condensing unit will be added to this program and will be

implemented prior to the end of the current license. This is Commitment #13 of Appendix A of

this SER. The applicant also updated the UFSAR Supplement for the Open-Cycle Cooling

Water System Program to reflect this addition. The staff concludes that the use of periodic

inspections performed as part of the Open-Cycle Cooling Water System Program is an

i, appropriate method of managing the loss of material due to galvanic corrosion; therefore, the

staff finds this acceptable.

After evaluating the applicant's AMR for each of the components in the service water system,

the staff evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects. For those components identified in Table 3.3-1 of the LRA, the staff

verified that the applicant credited the AMPs recommended by the GALL Report. For the

components identified in LRA Table 3.3-2, the staff verified that the applicant credited an AMP

that is appropriate for the identified aging effects.

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On the basis of its review, the staff finds that the AMPs credited in the LRA for the service water

system will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.17 Reactor Building Closed Cooling Water System

Summary of Technical Information in the Application. The description of the reactor building

closed cooling water system can be found in Section 2.3.3.17 of the LRA. The passive, longlived components in this system that are subject to an AMR are identified in LRA Table 2.3.3-

17. The components, aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

Aging Effects

Table 2.3.3-17 of the LRA lists individual system components within the scope of license

renewal and subject to AMR. The components include closure bolting, flow elements, NSR

vents or drains, piping and fittings, pumps, tanks, and valves. Components specific to Dresden

only include heat exchanger, manifolds, thermowells, tubing , and orifice bodies. Components

specific to Quad Cities only are heat exchanger (spatial interaction), piping and fittings (spatial

interaction) (include flow elements), and valves (attached support).

Carbon steel and stainless steel components exposed to chemically treated demineralized

water are subject to the aging effects of loss of material due to general, galvanic (carbon steel

only), pitting, crevice, microbiologically influenced, erosion, or flow-accelerated corrosion and

wear and crack initiation and growth due to fatigue and SCC. Carbon steel, stainless steel,

brass, or bronze components exposed to warm and moist air are subject to the aging effect of

loss of material due to corrosion. Brass and bronze components exposed to chemically treated

demineralized water are subject to the aging effects of loss of material due to general, galvanic,

pitting, crevice, and microbiologically influenced corrosion and selective leaching, and crack

initiation and growth due to fatigue and SCC. Stainless steel exposed to air, moisture, and

humidity experiences no aging effects. Heat exchangers exposed to raw water are subject to

the aging effect of loss of heat transfer function due to buildup of deposit and fouling.

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the reactor

building closed cooling water system:

* Water Chemistry Program (B.1.2)

* Bolting Integrity Program (B.1.12)

* Open-Cycle Cooling Water System Program (B.1.13)

* Closed-Cycle Cooling Water System Program (B.1.14)

* Compressed Air Monitoring Program (B.1.16)

* One-Time Inspection Program (B.1.23)

* Selective Leaching of Materials Program (B.1.24)

* Structures Monitoring Program (B.1.30)

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A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the reactor building closed cooling

water system will be adequately managed by these AMPs during the period of extended

operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, on

components in the reactor building closed cooling water system. The staff also reviewed the

applicable UFSAR Supplements for the AMPs to ensure that the program descriptions

adequately describe the AMPs.

Aging Effects

The staff reviewed the information in Section 2.3.3.17, Table 2.3.3-17, and Tables 3.3-1 and

3.3-2 in the LRA. During its review, the staff determined that additional information was

needed.

Metals and alloys that are in contact with different, more cathodic metals or alloys in the

presence of an electrolyte fluid may be subject to the aging effect of loss of material from

galvanic corrosion. Many systems/components of the auxiliary systems described by various

items in Table 3.3-2 of the LRA have material/environment combinations for which loss of

material from galvanic corrosion may be an applicable aging effect/mechanism. However, the

applicant does not include loss of material due to galvanic corrosion as an aging

effect/mechanism that requires management for the period of extended operation. By letter

dated August 4, 2003, the staff issued RAI 3.3-1 pertaining to this issue. The staff's evaluation

of the applicant's response is documented in Section 3.3.2.5.1 of this SER.

Carbon steel, stainless steel, brass, and bronze components exposed to moist gas (moist

nitrogen) or a moist air environment may experience the aging effect of loss of material due to

general (for carbon steel only), pitting, and crevice corrosion (for both carbon steel and

stainless steel) when pollutants such as oxygen, SO2, NO., or CO are present in the moist air,

particularly when the humidity is greater than 60 percent. However, in Table 3.3-2, the

applicant concluded that no aging effects were identified for the external surfaces of the carbon

steel and stainless steel piping and fittings, accumulators, dampeners, filters/strainers, flow

elements, pumps, orifices, rupture discs, tanks, tubing, and valves exposed to either the

containment nitrogen gas environment or an air, moisture, and humidity environment because

these components are not subject to any viable aging mechanism in the absence of aggressive

chemical species. By letter dated August 4, 2003, the staff issued RAI 3.3-3 requesting the

applicant to provide information to justify the conclusions in Table 3.3-2, Reference Nos.

3.3.2.27 and 3.3.2.40, as to whether pollutants such as oxygen, NO,, SO2 or CO are present,

and if so, to what extent, in the containment gas or air, moisture, and humidity environments.

The staff's evaluation of the applicant's response is documented in Section 3.3.2.5.3 of this

SER.

Aluminum and aluminum alloys components may experience general, pitting, and crevice

corrosion when exposed to moisture and humidity environments, especially with the presence

of contaminants and water (condensation from moist air). However, AMR Reference No.

3.3.2.126 of Table 3.3-2 of the LRA only identifies loss of material due to general and pitting

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corrosion as a plausible aging effect for aluminum components exposed to moist air. In Table

3.3-2, Reference No. 3.3.2.21 of the LRA, the applicant concluded that there is no aging effect

on aluminum components of the air handlers heating/cooling system exposed to an air,

moisture, and humidity environment. By letter dated August 4, 2003, the staff requested, in RAI

3.3-4, the applicant to (1) explain the different conclusions on aging effects described above,

(2) provide the technical basis for not including loss of material due to crevice corrosion as an

applicable aging effect, and( 3) clarify if there is any condensate on the aluminum fins of the

cooling coils. The staff's evaluation of the applicant's response is documented in Section

3.3.2.5.4 of this SER.

Loss of material due to general, pitting, and crevice corrosion may be an applicable aging effect

on carbon steel components exposed to chemically treated demineralized water. However, in

several AMR references, the applicant identified crack initiation and growth due to SCC and

IGSCC as the applicable aging effect/mechanism instead of loss of material due to general,

pitting, and crevice corrosion. By letter dated August 4, 2003, the staff requested, in RAI 3.3-6,

the applicant to provide clarification. The staff's evaluation of the applicant's response is

documented in Section 3.3.2.5.6 of this SER.

The aging effects identified in the LRA for the reactor building closed cooling water system are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible the aging effects were identified and that the aging effects listed

are appropriate for the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs with managing the aging effects described

above for the reactor building closed cooling water system:

* Water Chemistry Program (Section 3.0.3.2)

* Bolting Integrity Program (Section 3.0.3.5)

* Open-Cycle Cooling Water System Program (Section 3.0.3.6)

* Closed-Cycle Cooling Water System Program (Section 3.0.3.7)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* Selective Leaching of Materials Program (Section 3.0.3.11)

* Structures Monitoring Program (Section 3.0.3.14)

* Periodic Inspection of Components Subject to Moist Environments Program (Section

3.0.3.18)

As part of RAI B.1.23.2-6, the staff questioned the use of one-time inspections to manage aging

for components in a moist air environment. In its response dated March 25, 2004, the applicant

credited the Periodic Inspection of Components Subject to Moist Environments program to

manage aging effects for stainless steel, carbon steel, cast iron, aluminum, copper, and brass

and bronze components exposed to moist air environments and subject to wetting. The staff's

evaluation of the Periodic Inspection of Components Subject to Moist Environments AMP is

contained in SER section 3.0.3.18.

These AMPs are credited for managing the aging effects on components in several structures

and systems and, therefore, are considered common AMPs. The staff has evaluated these

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common AMPs and found them to be acceptable for managing the aging effects identified for

components in this system. The staff's evaluation of these AMPs is documented in Sections

3.0.3.2, 3.0.3.5, 3.0.3.6, 3.0.3.7, 3.0.3.8, 3.0.3.10, 3.0.3.11, and 3.0.3.14, respectively, of this

SER.

After evaluating the applicant's AMR for each of the components in the reactor building closed

cooling water system, the staff evaluated the AMPs listed above to determine if they are

appropriate for managing the identified aging effects for this system. For those components

identified in Table 3.3-1 of the LRA, the staff verified that the applicant credited the AMPs

recommended by the GALL Report. For the components identified in LRA Table 3.3-2, the staff

verified that the applicant credited AMPs that are appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the reactor

building closed cooling water system will effectively manage or monitor the aging effects

identified in the LRA.

In response to the staff's concern, expressed in RAI 2.1-2, regarding the extent of the boundary

of the non-safety-related piping attached to the safety-related piping, the applicant has since

included additional piping to the scope of license renewal. The applicant stated that while

additional components have been added to the scope of license renewal for each system, the

components are comprised of the same materials and experience the same environments as

other components within the system. As such, there are no new AMPs required. For the

auxiliary systems, only the reactor building closed cooling water system, Table 2.3.3-17,

needed revision to (1) remove a note, "(Quad City only)," for piping, fittings, and valves

(attached support) and (2) replace the AMR reference 3.3.2.267 with the AMR reference

3.3.2.40 for valves (attached support). No other auxiliary systems scoping and screening tables

are affected. The staff has reviewed the revised Table 2.3.3-17, and verified that the added

piping and valves to the scope of license renewal are included in the same AMPs already

applied to other components within the reactor building closed cooling water system. Based on

the above, the staff concluded that the applicants response to RAI 2.1-2 is acceptable for the

auxiliary systems.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.18 Turbine Building Closed Cooling Water System

Summary of Technical Information in the Application. The description of the turbine building

closed cooling water system can be found in Section 2.3.3.18 of the LRA. The passive, longlived components in this system that are subject to an AMR are identified in LRA Table 2.3.3-

18. The components, aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

Aging Effects

Table 2.3.3-18 of the LRA lists individual system components within the scope of license

renewal and subject to AMR. The components include closure bolting, heat exchanger, piping

and fittings, and valves.

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Carbon steel and admiralty brass components exposed to raw water are subject to the aging

effects of loss of material due to general, galvanic, microbiologically influenced, erosion, f lowaccelerated, pitting, and crevice corrosion, wear, and selective leaching, and crack initiation and

growth due to fatigue and SCC; carbon steel components exposed to chemically treated

demineralized water less than 900 C (194 0F) are subject to the aging effect of crack initiation

and growth due to fatigue and SCC.

Aging Management Programs

The LRA credited the following AMPs for managing the identified aging effects for the turbine

building -closed cooling water system:

* Bolting Integrity Program (B.1.12)

* Open-Cycle Cooling Water System Program (B.1.13)

* Closed-Cycle Cooling Water System Program (B.1.14)

* Structures Monitoring Program (B.1.30)

* Selective Leaching of Materials Program (B.1.24)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the turbine building closed cooling

water system will be adequately managed by these AMPs during the period of extended

operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, on

components in the turbine building closed cooling water system. The staff also reviewed the

applicable UFSAR Supplements for the AMPs to ensure that the program descriptions

adequately describe the AMPs.

Aging Effects

The staff reviewed the information in Section 2.3.3.18, Table 2.3.3-18, and Tables 3.3-1 and

3.3-2 in the LRA. On the basis of its review, the staff finds that the applicant has correctly

identified the applicable aging effects on the components consistent with industry experience

for the combinations of materials and environments in the turbine building closed cooling water

system.

The aging effects identified in the LRA for the turbine building closed cooling water system are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible the aging effects were identified and that the aging effects listed

are appropriate for the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the turbine building closed cooling water system:

* Bolting Integrity Program (Section 3.0.3.5)

* Open-Cycle Cooling Water System Program (Section 3.0.3.6)

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* Closed-Cycle Cooling Water System Program (Section 3.0.3.7)

* Structures Monitoring Program (Section 3.0.3.14)

* Selective Leaching of Materials Program (Section 3.0.3.11)

These AMPs are credited for managing the aging effects on components in several structures

and systems and, therefore, are considered common AMPs. The staff has evaluated these

common AMPs and found them to be acceptable for managing the aging effects identified for

this system. The staff's evaluation of these AMPs is documented in Sections 3.0.3.5, 3.0.3.6,

3.0.3.7, 3.0.3.14, and 3.0.3.11, respectively, of this SER.

After evaluating the applicant's AMR for each of the components in the turbine building closed

cooling water system, the staff evaluated the AMPs listed above to determine if they are

appropriate for managing the identified aging effects for this system. For those components

identified in Table 3.3-1 of the LRA, the staff verified that the applicant credited the AMPs

recommended by the GALL Report. For the components identified in LRA Table 3.3-2, the staff

verified that the applicant credited AMPs that are appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the turbine

building closed cooling water system will effectively manage or monitor the aging effects

identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.19 Demineralized Water Makeup System

Summary of Technical Information in the Application. The description of the demineralized

water makeup system can be found in Section 2.3.3.19 of this SER. The passive, long-lived

components in this system that are subject to an AMR are identified in LRA Table 2.3.3-19.

The components, aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

Aging Effects

Table 2.3.3-19 of the LRA lists individual system components within the scope of license

renewal and subject to AMR. The components include closure bolting, NSR vents or drains,

piping and fittings, piping and fittings (spatial interaction), piping and fittings (attached support),

valves, and valves (spatial interaction). The components specific to Dresden only include

pumps and restricting orifices. The components specific to Quad Cities only include flow

elements (spatial interaction), piping and valves (attached support), pumps (spatial interaction),

restricting orifices (spatial interaction), strainers (spatial interaction), and valves (attached

support).

The LRA identifies that high-strength, low-alloy steel closure bolting components exposed to

outdoor ambient conditions are subject to the aging effect of loss of material due to general

corrosion and wear. Carbon steel, stainless steel, brass, or bronze components in the NSR

vents or drains, piping, and valves system that are exposed to an air, moisture, humidity, and

leaking fluid environment are subject to the aging effect of loss of material due to corrosion.

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Carbon steel and stainless steel components exposed to treated water are subject to the aging

effect of loss of material due to general (carbon steel only), pitting, and crevice corrosion.

Carbon steel components exposed to outdoor ambient conditions are subject to the aging'effect

of loss of material due to general, pitting, and crevice corrosion. Stainless steel components

exposed to air, moisture, and humidity or outdoor ambient conditions experience no aging

effects. Cast iron components exposed to treated water are subject to the aging effect of loss of

material due to selective leaching. Cast iron components exposed to air, moisture, and humidity

are subject to the aging effect of loss of material due to pitting and crevice corrosion. Aluminum

components exposed to treated water less than 90 0C (194 'F) are subject to the aging effect

of loss of material due to pitting and crevice corrosion. Aluminum components exposed to

outdoor ambient conditions are subject to the aging effect of loss of material due to pitting

corrosion. Brass or bronze components exposed to demineralized water are subject to the

aging effect of loss of material due to pitting and crevice corrosion. Brass or bronze

components exposed to air, moisture, and humidity experience no aging effects.

Aging Management Programs

The following AMPs are utilized to manage aging effects in the demineralized water makeup

system:

* Water Chemistry Program (B.1.2)

* BWR Stress Corrosion Cracking Program (B.1.7)

* Bolting Integrity Program (B.1.12)

* One-Time Inspection Program (B.1.23)

* Selective Leaching of Materials Program (B.1.24)

* Structures Monitoring Program (B.1.30)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the demineralized water makeup

system will be adequately managed by these AMPs during the period of extended operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects,-on

components in the demineralized water makeup system. The staff also reviewed the applicable

UFSAR Supplements for the AMPs to ensure that the program descriptions adequately

describe the AMPs.

Aging Effects

The staff reviewed the information in Section 2.3.3.19, Table 2.3.3-19, and Section 3.3.3, Table

3.3-2 in this SER. During its review, the staff determined that additional information was

needed.

In LRA Table 3.3-2, Reference No. 3.3.2.1 8, the applicant stated that high-strength, low-alloy

steel closure bolting components in the outdoor ambient conditions are subject to the aging

effect of loss of material due to general corrosion and wear. However, the applicant did not

include crack initiation and growth due to SCC or other mechanisms as an applicable aging

effect/mechanism. By letter dated August 4, 2003, the staff requested, in RAI 3.3-5, the

applicant to provide its technical basis for not including this aging effect/mechanism. The staff's

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evaluation of the applicant's response is documented in Section 3.3.2.5.5 of this SER.

Loss of material due to general, pitting, and crevice corrosion may be an applicable aging effect

on carbon steel components exposed to chemically treated demineralized water. However, in

several AMR references, the applicant identified crack initiation and growth due to SCC and

IGSCC as the applicable aging effect/mechanism instead of loss of material due to general,

pitting, and crevice corrosion. By letter dated August 4, 2003, the staff requested, in RAI 3.3-6,

the applicant to provide clarification. The staff's evaluation of the applicant's response is

documented in Section 3.3.2.5.6 of this SER.

For several AMR items, the LRA was not clear as to how the applicant was verifying the

effectiveness of the Water Chemistry Program. By letter dated August 4, 2003, the staff

requested, in RAI 3.3-8, the applicant to clarify whether a one-time inspection should be

performed for these components to verify the effectiveness of the Water Chemistry Program.

The staff's evaluation of the applicant's response is documented in Section 3.3.2.5.8 of this

SER.

The applicant uses the Bolting Integrity Program (B.1.12) to manage general corrosion on

external surfaces of many auxiliary system nonbolting components. The staff notes that the

Bolting Integrity Program description states, "The program consists of visual inspections for

external surface degradation that may be caused by loss of material or cracking of the bolting,

or by an adverse environment." This suggests that only the bolting material will be inspected

for aging degradation. By letter dated August 4, 2003, the staff requested, in RAI 3.3-9, the

applicant to explain (including the acceptance criteria and inspection interval) how the Bolting

Integrity Program is used to manage general corrosion on external surfaces of nonbolting

components, such as piping, valves, mufflers, and others. The staff's evaluation of the

applicant's response is documented in Section 3.3.2.5.9 of this SER.

The LRA identifies that loss of material due to pitting and crevice corrosion may be an

applicable aging effect on aluminum components exposed to outdoor ambient conditions or

cast iron exposed to treated water. However, in Table 3.3-2, Reference No. 3.3.2.22, the

applicant identified loss of material due to pitting corrosion as the only aging effect/mechanism

on the aluminum components exposed to outdoor ambient conditions. Similarly, in Table 3.3-2,

Reference No. 3.3.2.182, the applicant identified only loss of material due to selective leaching

as the applicable aging effect/mechanism on cast iron exposed to treated water. By letter

dated August 4, 2003, the staff requested, in RAI 3.3.2.4.19, the applicant to provide the

technical basis for excluding the aging effect of loss of material due to crevice corrosion and/or

pitting corrosion from the AMR.

In its response dated October 3, 2003, the applicant stated that according to the "Metals

Handbook," Ninth Edition, Volume 13, the aging effect/mechanism that may affect aluminum

components exposed to an outdoor ambient environment is loss of material due to pitting.

Aluminum alloys have excellent resistance to atmospheric corrosion, and in many outdoor

applications, such alloys do not require shelter, protective coatings, or maintenance. Corrosion

of most aluminum alloys by weathering is restricted to mild surface roughening by shallow

pitting, with no general thinning. Therefore, the applicant concluded that loss of material due to

pitting is the only applicable aging effect on aluminum components exposed to an outdoor

environment, as evaluated in Aging Management Reference 3.3.2.22. The applicant further

stated that loss of material due to pitting and crevice corrosion of cast iron components is

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addressed by Aging Management Reference 3.3.2.300. Aging Management Reference

3.3.2.182 addresses the aging effect of loss of material due to selective leaching on cast iron

exposed to a treated water internal environment. The applicant clarified that Aging

Management Reference 3.3.2.300 addresses the aging effect of loss of material due to pitting

and crevice corrosion on cast iron exposed to an external environment of air, moisture, and

humidity less than 100 CC (212 OF).

On the basis of its review, the staff finds the applicant's response to RAI 3.3.2.4.19 acceptable

because the applicant has shown that (1) loss of material due to pitting is the only applicable

aging effect on aluminum components exposed to an outdoor environment, (2) Aging

Management Reference 3.3.2.182 addresses the aging effect of loss of material due to

selective leaching on cast iron exposed to a treated water internal environment, and (3) Aging

Management Reference 3.3.2.300 addresses the aging effect of loss of material due to pitting

and crevice corrosion on cast iron exposed to an external environment of air, moisture, and

humidity less than1O00 C (212 OF). The staff considers the issues related to RAI 3.3.2.4.19 to

be resolved.

The aging effects identified in the LRA for the demineralized water makeup system are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible the aging effects were identified and that the aging effects listed

are appropriate for the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the demineralized water makeup system.

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress Corrosion Cracking Program (Section 3.0.3.3)

* Bolting Integrity Program (Section 3.0.3.5)

* One-Time Inspection Program (Section 3.0.3.10)

* Selective Leaching of Materials Program (Section 3.0.3.11)

* Structures Monitoring Program (Section 3.0.3.14)

These AMPs are credited for managing the aging effects on components in several structures

and systems and, therefore, are considered common AMPs. The staff's evaluation of these

AMPs is documented in Sections 3.0.3.2, 3.0.3.3, 3.0.3.5, 3.0.3.10, 3.0.3.11, and 3.0.3.14,

respectively, of this SER.

After evaluating the applicant's AMR for each of the components in the demineralized water

makeup system, the staff evaluated the AMPs.listed above to determine if they are appropriate

for managing the identified aging effects. For those components identified in Table 3.3-1 of the

LRA, the staff verified that the applicant credited the AMPs recommended by the GALL Report.

For the components identified in LRA Table 3.3-2, the staff verified that the applicant credited

an AMP that is appropriate for the identified aging effects.

By letter dated August 4, 2003, the staff requested, in RAI 3.3-7, the applicant to clarify which

specific AMP(s) is applicable for managing AMR item 3.3.1.5, "Specific Corrosion Mechanism,"

and to explain how the AMP(s) manages that corrosion mechanism for components in various

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systems, including the demineralized water makeup. The staff's evaluation of the applicant's

response is documented in Section 3.3.2.5.7 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the

demineralized water makeup system will effectively manage or monitor the aging effects

identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.20 Residual Heat Removal Service Water System (Quad Cities Only)

Summary of Technical Information in the Application. The description of the residual heat

removal service water system can be found in Section 2.3.3.20 of the SER. The passive, longlived components in this system that are subject to an AMR are identified in LRA Table 2.3.3-

20. The components, aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

Aging Effects

Table 2.3.3-20 of the LRA lists individual system components within the scope of license

renewal and subject to AMR. The components include air handlers heating/cooling (Aux & RW

HVAC), ducts and fittings, access doors, heat exchangers, and NSR vents or drains. The

components specific to Quad Cities only include closure bolting,' dampeners, equipment frames,

orifice bodies, piping and fittings, piping and fittings (attached support), pulsation dampeners,

pumps, sight glass (attached supports), strainer bodies, strainer screens, thermowells, tubing,

tubing (attached supports), valves, and valves (attached support).

Air handlers with copper tubes, stainless steel tubesheets, and carbon steel end bells exposed

to raw water or warm moist air are subject to the aging effects of loss of material due to

general, galvanic, pitting, crevice, and microbiologically influenced corrosion, erosion or flowaccelerated corrosion, wear, and cracking initiation and growth due to fatigue and SCC. Copper

tubes in air handlers are subject to the aging effect of loss of heat transfer function due to

buildup of deposittfouling. Heat exchangers with stainless steel tubes, cast iron tubesheets,

carbon steel or cast iron shells, and cast iron channel heads exposed to raw water on the tube

side and torus water on the shell side are subject to the aging effects of loss of material due to

general, galvanic, pitting, crevice, and microbiologically influenced corrosion, erosion or flowaccelerated corrosion, selective leaching, wear, and cracking initiation and growth due to

fatigue and SCC. Heat exchanger tubes are subject to the aging effect of loss of heat transfer

function due to buildup of deposit/fouling. Heat exchanger external surfaces exposed to air,

moisture, humidity, and leaking fluids are subject to the aging effect of loss of material due to

pitting and crevice corrosion. Carbon steel, stainless steel, brass, or bronze NSR vents or

drains exposed to air, moisture, and leaking fluid are subject to the aging effect of loss of

material due to corrosion. Brass or bronze, carbon steel, saran-lined steel, iron cast (lined),

and stainless steel components exposed to air, moisture, humidity, and leaking fluid are subject

to the aging effect of loss of material due to general (carbon steel, saran-lined steel), pitting,

and crevice corrosion. Carbon steel components exposed to raw water are subject to the aging

effect of loss of material due to general, pitting, crevice, and microbiologically influenced

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corrosion. Saran-lined steel components exposed to raw water are subject to the aging effect

of loss of material due to general, pitting, crevice, galvanic, and microbiologically influenced

corrosion and erosion. Saran-lined steel components exposed to raw water are subject to the

aging effect of loss of intended function due to flow blockage caused by biofouling,- silting, and

corrosion product buildup. Iron cast (lined) components exposed to raw water are subject to the

aging effect of loss of material due to general, pitting, crevice, and microbiologically influenced

corrosion and selective leaching. Brass or bronze components exposed to an air, moisture,

and humidity environment experience no aging effects. Cast iron components exposed to raw

water are subject to the aging effect of loss of material due to general, pitting, crevice, galvanic,

and microbiologically influenced corrosion and selective leaching. Cast iron components

exposed to raw water are subject to the aging effect of loss intended function due to flow

blockage caused by biofouling, silting, and corrosion product buildup. Cast iron components

exposed to an air, moisture, and humidity environment are subject to the aging effect of loss of

material due to pitting and crevice corrosion.

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the residual

heat removal service water system:

* Water Chemistry Program (B.1.2)

* Bolting Integrity Program (B.1.12)

* Open-Cycle Cooling Water System Program (B.1.13)

* One-Time Inspection Program (B.1.23)

* Selective Leaching of Materials Program (B.1.24)

* Buried Piping and Tanks Inspections Program (B.1.25)

* Structures Monitoring Program (B.1.30)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the residual heat removal service

water system will be adequately managed by these AMPs during the period of extended

operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, on

components in the residual heat removal service water system. The staff also reviewed the

applicable UFSAR Supplements for the AMPs to ensure that the program descriptions

adequately describe the AMPs.

Aging Effects

The staff reviewed the information in Section 2.3.3.20, Table 2.3.3-20, and Tables 3.3-1 and

3.3-2 in the LRA. During its review, the staff determined that additional information was

needed. The issues addressed in the RAls are related to this system, in addition to other

systems, even though the RAls are evaluated in other sections of this SER as specified in the

following text.

Metals and alloys that are in contact with different, more cathodic metals or alloys in the

presence of an electrolyte fluid may be subject to the aging effect of loss of material from

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galvanic corrosion. Many systems/components of the auxiliary systems described by various

items in Table 3.3-2 of the LRA have materiaVenvironment combinations for which loss of

material from galvanic corrosion may be an applicable aging effect/mechanism. However, the

applicant does not include loss of material due to galvanic corrosion as an aging

effect/mechanism that requires management for the period of extended operation. By letter

dated August 4, 2003, the staff issued RAI 3.3-1 pertaining to this issue. The staff's evaluation

of the applicant's response is documented in Section 3.3.2.5.1 of this SER.

The description in item 3.3.2.130 of Table 3.3-2 lists loss of material/corrosion as an aging effect/mechanism for carbon steel, stainless steel, brass, or bronze components in an

environment of air, moisture, humidity, and leaking fluid. However, the LRA does not

specifically identify which type of corrosion is responsible for the loss of material. The type of

corrosion is important because it determines the susceptible locations to be inspected. By letter

dated August 4, 2003, the staff requested, in RAI 3.3-2, the applicant to provide a specific

description of the types of corrosion responsible for the aging effect of loss of material for the

relevant components, as well as the criteria for selecting these samples, including susceptible

l locations for inspections. The staff's evaluation of the applicant's response is documented in

Section 3.3.2.5.2 of this SER.

Carbon steel, stainless steel, brass, and bronze components exposed to moist gas (moist nitrogen) or a moist air environment may experience the aging effect of loss of material due to

l general (for carbon steel only), pitting, and crevice corrosion (for both carbon steel and

stainless steel) when pollutants such as oxygen, S02, NO., or CO are present in the moist air,

particularly when the humidity is greater than 60 percent. However, in Table 3.3-2, the

applicant concluded that no aging effects were identified for the external surfaces of the carbon

steel and stainless steel piping and fittings, accumulators, dampeners, filters/strainers, flow

elements, pumps, orifices, rupture discs, tanks, tubing, and valves exposed to either the , containment nitrogen gas environment or an air, moisture, and humidity environment because

these components are not subject to any viable aging mechanism in the absence of aggressive

chemical species. By letter dated August 4, 2003, the staff issued RAI 3.3-3 requesting the

applicant to provide information to justify the conclusions in Table 3.3-2, Reference Nos.

3.3.2.27 and 3.3.2.40, as to whether pollutants such as oxygen, NO., SO2 or CO are present,

and if so, to what extent, in the containment gas or air, moisture, and humidity environments.

The staff's evaluation of the applicant's response is documented in Section 3.3.2.5.3 of this

SER.

Aluminum and aluminum alloys components may experience general, pitting, and crevice

corrosion when exposed to moisture and humidity environments, especially with the presence

of contaminants and water (condensation from moist air). However, AMR Reference No.

3.3.2.126 of Table 3.3-2 of the LRA only identifies loss of material due to general and pitting

corrosion as a plausible aging effect for aluminum components exposed to moist air. In Table

3.3-2, Reference No. 3.3.2.21 of the LRA, the applicant concluded that there is no aging effect

on aluminum components of the air handlers heating/cooling system exposed to an air,

moisture, and humidity environment. By letter dated August 4, 2003, the staff requested, in RAI

3.3-4, the applicant to (1) explain the different conclusions on aging effects described above,

(2) provide the technical basis for not including loss of material due to crevice corrosion as an

applicable aging effect, and (3) clarify if there is any condensate on the aluminum fins of the

cooling coils. The staff's evaluation of the applicant's response is documented in Section

3.3.2.5.4 of this SER.

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Loss of material due to general, pitting, and crevice corrosion may be an applicable aging effect

on carbon steel components exposed to chemically treated demineralized water. However, in

several AMR references, the applicant identified crack initiation and growth due to SCC and

IGSCC as the applicable aging effect/mechanism instead of loss of material due to general,

pitting, and crevice corrosion. By letter dated August 4, 2003, the staff requested, in RAI 3.3-6,

the applicant to provide clarification. The staff's evaluation of the applicant's response is

documented in Section 3.3.2.5.6 of this SER.

By letter dated August 4,2003, the staff requested, in RAI 3.3-7, the applicant to clarify which

specific AMP(s) is applicable for managing the AMR item 3.3.1.5, "Specific Corrosion

Mechanism," and to explain how the AMP(s) manages that corrosion mechanism for

components in the various auxiliary systems. The staff's evaluation of the applicant's response

is documented in Section 3.3.2.5.7 of this SER.

For several AMR items, the LRA was not clear as to how the applicant was verifying the

effectiveness of the Water Chemistry Program. By letter dated August 4, 2003, the staff

requested, in RAI 3.3-8, the applicant to clarify whether a one-time inspection should be

performed for these components to verify the effectiveness of the Water Chemistry Program.

The staff's evaluation of the applicant's response is documented in Section 3.3.2.5.8 of this

SER.

Loss of material due to selective leaching may be an applicable aging effect for copper alloy

components exposed to a saturated air environment where water condensation may occur on

the surfaces of these components. However, in LRA Table 3.3-2, Reference Nos. 52, 242, and

262, loss of material due to selective leaching was not identified as an applicable aging effect

for copper alloy components in saturated air. By letter dated August 4, 2003, the staff issued

RAI 3.3.2.4.8 requesting the applicant to provide the technical basis for excluding this aging

effect from AMR. The staff's evaluation of the applicant's response is documented in Section

3.3.2.4.8 of this SER.

The aging effects identified in the LRA for the residual heat removal service water system are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible the aging effects were identified and that the aging effects listed

are appropriate for the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the residual heat removal service water system:

* Water Chemistry Program (Section 3.0.3.2)

* Bolting Integrity Program (Section 3.0.3.5)

* Open-Cycle Cooling Water System Program (Section 3.0.3.6)

* One-Time Inspection Program (Section 3.0.3.10)

* Selective Leaching of Materials Program (Section 3.0.3.11)

* Buried Piping and Tanks Inspections Program (Section 3.0.3.12)

* Structures Monitoring Program (Section 3.0.3.14)

These AMPs are credited for managing the aging effects on components in several structures

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and systems and, therefore, are considered common AMPs. The staff has evaluated these

common AMPs and has found them to be acceptable for managing the aging effects identified

for this system. The staff's evaluation of these AMPs is documented in Sections 3.0.3.2,

3.0.3.5, 3.0.3.6, 3.0.3.10, 3.0.3.11, 3.0.3.12, and 3.0.3.14, respectively, of this SER.

After evaluating the applicant's AMR for each of the components in the residual heat removal

service water system, the staff evaluated the AMPs listed above to determine if they are

appropriate for managing the identified aging effects for this system. For those components

identified in Table 3.3-1 of the LRA, the staff verified that the applicant credited the AMPs

recommended by the GALL Report. For the components identified in LRA Table 3.3-2, the staff

verified that the applicant credited AMPs that are appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the residual heat

removal service water system will effectively manage or monitor the aging effects identified in

the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.21 Containment Cooling Service Water System (Dresden Only)

Summarv of Technical Information in the Application. The description of the containment

cooling service water system can be found in Section 2.3.3.21 of this SER. The passive, longlived components in this system that are subject to an AMR are identified in LRA Table 2.3.3-

21. The components, aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

Aging Effects

Components of the containment cooling service water system are described in Section 2.3.3.21

of the LRA as being within the scope of license renewal and subject to an AMR. Tables 2.3.3-

21, 3.3-1, and 3.3-2 of the LRA list individual components of the system, including piping and

fittings, buried piping, tubing, valves, pumps, thermowells, strainer bodies and screens, orifice

bodies, heat exchangers, flow elements, duct and fittings, access doors, equipment frames, air

handlers, and closure bolting.

Carbon steel, stainless steel, brass, bronze, and cast iron exposed to an external environment

of high moisture and humidity air and leaking fluid in the pump vault are subject to loss of

material due to corrosion. Loss of material is identified for cast iron exposed to the plant's

indoor building environment (defined in the LRA as air, moisture, and humidity less than 100 0C

(212 'F)). No aging effect is identified for stainless steel, brass, and bronze exposed to the

plant's indoor building environment. Carbon steel submerged in raw water is subject to loss of

material due to general, pitting, and crevice corrosion and MIC. Carbon steel in a buried

environment is also subject to loss of material due to general, pitting, and crevice corrosion and

MIC. Cast iron exposed to raw water is subject to loss of material due to general, pitting,

crevice corrosion, MIC, and selective leaching. Copper and carbon steel heat exchanger

components exposed to raw water on the tube side are subject to loss of material, cracking,

and fouling. Copper and carbon steel heat exchanger components exposed to torus water

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(demineralized water) on the shell side are subject to loss of material and cracking.

Aging Management Programs

The following AMPs are utilized to manage aging effects in the containment cooling service

water system:

* Water Chemistry Program (B.1.2)

* Bolting Integrity Program (B.1.12)

* Open-Cycle Cooling Water System Program (B.1.13)

* Selective Leaching of Materials Program (B.1.24)

* Structures Monitoring Program (B.1.30)

* Buried Piping and Tanks Inspection Program (B.1.25)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the containment cooling service

water system will be adequately managed by these AMPs during the period of extended

operation.

Staff Evaluation.

Aging Effects

The staff reviewed the information in Section 2.3.3.21 and Tables 2.3.3-21, 3.3-1, and 3.3-2 in

the LRA. During its review, the staff determined that additional information was needed.

The description in item 3.3.2.130 of Table 3.3-2 lists loss of material/corrosion as an aging

effect/mechanism for carbon steel, stainless steel, brass, or bronze components in an

environment of air, moisture, humidity and leaking fluid. However, the LRA does not specifically

identify which type of corrosion is responsible for the loss of material. The type of corrosion is

important because it determines the susceptible locations to be inspected. By letter dated

August 4, 2003, the staff requested, in RAI 3.3-2, the applicant to provide a specific description

of the types of corrosion responsible for the aging effect of loss of material for the relevant

components, as well as the criteria for selecting these samples, including susceptible locations

for inspections. The staff's evaluation of the applicant's response is documented in Section

3.3.2.5.2 of this SER.

Aging management of the air handlers (heat exchangers) is addressed by Aging Management

Reference Nos. 3.3.2.8 and 3.3.2.9. While these references discuss both the internal and

external environment of the heat exchanger tubes, it was not clear whether the aging effects or

the AMPs had been identified for both the internal and external environments. The tube internal

environment is open-cycle cooling water (raw water) and the external environment is warm,

moist air. The applicant identified loss of material and cracking as applicable aging effects, and

the credited Open-Cycle Cooling Water System Program (B.1.13) with managing these aging

effects. By letter dated August 4, 2003, the staff requested, in RAI 3.3.2.4.21 (a), the applicant

to provide justification for not identifying any aging effects for the components on the shell side

exposed to warm, moist air, especially considering condensation on the tubes.

In its response dated October 3, 2003, the applicant stated that condensation is present on the

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tubes of the shell side of the air handlers (heat exchangers). Aging Management References

3.3.2.8 and 3.3.2.9 of LRA Table 3.3-2 address open/coil fin type air coolers. The materials are

stainless steel, copper, aluminum, and carbon steel, and they are exposed to warm, moist air.

Appendix G of "Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools,

Revision 3," EPRI 1003056, which is applicable to air handlers in air environments, identifies

loss of material due to wear, buildup of deposit due to fouling, and cracking due to fatigue as

the applicable aging effects/mechanisms for stainless steel, copper, and aluminum air handling

components in air environments. EPRI 1003056, Appendix D, which is applicable to carbon

steel components in air/gas environments, identifies loss of material due to general corrosion,

galvanic corrosion, and MIC as an aging effect/mechanism for carbon steel in air environments.

The applicant stated that Aging Management References 3.3.2.8 and 3.3.2.9, along with Aging

Management Reference 3.3.2.7, include aging effects for both tube side and shell side

surfaces. These references identify the above aging effects/mechanisms for the subject air

handler surfaces in a warm, moist air environment. The applicant stated that the associated

AMP, the Open-Cycle Cooling Water System Program (B.1.13), includes provisions for

inspection of the external surfaces of the air handler cooling water components. On the basis

of its review, the staff finds the applicant's response to RAI 3.3.2.4.21 (a) acceptable because

the applicant has identified the applicable aging effects and has provided an appropriate AMP

to manage the aging effects.

The AMR of this system specifies References 3.3.2.208 and 3.3.2.179 for cast iron components

in raw water. Reference 3.3.2.208 includes galvanic corrosion as a mechanism for loss of

material, but Reference 3.3.2.179 does not. By letter dated August 4, 2003, the staff

requested, in RAI 3.3.2.4.21 (b), the applicant to clarify whether the components covered by

Reference 3.3.2.179 (pump casings) are also susceptible to galvanic corrosion, and to provide

the applicable AMP(s). In its response dated October 3, 2003, the applicant stated that,

according to EPRI 1003056, "Non-Class 1 Mechanical Implementation Guideline and

Mechanical Tools, Revision 3," Appendix B, galvanic corrosion is an applicable aging

mechanism for cast iron components that are in contact with metals higher in the galvanic

series. The applicant stated that Reference 3.3.2.208 is associated with cast iron strainer

bodies in the Dresden containment cooling service water and service water systems. These

strainer bodies are in raw water environments and are in contact with strainer filters made of

stainless steel, which is higher in the galvanic series than cast iron. Therefore, the applicant

concluded that galvanic corrosion is an applicable aging effect for the strainer bodies.

The applicant further stated that Reference 3.3.2.179 is associated with cast iron pump casings

in raw water environments in the Dresden CCSW and service water systems. These pump

casings are not in contact with any metals higher in the galvanic series; therefore, the applicant

concluded that galvanic corrosion is not an applicable aging mechanism. On the basis of its

review, since the pump casings are not in contact with metals higher in the galvanic series, the

staff agrees with the applicant's conclusion that there is no galvanic corrosion of the pump

casings. Therefore, the staff finds the applicant's response to RAI 3.3.2.4.21 acceptable.

The aging effects identified in the LRA for the containment cooling service water system are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible the aging effects were identified and that the aging effects listed

are appropriate for the combination of materials and environments specified.

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Aging Management Programs

The applicant credited the following AMPs for managing the aging effects in the containment

cooling service water system:

* Water Chemistry Program (Section 3.0.3.2)

* Bolting Integrity Program (Section 3.0.3.5)

* Open-Cycle Cooling Water System Program (Section 3.0.3.6)

* Selective Leaching of Materials Program (Section 3.0.3.11)

* Structures Monitoring Program (Section 3.0.3.14)

* Buried Piping and Tanks Inspection Program (Section 3.0.3.12)

The Bolting Integrity Program, Open-Cycle Cooling Water System Program, Water Chemistry

Program, Selective Leaching of Materials Program, Structures Monitoring Program, and Buried

Piping and Tanks Inspection Program are credited with managing the aging effects of several

components in different structures and systems and are, therefore, considered common AMPs.

The staff has evaluated these common AMPs and has found them to be acceptable for

managing the aging effects identified for this system. The staff's evaluation of these AMPs is

documented in Sections 3.0.3.2, 3.0.3.5, 3.0.3.6, 3.0.3.12, 3.0.3.11, 3.0.3.14, and 3.0.3.12,

respectively, of this SER.

The staff identified that loss of material due to galvanic corrosion is location dependent.

Adequate aging management may need to target susceptible locations for inspection and

testing. By letter dated August 4, 2003, the staff asked the applicant to clarify whether the

inspection and testing activities described in the Open-Cycle Cooling Water System Program

(B.1.13) are targeted or opportunistic with respect to managing loss of material due to galvanic

corrosion (RAI B.1.13). In its responses dated October 3, 2003, and December 17, 2003, the

applicant stated that the Open-Cycle Cooling Water System Program manages galvanic

corrosion through periodic inspections of in-scope components, as appropriate. The in-scope

components include heat exchangers and strainer bodies. The applicant further stated that a

new surveillance for periodic inspection of the strainer in the containment cooling service water

supply line to the main control room HVAC refrigeration condensing unit will be added to this

program and will be implemented prior to the end of the current license. The applicant also

updated the UFSAR Supplement for the Open-Cycle Cooling Water System Program to reflect

this addition. The staff concludes that the use of periodic inspections performed as part of the

Open-Cycle Cooling Water System Program is an appropriate method of managing the loss of

material due to galvanic corrosion; therefore, the staff finds this acceptable.

After evaluating the applicant's AMR for each of the components in the containment cooling

service water system, the staff evaluated the AMPs listed above to determine if they are

appropriate for managing the identified aging effects for this system. For those components

identified in Table 3.3-1 of the LRA, the staff verified that the applicant credited the AMPs

recommended by the GALL Report. For the components identified in LRA Table 3.3-2, the staff

verified that the applicant credited AMPs that are appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the containment

cooling service water system will effectively manage or monitor the aging effects identified in

the LRA.

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Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.22 Ultimate Heat Sink

Summary of Technical Information in the ApDlication. The description of the ultimate heat sink

can be found in Section 2.3.3.22 of this SER. The passive, long-lived components in this

system that are subject to an AMR are identified in LRA Tables 2.3.3-22. The components,

aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

Aging Effects

Table 2.3.3-22 of the LRA lists individual system components that are within the scope of

license renewal and subject to AMR. The components include closure bolting, piping and

fittings, stop logs, valves, including the ice melt gates (from the applicant's response to RAI

2.3.3.22-1), and pump casings.

The LRA identifies the following applicable aging effects for the ultimate heat sink. The LRA

identifies that cast iron, low-alloy steel, and carbon steel components in an air, moisture,

humidity, and leaking fluid environment are subject to loss of material from general corrosion,

pitting, and crevice corrosion (for carbon steel and cast iron), as well as crack initiation and

growth from cyclic loading and SCC for the low-alloy steel components. Cast iron components

in raw water or untreated fresh water environments are subject to loss of material from selective

leaching, general, pitting, and crevice corrosion and MIC. Carbon steel components in a

submerged raw water environment are subject to the aging effect of loss of material from

general, pitting, and crevice corrosion, MIC, and macroorganisms. Carbon steel piping and

fittings buried in soil are subject to the aging effect of loss of material due to general, pitting,

and crevice corrosion, and MIC. The LRA does not identify any aging effects for carbon steel

components encased in concrete. The applicant did not identify any aging effects for aluminum

stop logs in the indoor environment (from the applicant's response to RAI 2.3.3.22-2).

Aging Management Programs

The LRA credited the following AMPs for managing the identified aging effects for the ultimate

heat sink:

* Open-Cycle Cooling Water System Program (B.1.13)

* Bolting Integrity Program (B.1.12)

* Structures Monitoring Program (B.1.30)

* Selective Leaching of Materials Program (B.1.24)

* Buried Piping and Tank Inspection (B.1.25)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the ultimate heat sink will be

adequately managed by these AMPs during the period of extended operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

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AMR for the aging effects, and the AMPs credited for managing the aging effects, of the

components in the ultimate heat sink. The staff also reviewed the applicable UFSAR

Supplements for the AMPs to ensure that the program descriptions adequately describe the

AMPs.

Aging Effects

The staff reviewed the information in Tables 2.3.3-22, 3.3-1, and 3.3-2 for the ultimate heat

sink. During its review, the staff determined that additional information was needed.

Metals and alloys that are in contact with different, more cathodic metals or alloys in the

presence of an electrolyte fluid may be subject to the aging effect of loss of material from

galvanic corrosion. Many systems/components of the auxiliary systems described by various

items in Table 3.3-2 of the LRA have material/environment combinations for which loss of

material from galvanic corrosion may be an applicable aging effect/mechanism. However, the

applicant does not include loss of material due to galvanic corrosion as an aging

effect/mechanism that requires management for the period of extended operation. By letter

dated August 4, 2003, the staff issued RAI 3.3-1 pertaining to this issue. The staff's evaluation

of the applicant's response is documented in Section 3.3.2.5.1 of this SER.

By letter dated August 4, 2003, the staff requested, in RAI 3.3-7, the applicant to clarify which

specific AMP(s) is applicable for managing the AMR item 3.3.1.5, "Specific Corrosion

Mechanism," and to explain how the AMP(s) manages that corrosion mechanism for

components in the various auxiliary systems. The staff's evaluation of the applicant's response

is documented in Section 3.3.2.5.7 of this SER.

The applicant uses the Bolting Integrity Program (B.1.12) to manage general corrosion on the

external surfaces of many auxiliary system nonbolting components. The staff notes that the

Bolting Integrity Program description states, 'The program consists of visual inspections for

external surface degradation that may be caused by loss of material or cracking of the bolting,

or by an adverse environment." This suggests that only the bolting material will be inspected

for aging degradation. By letter dated August 4, 2003, the staff requested, in RAI 3.3-9, the

applicant to explain (including the acceptance criteria and inspection interval) how the Bolting

Integrity Program is used to manage general corrosion on external surfaces of non-bolting

components, such as piping, valves, mufflers, and others. The staff's evaluation of the

applicant's response is documented in Section 3.3.2.5.9 of this SER.

Loss of material from erosion and flow blockage from biofouling, silting, and corrosion product

buildup may also be applicable aging effects/aging mechanisms for some cast iron components

in a raw water environment. By letter dated August 4, 2003, the staff requested, in RAI

3.3.2.4.22 (a), the applicant to clarify whether these are applicable aging effects/aging

mechanisms for these components in the ultimate heat sink. If so, the staff requested the

applicant to provide the applicable AMP(s). If not, the applicant was requested to provide the

basis for excluding erosion and flow blockage as applicable aging effects/aging mechanisms,

including applicable operating experience.

In addition, in Table 2.3.3-22 and in item 3.3.2.28 of Table 3.3-2 of the LRA, for the

material/environment of carbon steel components encased in concrete, the applicant stated that

there is no applicable aging effect. The staff notes that good design and construction practices

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are necessary to prevent steel corrosion in an environment of being embedded in concrete. By

letter dated August 4, 2003, the staff requested, in RAI 3.3.2.4.22 (b), the applicant to provide

specifics of the design and construction practices used for the carbon steel components

encased in concrete in the ultimate heat sink, including applicable standards and operating

experience.

In its response dated October 3, 2003, the applicant stated that for part (a) of the RAI

3.3.2.4.22, loss of material from erosion and flow blockage from biofouling, silting, and

corrosion product buildup are not applicable aging effects/aging mechanisms for cast iron

components in a raw water environment in the ultimate heat sink. Cast iron components within

the scope of license renewal in the ultimate heat sink are pumps and valves with a pressure

boundary component intended function. The aging effect/mechanism for these components is

"Loss of materiaVGeneral, pitting and crevice corrosion, selective leaching and microbiologically

influenced corrosion." The applicant further stated that a review of plant operating history did

not reveal any loss of intended function for cast iron components in the ultimate heat sink due

to the erosion and flow blockage aging mechanisms. The applicant clarified that Aging

+i Management Reference 3.3.2.172 addresses the aging management of the internal surfaces of

cast iron components, and that Aging Management Reference 3.3.2.300 addresses the aging

management of the external surfaces of cast iron components.

For part (b) of RAI 3.3.2.4.22, the applicant stated that EPRI TR-1 14881, 'Aging Effects for

Structures and Structural Components (Structural Tools)" identifies that "the high alkalinity of

concrete (pH > 12.5) provides an environment around embedded steel and steel reinforcement

which protects them from corrosion." EPRI TR-1 14881 further states that the corrosion rate is

insignificant until a pH of 4.0 is reached. The concrete structures and structural members are

designed and constructed in accordance with ACI-318-63 and ASTM standards which provide a

good quality, dense, low permeability concrete that provides adequate concrete cover over the

encased steel. The applicant further stated that a review of plant operating history did not

reveal any loss of intended function for the carbon steel components encased in concrete in the

ultimate heat sink.

The applicant clarified that Aging Management Reference 3.3.2.28 discusses the aging

management of external surfaces of the carbon steel components (underground corrugated

steel ice melting piping) encased in concrete, and further stated that Aging Management

Reference 3.3.1.15 discusses the aging management of the internal surfaces of carbon steel

components (underground corrugated steel ice melting piping) in a raw water environment.

On the basis of its review, the staff finds the applicant's response to RAI 3.3.2.4.22 acceptable

because (1) the applicant showed that a review of plant operating history did not reveal any loss

of intended function for cast iron components in the ultimate heat sink due to the erosion and

flow blockage aging mechanisms, and (2) the applicant demonstrated that the concrete

structures and structural members are designed and constructed in accordance with ACI-318-

63 and ASTM standards. Further, the applicant showed that a review of plant operating history

did not reveal any loss of intended function for the carbon steel components encased in

concrete in the ultimate heat sink. The staff considers the issues related to RAI 3.3.2.4.22

parts (a) and (b) to be resolved.

The aging effects identified in the LRA for the ultimate heat sink are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

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plausible the aging effects were identified and that the aging effebts listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the ultimate heat sink:

* Open-Cycle Cooling Water System Program (Section 3.0.3.6)

* Bolting Integrity Program (Section 3.0.3.5)

* Structures Monitoring Program (Section 3.0.3.14)

* Selective Leaching of Materials Program (Section 3.0.3.1 1)

* Buried Piping and Tank Inspection (Section 3.0.3.12)

These AMPs are credited for managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. These AMPs are evaluated in

Sections 3.0.3.6, 3.0.3.5, 3.0.3.14, and 3.0.3.11, and 3.0.3.12, respectively, of this SER.

After evaluating the applicant's AMR for each of the components in the ultimate heat sink, the

staff evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects. For those components identified in Table 3.3-1 of the LRA, the staff

verified that the applicant credited the AMPs recommended by the GALL Report. For the

components identified in LRA Table 3.3-2, the staff verified that the applicant credited an AMP

that is appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the ultimate heat

sink will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.23 Fuel Pool Cooling and Filter Demineralizer System (Dresden Only)

Summary of Technical Information in the ApDlication. The description of the fuel pool cooling

and filter demineralizer system can be found in Section 2.3.3.23 of this SER. The passive,

long-lived components in this system that are subject to an AMR are identified in LRA Table

2.3.3-23. The components, aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-

2.

Aging Effects

Components of the fuel pool cooling and filter demineralizer system are described in Section

2.3.3.23 of the LRA as being within the scope of license renewal and subject to an AMR. Table

2.3.3-23 of the LRA lists individual components of the system including fittings, valves, sight

glasses, and closure bolting.

Carbon steel and low-alloy steel exposed to external sheltered environment with warm, moist air

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is subject to loss of material due to corrosion. No aging effect is identified for stainless steel

exposed to external sheltered environment with warm, moist air. Carbon steel exposed to

internal environment of demineralized oxygenated water, wet gas, or warm, moist air is subject

to loss of material due to general, pitting, and crevice corrosion. Stainless steel exposed to

internal environment of chemically treated oxygenated water is subject to loss of material due to

general, pitting, and crevice corrosion.

Aging Management Programs

The following AMPs are utilized to manage aging effects in the fuel pool cooling and filter

demineralizer system:

* Water Chemistry Program (B.1.2)

* One-time Inspection Program (B.1.23)

* Bolting Integrity Program (B.1.12)

* Structures Monitoring Program (B.1.30)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effect of aging associated with the components of the fuel pool cooling and filter

demineralizer system will be adequately managed by these AMPs during the period of extended

operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, in the

components of the fuel pool cooling and filter demineralizer system. The staff also reviewed

the applicable UFSAR Supplements for the AMPs to ensure that the program descriptions

adequately describe the AMPs.

Aging Effects

The staff reviewed the information in Section 2.3.3.23 and Tables 2.3.3-23, 3.3-1, and 3.3-2 in

the LRA. During its review, the staff determined that additional information was needed to

complete its review.

The description in Item 3.3.2.130 of Table 3.3-2 lists loss of material/corrosion as the aging

effect/mechanism for carbon steel, stainless steel, brass, or bronze components in an

environment of air, moisture, humidity, and leaking fluid. However, the LRA does not

specifically identify which type of corrosion is responsible for the loss of material. The type of

corrosion is important because it determines the susceptible locations to be inspected. By letter

dated August 4, 2003, the staff requested, in RAI 3.3-2, the applicant to provide a specific

description of the types of the corrosion responsible for the aging effect of loss of material for

the relevant components and the criteria for selecting these samples including susceptible

locations for inspections. The staff's evaluation of the applicant's response is documented in

Section 3.3.2.5.2 of this SER.

NUREG-1 801 identifies loss of material due to corrosion is an aging effect for shell-side

components (shell and access cover, channel head, and tubes) of the heat exchanger of the

fuel pool cooling and cleanup system exposed to closed-cycle cooling water. LRA Table 2.3.3-

23 does not include any aging effect for the heat exchanger of the fuel pool cooling and cleanup

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system. By letter dated August 4, 2003, the staff requested, in RAI 3.3.2.4.23, the applicant to

provide justification for not identifying any aging effect for the shell-side components of the heat

exchanger of the fuel pool cooling and filter demineralizer system in LRA Table 2.3.3-23.

In its response dated October 3, 2003, the applicant stated that the applicant does not consider

the Dresden heat exchangers associated with the fuel pool cooling and cleanup system to be

within the scope of license renewal. The applicant explained that the fuel pool cooling and

cleanup system is a non-safety:related closed-loop system that is normally in continuous

operation. In normal operation, the fuel pool cooling and cleanup system interfaces directly with

the spent fuel pool, which is a Class I structure, and during refueling operations it may be

aligned to support filling or draining the reactor cavity and/or the equipment storage pool. The

non-safety-related reactor building closed cooling water system provides the cooling medium'

for the fuel pool cooling heat exchangers, and the non-safety-related demineralized water

makeup system is the normal makeup water supply for the fuel storage pool. Each of the two

spent fuel pool cooling system return lines to the spent fuel pool have openings in the pipe

about 6 inches below the pool surface to act as antisiphon devices by allowing air into the pipe

to break the vacuum if siphoning begins. This precludes uncontrolled draining of the spent fuel

pool in the event of a pipe failure. Additionally, the heat exchangers are not located near

safety-related equipment that could be affected by failure of these components.

The applicant further explained that the complete loss of fuel pool cooling could result in

overheating of fuel rods stored in the fuel pool if makeup systems were not activated and the

fuel pool were allowed to boil away. However, this is not a design- or licensing-basis event and

several hours would be available for restoration of makeup systems. Makeup systems available

include the condensate transfer system, the demineralized water system, and the fire water

system, any of which could be connected by hoses to provide makeup to the spent fuel pool.

Calculations performed as part of the extended power uprate evaluation determined that with a

complete loss of cooling to the spent fuel pool, it would take at least 8 hours for the Dresden

fuel pool to reach 212 'F (100 'C) . This would provide adequate time to establish alternative

sources of makeup water to the pool. Because failure of the fuel pool cooling system does not

threaten to cause consequential failure of other safety-related systems or components, and

because postulated failure of the fuel pool cooling system allows ample time to implement

alternative makeup to the fuel pool, failure of the fuel pool cooling system is not considered a

failure of a non-safety-related system whose failure could prevent satisfactory accomplishment

of any of the safety-related functions identified in 10 CFR 54.4(a)(1).

The staff understands that the fuel pool cooling and cleanup system at Dresden is a non-safetyrelated closed-loop system that is normally in continuous operation. The design objectives of

the system are to handle the spent fuel pool cooling load and to maintain pool water clarity.

The only intended function of the system is to preclude adverse effects from failure of segments

of piping and components on safety-related SSCs.

In its response dated October 3, 2003, the applicant stated that the fuel pool cooling and

cleanup system (with the exception of the segments of piping discussed below) is not located

near safety-related equipment that could be affected by failure of fuel pool cooling and cleanup

system components. The applicant performed a walkdown of the system and determined

that-

* The segment of line 2-1910B-6W-K red highlighted on boundary diagram LR-DRE-M-31 is in

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scope of license renewal because it is physically located such that leakage or spray from

this line could spatially interact with safety-related primary containment isolation valve AOV

2-1601-23.

* The red-highlighted portion of the drain line (from globe valve 3-1901 -11 to the 6"x4"

reducer) as shown on boundary diagram LR-DRE-M-362 is physically located such that

leakage from this line could spatially interact with safety-related primary containment

isolation valve AOV 3-1601-23. Because of this spatial relationship, the highlighted portion

of the line was determined to be in scope of license renewal.

On the basis of its review, the staff finds the applicant's response acceptable because the spent

fuel pool cooling heat exchangers are not located near safety-related equipment and their

failure does not threaten to cause consequential failure of other safety-related systems or

components. Therefore, the spent fuel pool cooling heat exchangers are not in scope of

license renewal and are not included in LRA Table 2.3.3.12. The staff considers issues related

to RAI 3.3.2.4.23 to be resolved.

The aging effects identified in the LRA for the fuel pool cooling and filter demineralizer system

are consistent with industry operating experience for the materials and environments listed.

The staff finds that all the plausible the aging effects were identified and that the aging effects

listed are appropriate for the combination of materials and environments specified.

Aging Management Programs

The applicant credited the following AMPs for managing the aging effects in the fuel pool

cooling and filter demineralizer system.

* Water Chemistry Program (Section 3.0.3.2)

* One-time Inspection Program (Section 3.0.3.10)

* Bolting Integrity Program (Section 3.0.3.5)

* Structures Monitoring Program (Section 3.0.3.14)

* Periodic Inspection of Components Subject to Moist Environments Program (Section

3.0.3.18)

As part of RAI B.1.23.2-6, the staff questioned the use of the one-time inspections to manage

aging for components in a moist air environment. In its response dated March 25, 2004, the

applicant credited the Periodic Inspection of Components Subject to Moist Environments

program to manage aging effects for stainless steel, carbon steel, cast iron, aluminum, copper,

and brass and bronze components exposed to moist air environments and subject to wetting.

The staff's evaluation of the Periodic Inspection of Components Subject to Moist Environments

AMP is contained in SER section 3.0.3.18.

The Water Chemistry, One-time Inspection, Bolting Integrity, and Structures Monitoring

Programs are credited with managing the aging effects of several components in different

structures and systems and are, therefore, considered common AMPs. The staff has evaluated

these common AMPs and has found them to be acceptable for managing the aging effects

identified for this system. The staff's evaluation of these AMPs is documented in Sections

3.0.3.2, 3.0.3.10, 3.0.3.5, and 3.0.3.14 of this SER.

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After evaluating the applicant's AMR for each of the components in the fuel pool cooling and

filter demineralizer system, the staff evaluated the AMPs listed above to determine if they are

appropriate for managing the identified aging effects for this system. For those components

identified in Table 3.3-1 of the LRA, the staff verified that the applicant credited the AMPs

recommended by the GALL Report. For the components identified in LRA Table 3.3-2, the staff

verified that the applicant credited AMPs that are appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the fuel pool

cooling and filter demineralizer system will effectively manage or monitor the aging effects

identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.24 Plant Heating System

Summary of Technical Information in the ADplication. The description of the plant heating

system can be found in Section 2.3.3.24 of this SER. The passive, long-lived components in

this system that are subject to an AMR are identified in LRA Table 2.3.3-24. The components,

aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

Aging Effects

Table 2.3.3-24 of the LRA lists individual system components that are within the scope of

license renewal and subject to an AMR. The components include closure bolting,

filters/strainers, NSR vents or drains, piping and valves (Dresden only), piping and fittings,

pumps, sight glasses (Quad Cities only), tanks, thermowells (Dresden only), traps, tubing, and

valves. All of these components are in the scope of license renewal due to the potential for

spatial interactions.

The LRA identified the following applicable aging effects for the plant heating system. The LRA

identifies that cast iron, low-alloy steel, carbon steel, stainless steel, and brass or bronze

components in air, moisture, humidity, or leaking fluid environments are subject to loss of

material from general corrosion (not for stainless steel), pitting and crevice corrosion, as well as

crack initiation and growth from cyclic loading, and SCC for the low-alloy steel components.

Cast iron, carbon steel, copper, and brass or bronze components in saturated

steam/condensate environments are subject to loss of materials from general corrosion; while

stainless steel components in the same environment are subject to the aging effects of loss of

material from pitting and crevice corrosion. The LRA does not identify any aging effects for

stainless steel, copper, and brass or bronze components in the air, moisture, and humidity less

than 100 'C (212 'F) environment.

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Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the plant

heating system.

* Open-Cycle Cooling Water System Program (B.1.13)

* Bolting Integrity Program (B.1.12)

* One-Time Inspection Program (B.1.23)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the plant heating system will be

adequately managed by these AMPs during the period of extended operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, in the

components of the plant heating system. The staff also reviewed the applicable UFSAR

Supplements for the AMPs to ensure that the program descriptions adequately describe the

AMPs.

Aging Effects

The staff reviewed the information in Tables 2.3.3-24, 3.3-1, and 3.3-2 for the plant heating

system. During its review, the staff determined that additional information was needed to

complete its review.

Metals and alloys that are in contact with different, more cathodic metals or alloys in the

presence of an electrolyte fluid may be subjected to the aging effect of loss of material from

galvanic corrosion. Many system components of the auxiliary system described by various

items in Table 3.3-2 of the LRA have materials/environment combinations to which loss of

material from galvanic corrosion may be an applicable aging effect/mechanism. However, the

applicant does not include loss of material due to galvanic corrosion as an aging

effect/mechanism that requires management for the period of extended operation. By letter

dated August 4, 2003, the staff issued RAI 3.3-1 pertaining to this issue. The staff's evaluation

of the applicant's response is documented in Section 3.3.2.5.1 of this SER.

The description in Item 3.3.2.130 of Table 3.3-2 lists loss of material/corrosion as aging

effect/mechanism for carbon steel, stainless steel, and brass or bronze components in an

environment of air, moisture, humidity, and leaking fluid. However, the LRA does not

specifically identify which type of corrosion is responsible for the loss of material. The type of

corrosion is important because it determines the susceptible locations to be inspected. By letter

dated August 4, 2003, the staff requested, in RAI 3.3-2, the applicant to provide a specific

description of the types of corrosion responsible for the aging effect of loss of materials for the

relevant components and the criteria for selecting these samples, including susceptible

locations for inspections. The staff's evaluation of the applicant's response is documented in

Section 3.3.2.5.2 of this SER.

Carbon steel, stainless steel, and brass and bronze components exposed to moist gas (moist

nitrogen) or moist air environment may experience aging effects of loss of material due to

general (for carbon steel only), pitting, and crevice corrosion (for both carbon steel and

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stainless steel) when pollutants such as oxygen, SO2, NO1, or CO are present in the moist air,

particularly when the humidity is greater than 60 percent. However, in Table 3.3-2, the

applicant concluded that no aging effects are identified for the external surfaces of the carbon

steel and stainless steel piping and fittings, accumulators, dampeners, filters/strainers, flow

elements, pumps, orifices, rupture discs, tanks, tubing, and valve components exposed to

either the containment nitrogen gas environment or air, moisture, humidity environment

because these components are not subject to any viable aging mechanism in the absence of

aggressive chemical species. By letter dated August 4, 2003, the staff issued RAI 3.3-3

requesting the applicant to provide information on whether the pollutants such as oxygen, NO1,

SO2 or CO are present, and, if so, to what extent in the containment gas or air, moisture,

humidity environments to justify the conclusions in Table 3.3-2, Reference Nos. 3.3.2.27 and

3.3.2.40. The staff's evaluation of the applicant's response is documented in Section 3.3.2.5.3

of this SER.

Loss of material from selective leaching may be an applicable aging effect/aging mechanism for

cast iron and brass components in saturated steam/condensate, as well as air, moisture,

humidity, and leaking fluid environments if stagnant liquids are present in these environments;

however, the LRA only identifies a loss of material due to general corrosion for these

components. By letter dated August 4, 2003, the staff requested, in RAI 3.3.2.4.24(a), the

applicant to clarify whether selective leaching is applicable to components in the plant heating

system and, if so, to provide the applicable AMP(s). In its responses dated October 3 and

December 22, 2003, the applicant stated that these components are subject to loss of material

due to general corrosion, and they may also be subject to loss of material due to selective

leaching if stagnant liquids are present in these environments. The loss of material is managed

by periodic inspections in stagnant flow areas. The applicant also stated that selective leaching

in brass alloys results in either a uniform attack or a localized plug attack, while selective

leaching of gray cast iron results in iron being dissolved, leaving a porous mass consisting of

graphite, voids, and rust. The applicant stated that the inspection will detect the loss of material

whether it is due to selective leaching or general corrosion. The staff finds that periodic

inspections for loss of material will identify selective leaching if it is occurring; therefore, the

staff finds this acceptable.

The aging effects identified in the LRA for the plant heating system are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant credited the following AMPs to manage the aging effects described above for the

plant heating system.

* Open-Cycle Cooling Water System Program (Section 3.0.3.6)

* Bolting Integrity Program (Section 3.0.3.5)

* One-Time Inspection Program (Section 3.0.3.10)

* Periodic Inspection of Plant Heating System (Section 3.3.2.3.7)

These AMPs are credited for managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. These AMPs are evaluated in

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Sections 3.0.3.6, 3.0.3.5, 3.0.3.10, and 3.3.2.3.7 of this SER.

The LRA credits a one-time inspection for aging management of a carbon steel tank in this

system. By letter dated August 4, 2003, the staff asked for clarification related to whether all

parts of the tank are accessible, or how the inaccessible parts of the tank would be managed.

In its response dated October 3,2003, the applicant stated that the tanks (grouped under Aging

Management Reference 3.3.2.214) are not buried or embedded in a way that makes large

areas of the tanks inaccessible for inspection and will be periodically inspected.

Consistent with its response to RAI B.1.23-2, the applicant stated that one or more components

in the plant heating system with material consisting of carbon steel exposed to an environment

of saturated steam/condensate will be periodically inspected using the Period Inspection of

Plant Heating System Program (B.2.8), which is described in the applicant's letter dated

January 26, 2004. The applicant further stated that the inspected component(s) will serve as a

representative sample for all carbon steel components in the plant heating system,

encompassing both the accessible parts of the plant heating system and any small areas of the

tank where access may be difficult. The staff noted that the applicant planned to periodically

inspect a representative sample of accessible locations, but that it was not clear that the

accessible locations would be a leading indicator for the tank bottom. The staff noted that this

system is only in scope for spatial interactions and a leak in the tank bottom may not pose a

concern. Therefore, the staff asked the applicant to describe how the proposed inspections

would bound the loss of material in the tank bottom, or justify that a leak in this area is not a

concern. In its response dated December 22, 2003, the applicant stated that the plant heating

steam system was included within the scope of license renewal at both sites because of the

numerous instances in which heating steam components were found located above safetyrelated equipment. In these instances, the possibility exists in which failed plant heating steam

components could spray water onto safety-related equipment located below. While not all

heating steam components have the ability to spatially interact with safety-related equipment, a

decision was made to include all of the plant system components within the scope of license

renewal. The applicant further stated that the tanks in question are among those plant heating

steam components that cannot spatially interact with safety-related equipment. Therefore, the

applicant concluded that potential leakage from the plant heating system tanks does not

jeopardize the functionality of any safety-related structures or components, and does not

present a concern for loss of any safety-related intended functions during the period of

extended operation. The staff concludes that the proposed inspections would adequately

identify degradation of the plant heating system; therefore, the staff finds this acceptable.

After evaluating the applicant's AMR for each of the components in the plant heating system,

the staff evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects. For those components identified in Table 3.3-1 of the LRA, the staff

verified that the applicant credited the AMPs recommended by the GALL Report. For the

components identified in LRA Table 3.3-2, the staff verified that the applicant credited an AMP

that is appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the plant heating

system will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

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consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.25 Containment Atmosphere Monitoring System

Summary of Technical Information in the Application. The description of the containment

atmosphere monitoring system can be found in Section 2.3.3.25 of this SER. The passive,

long-lived components in this system that are subject to an AMR are identified in LRA Tables

2.3.3-25. The components, aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-

2.

Aging Effects

Table 2.3.3-25 of the LRA lists individual system components that are within the scope of

license renewal and subject to an AMR. Table 2.3.3-25 lists all component groups in this

category, components not evaluated in GALL and considered as plant-specific, in the

containment atmosphere monitoring system. The' components listed by the applicant in the

Dresden/Quad Cities Nuclear Stations LRA for this category include closure bolting,

filters/strainers, flexible hoses, NSR vents or drains, piping and valves (attached support),

piping and fittings (attached support), piping and fittings, pumps, restricting orifices, sample

pumps, tubing, valves, and valves (attached support).

The LRA identified the following applicable aging effects for the containment atmosphere

monitoring system. The LRA identifies that low-alloy steel, carbon steel, stainless steel, and

brass or bronze components in air, moisture, humidity, or leaking fluid environments are subject

to loss of material from general corrosion (not for stainless steel), pitting, and crevice corrosion,

as well as crack initiation and growth from cyclic loading, SCC for the low-alloy steel

components. Stainless steel components in warm, moist air and wet gas environments, as well

as moist containment atmosphere (air/nitrogen), steam, or demineralized water environment

are subject to loss of materials from pitting and crevice corrosion. Elastomer neoprene and

similar materials in both dry gas and warm, moist air environments are subject to the aging

effect of hardening and loss of strength from elastomer degradation. The LRA does not identify

any aging effect for stainless steel, or brass or bronze components in dry gas environment and

in containment nitrogen environment (for stainless steel).

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the

containment atmosphere monitoring system.

* One-Time Inspection Program (B.1.23)

* Bolting Integrity Program (B.1.12)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the containment atmosphere

monitoring system will be adequately managed by these AMPs during the period of extended

operation.

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Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, in the

components of the containment atmosphere monitoring system. The staff also reviewed the

applicable UFSAR Supplements for the AMPs to ensure that the program descriptions

adequately describe the AMPs.

Aging Effects

The staff reviewed the information in Tables 2.3.3-25, 3.3-1, and 3.3-2 for the containment

atmosphere.monitoring system. During its review, the staff determined that additional

information was needed to complete its review.

Carbon steel, stainless steel, and brass and bronze components exposed to moist gas (moist

nitrogen) or moist air environment may experience aging effects of loss of material due to

general (for carbon steel only), pitting, and crevice corrosion (for both carbon steel and

stainless steel) when pollutants such as oxygen, SO2, NOR, or CO are present in the moist air,

particularly when the humidity is greater than 60 percent. However, in Table 3.3-2, the

applicant concluded that no aging effects are identified for the external surfaces of the carbon

steel and stainless steel piping and fittings, accumulators, dampeners, filters/strainers, flow

elements, pumps, orifices, rupture discs, tanks, tubing, and valve components exposed to

either the containment nitrogen gas environment or air, moisture, humidity environment

because these components are not subject to any viable aging mechanism in the absence of

aggressive chemical species. By letter dated August 4, 2003, the staff issued RAI 3.3-3

] requesting the applicant to provide information on whether the pollutants such as oxygen, NOR,

SO2.or CO are present, and, if so, to what extent in the containment gas or air, moisture,

humidity environments to justify the conclusions in Table 3.3-2, Reference Nos. 3.3.2.27 and

3.3.2.40. The staff's evaluation of the applicant's response is documented in Section 3.3.2.5.3

I of this SER.

The aging effects identified in the LRA for the containment atmosphere monitoring system are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible the aging effects were identified and that the aging effects listed

are appropriate for the combination of materials and environments specified.

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Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the containment atmosphere monitoring system.

* One-Time Inspection Program (Section 3.0.3.10)

* Bolting Integrity Program (Section 3.0.3.5)

* Periodic Inspection of Components Subject to Moist Environments (3.0.3.18)

As part of RAI B.1.23.2-6, the staff questioned the use of the one-time inspections to manage

aging for components in a moist air environment. In its response dated March 25, 2004, the

applicant credited the Periodic Inspection of Components Subject to Moist Environments

program to manage aging effects for stainless steel, carbon steel, cast iron, aluminum, copper,

and brass and bronze components exposed to moist air environments and subject to wetting.

The staff's evaluation of the Periodic Inspection of Components Subject to Moist Environments

AMP is contained in SER section 3.0.3.18.

These AMPs are credited for managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. The staff's evaluation of these

AMPs is documented in Sections 3.0.3.10 and 3.0.3.5 of this SER.

After evaluating the applicant's AMR for each of the components in the containment

atmosphere monitoring system, the staff evaluated the AMPs listed above to determine if they

are appropriate for managing the identified aging effects. For those components identified in

Table 3.3-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by

the GALL Report. For the components identified in LRA Table 3.3-2, the staff verified that the

applicant credited an AMP that is appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the containment

atmosphere monitoring system will effectively manage or monitor the aging effects identified in

the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.26 Nitrogen Containment Atmosphere Dilution System

Summary of Technical Information in the Application. The description of the nitrogen

containment atmosphere dilution system can be found in Section 2.3.3.26 of this SER. The

passive, long-lived components in this system that are subject to an AMR are identified in LRA

Table 2.3.3-26. The components, aging effects, and AMPs are provided in LRA Tables 3.3-1

and 3.3-2.

Aging Effects

Table 2.3.3-26 of the LRA lists individual system components within the scope of license

renewal and subject to an AMR. The components include closure bolting, restricting orifices

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(Dresden only), tubing, and valves.

High-strength, low-alloy steel closure bolting components exposed to outdoor ambient

conditions are subject to loss of materials due to general corrosion and wear, copper, brass, or

bronze components exposed to dry gas or air, moisture, and humidity environment experience

no aging effect; copper, brass, or bronze components exposed to outdoor ambient conditions

are subject to aging effect of loss of materials due to pitting and crevice corrosion.

Aging Management Programs

The LRA credited the following AMP with managing the identified aging effects for the nitrogen

containment atmosphere dilution system:

* Bolting Integrity Program (B.1.12)

A description of this AMP is provided in Appendix B of the LRA. The applicant concluded that

the effect of aging associated with the components of the nitrogen containment atmosphere

dilution system will be adequately managed by this AMP during the period of extended

operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMP credited for managing the aging effects, in the

components of the nitrogen containment atmosphere dilution system. The staff also reviewed

the applicable UFSAR Supplement for the AMP to ensure that the program description

adequately describes the AMP.

Aging Effects

The staff reviewed the information in Section 2.3.3.26, Table 2.3.3-26, and Table 3.3-2 in the

LRA. During its review, the staff determined that additional information was needed to

complete its review.

In LRA Table 3.3-2, Reference No. 3.3.2.18, the applicant stated that high-strength, low-alloy

steel closure bolting components in the outdoor ambient conditions are subject to aging effects

of loss of material due to general corrosion and wear. However, the applicant did not include

crack initiation and growth due to SCC or other mechanisms as applicable aging

effects/mechanisms. By letter dated August 4, 2003, the staff requested, in RAI 3.3-5, the

applicant to provide technical basis for not including this aging effect/mechanism. The staff's

evaluation of the applicant's response is documented in Section 3.3.2.5.5 of this SER.

In LRA Table 3.3-2, Reference Nos. 3.3.2.23 and 3.3.2.34, the applicant concluded that no

aging effects were identified for the external surfaces of copper tanks and accumulators and

the external surfaces of brass or bronze valves. By letter dated August 4, 2003, the staff

requested, in RAI 3.3.2.4.3, the applicant to provide the technical basis (including the level of

humidity and the level of pollutants) for this conclusion. The evaluation of the applicant's

response is documented in Section 3.3.2.4.3 of this SER.

The aging effects identified in the LRA for the nitrogen containment atmosphere dilution system

are consistent with industry operating experience for the materials and environments listed.

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The staff finds that all the plausible the aging effects were identified and that the aging effects

listed are appropriate for the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMP to manage the aging effects described above for

the nitrogen containment atmosphere dilution system.

* Bolting Integrity Program (Section 3.0.3.5)

This AMP is credited for managing the aging effects on components in several structures and

systems and, therefore, is considered a common AMP. The staff has evaluated this common

AMP and has found it to be acceptable for managing the aging effects identified for this system.

The staff's evaluation of this AMPs is documented in Section 3.0.3.5 of this SER.

After evaluating the applicant's AMR for each of the components in the nitrogen containment

atmosphere dilution system, the staff evaluated the AMP listed above to determine if it is

appropriate for managing the identified aging effects for this system. For those components

identified in Table 3.3-1 of the LRA, the staff verified that the applicant credited the AMP

recommended by the GALL Report. For the components identified in LRA Table 3.3-2, the staff

verified that the applicant credited the AMP that is appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the nitrogen

containment atmosphere dilution system will effectively manage or monitor the aging effects

identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.27 Drywell Nitrogen Inerting System

Summary of Technical Information in the Application. The description of the drywell nitrogen

inerting system can be found in Section 2.3.3.27 of the LRA. The passive, long-lived

components in this system that are subject to an AMR are identified in LRA Table 2.3.3-27.

The components, aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

Aging Effects

Table 2.3.3-28 of the LRA lists individual system components within the scope of license

renewal and subject to an AMR. The components include closure bolting, filters/strainers , flow

elements, isolation barriers, piping and fittings, tanks (include vaporizers), thermowells, traps

(Quad Cities only), tubing, and valves.

Aluminum, brass or bronze, carbon steel, or stainless steel components exposed to dry gas

experience no aging effect. Carbon steel and stainless steel components exposed to warm,

moist air are subject to aging effect of loss of material due to general (carbon steel only),

pitting, and crevice corrosion. Brass or bronze components exposed to saturated air are subject

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to aging effect of loss of material due to pitting and crevice corrosion. Aluminum, copper, and

stainless steel components exposed to air, moisture, and humidity environment experience no

aging effect. Carbon steel components exposed to containment nitrogen experience no aging

effect. Copper, brass, or bronze components exposed to outdoor ambient conditions are

subject to aging effect of loss of material due to pitting and crevice corrosion. Aluminum

components exposed to outdoor ambient conditions are subject to aging effect of loss of

material due to pitting corrosion. Stainless steel exposed to outdoor ambient environments

experience no aging effect.

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the drywell

nitrogen inerting system:

* Bolting Integrity Program (B.1.12)

* 10 CFR Part 50, Appendix J (B.1.28)

* Structures Monitoring Program (B.1.30)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effect of aging associated with the components of the drywell nitrogen inerting system

will be adequately managed by these AMPs during the period of extended operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, in the

components of the drywell nitrogen inerting system. The staff also reviewed the applicable

UFSAR Supplements for the AMPs to ensure that the program descriptions adequately

describe the AMPs.

Aging Effects

The staff reviewed the information in Section 2.3.3.27, Table 2.3.3-27, and Tables 3.3-1 and

3.3-2 in the LRA. During its review, the staff determined that additional information was needed

to complete its review.

The description in Item 3.3.2.130 of Table 3.3-2 lists loss of material/corrosion as aging

effect/mechanism for carbon steel, stainless steel, and brass or bronze components in an

environment of air, moisture, humidity, and leaking fluid. However, the LRA does not

specifically identify which type of corrosion is responsible for the loss of material. The type of

corrosion is important because it determines the susceptible locations to be inspected. By letter

dated August 4, 2003, the staff requested, in RAI 3.3-2, the applicant to provide a specific

description of the types of corrosion responsible for the aging effect of loss of materials for the

relevant components and the criteria for selecting these samples, including susceptible

locations for inspections. The staff's evaluation of the applicant's response is documented in

Section 3.3.2.5.2 of this SER.

Aluminum and aluminum alloy components may experience general, pitting, and crevice

corrosion when exposed to moisture and humidity environments, especially with the presence

of contaminants and water (condensation from moist air). However, AMR Reference No.

3.3.2.126 of Table 3.3-2 of the LRA, only identifies loss of material due to general and pitting

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corrosion as plausible aging effects for aluminum components exposed to moist air. In Table

3.3-2, Reference No. 3.3.2.21 of the LRA, the applicant concluded that there is no aging effect

on aluminum components of the air handlers heating/cooling system exposed to air, moisture,

and humidity environments. By letter dated August 4, 2003, the staff requested, in RAI 3.3-4,

the applicant to (1) explain the different conclusions on aging effects described above, (2)

provide the technical basis for not including loss of material due to crevice corrosion as an

applicable aging effect, and (3) clarify if there is any condensate on the aluminum fins of cooling

coils. The staff's evaluation of the applicant's response is documented in Section 3.3.2.5.4 of

this SER.

In LRA Table 3.3-2, Reference Nos. 3.3.2.23 and 3.3.2.34, the applicant concluded that no

aging effects were identified for the external surfaces of copper tanks and accumulators and

the external surfaces of brass or bronze valves.: By letter dated August 4, 2003, the staff

requested, in RAI 3.3.2.4.3, the applicant to provide the technical basis (including the level of

humidity and the level of pollutants) for this conclusion. The evaluation of the applicant's

response is documented in Section 3.3.2.4.3 of this SER.

In Table 3.3-2, Reference No. 124 of the LRA, the applicant identified carbon steel material

exposed to warm, moist air as subject to aging effect of loss of material due to pitting and

crevice corrosion. However, in Reference No. 273 for the same material/environment

combination, the applicant identified loss of material due to general, pitting, and crevice

corrosion as the applicable aging effect. By letter dated August 4, 2003, the staff issued RAI

3.3.2.4.27 requesting the applicant to clarify why different AMR results were arrived at for

components with the same materiaVenvironment combinations.

In its response dated October 3, 2003, the applicant stated that Aging Management Reference

3.3.2.124 assigned to Table 3.3-2 inadvertently omitted general corrosion. Table 3.3-2, Aging

Management Reference 3.3.2.124 should have read "Loss of materiaVGeneral, pitting and

crevice corrosion." On the basis of its review, the staff finds the applicant's response adequate

and acceptable because the applicant has added general corrosion to Reference No. 3.3.2.124

and the corresponding AMP.

The aging effects identified in the LRA for the drywell nitrogen inerting system are consistent

with industry operating experience for the materials and environments listed. The staff finds

that all the plausible the aging effects were identified and that the aging effects listed are

appropriate for the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the drywell nitrogen inerting system.

* Bolting Integrity Program (Section 3.0.3.5)

* 10 CFR Part 50, Appendix J (Section 3.0.3.13)

* Structures Monitoring Program (Section 3.0.3.14)

* Periodic Inspection of Components Subject to Moist Environments (3.0.3.18)

As part of RAI B.1.23.2-6, the staff questioned the use of the one-time inspections to manage

aging for components in a moist air environment. In its response dated March 25, 2004, the

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applicant credited the Periodic Inspection of Components Subject to Moist Environments

program to manage aging effects for stainless steel, carbon steel, cast iron, aluminum, copper,

and brass and bronze components exposed to moist air environments and subject to wetting.

The staff's evaluation of the Periodic Inspection of Components Subject to Moist Environments

AMP is contained in SER section 3.0.3.18.

These AMPs are credited with managing the aging effects on components in several structures

and systems and, therefore, are considered common AMPs. The staff has evaluated these

common AMPs and found them to be acceptable for managing the aging effects identified for

this system. The staffs evaluation of these AMPs is documented in Sections 3.0.3.5, 3.0.3.13,

and 3.0.3.14 of this SER.

After evaluating the applicant's AMR for each of the components in the drywell nitrogen inerting

system, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects for this system. For those components identified in Table

3.3-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by the

GALL Report. For the components identified in LRA Table 3.3-2, the staff verified that the

applicant credited AMPs that are appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the drywell

nitrogen inerting system will effectively manage or monitor the aging effects identified in the

LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.4.28 Safe Shutdown Makeup Pump System (Quad Cities Only)

Summary of Technical Information in the ApDlication. The description of the safe shutdown

makeup pump system can be found in Section 2.3.3.28 of this SER. The passive, long-lived

components in this system that are subject to an AMR are identified in LRA Table 2.3.3-28.

The components, aging effects, and AMPs are provided in LRA Tables 3.3-1 and 3.3-2.

Aging Effects

Table 2.3.3-28 of the LRA lists individual system components within the scope of license

renewal and subject to an AMR. The components include air handlers heating/cooling (auxiliary

and RW HVAC), access doors, closure bolting, ducts and fittings, closure bolts, equip frames,

filters/strainers, piping and fittings (include spectacles), pumps, restricting orifices, and valves.

Piping and fittings (including spectacle flanges), pumps, restricting orifices, and valve

components in the safe shutdown makeup pump system exposed to the reactor water

environment are subject to loss of material due to general, pitting, and crevice corrosion. Ducts

and fittings, access doors, closure bolts, equip frames, filters/strainers, piping and fittings

(including spectacle flanges), pumps, and valve components in the safe shutdown makeup

pump system exposed to warm, moist air environment are subject to loss of material due to

general, pitting, and crevice corrosion, and MIC. Air handlers heating/cooling components with

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copper tubes, stainless steel tubesheets, and carbon steel end bells exposed to raw water on

the tube side and warm, moist air on the shell (including the fin) side are subject to aging

effects of loss of material due to general, galvanic, pitting, and crevice corrosion, MIC, erosion

or flow-accelerated corrosion, and wear and cracking due to mechanical fatigue and SCC. Air

handlers with tube sides exposed to raw water are also subject to aging effect of loss'of

intended function due to buildup of deposit and fouling. Aluminum fins and stainless steel

components exposed to air, moisture, and humidity (less thanl 00 CC) experience no aging

effect.

Aging'Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the safe

shutdown makeup pump system:

* Water Chemistry Program (B.1.2)

* BWR Stress-Corrosion Cracking Program (B.1.7)

* Bolting Integrity Program (B.1.12)

* Open-Cycle Cooling Water System Program (B.1.13)

* Fire Water System (B.1.19)

* One-Time Inspection Program (B.1.23)

* Structures Monitoring Program (B.1.30)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effect of aging associated with the components of the safe shutdown makeup pump

system will be adequately managed by these AMPs during the period of extended operation.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, on

components in the safe shutdown makeup pump system. The staff also reviewed the

applicable UFSAR Supplements for the AMPs to ensure that the program descriptions

adequately describe the AMPs.

Aging Effects

The staff reviewed the information in Section 2.3.3.28, Table 2.3.3-28, and Table 3.3-2 in the

LRA. During its review, the staff determined that additional information was needed to

complete its review.

Aluminum and aluminum alloy components may experience general, pitting, and crevice

corrosion when exposed to moisture and humidity environments, especially with the presence

of contaminants and water (condensation from moist air). However, in Table 3.3-2, Reference

No. 3.3.2.126 of the LRA, the applicant identified only loss of material due to general and pitting

corrosion as plausible aging effects for aluminum components exposed to moist air. In Table

3.3-2, Reference No. 3.3.2.21 of the LRA, the applicant concluded that there is no aging effect

on aluminum components of the air handlers heating/cooling system exposed to air, moisture,

and humidity environments. By letter dated August 4, 2003, the staff issued RAI 3.3-4

requesting explanations on why different conclusions on aging effects were arrived at in Table

3.3-2, Reference Nos. 3.3.2.21 and 3.3.2.126 for the same materiaVenvironment combination

and provide technical basis for not including loss of material due to crevice corrosion as an

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applicable aging effect. The staff's evaluation of the applicant's response is documented in

Section 3.3.2.5.4 of this SER.

By letter dated August 4, 2003, the staff requested, in RAI 3.3-7, the applicant to clarify which

specific AMP(s) is applicable for managing the AMR Item 3.3.1.5 specific corrosion mechanism,

and explain how the AMP(s) manages that corrosion mechanism for components in various

systems, including the carbon dioxide system. The staff's evaluation of the applicant's

response is documented in Section 3.3.2.5.7 of this SER.

LRA Table 2.3.3-28 includes filters/strainers with a filter function and references 3.3.1.19 in

Section 3.3. It appears that Reference No. 3.3.1.19 applies to fire protection rather than the

safe shutdown makeup pump system, and this reference does not indicate how the filter

function is managed. LRA Section 2.3.3.28 indicates that the evaluation boundary includes the

safe shutdown room cooler and its associated piping from the service water system (evaluated

with the service water system). By letter dated August 4, 2003, the staff issued RAI 3.3.2.4.28

requesting the applicant to clarify if the strainer screens in the safe shutdown makeup pump

system (such as the safe shutdown room cooler strainer) are evaluated with the service water

system in Table 3.3-1, Reference No. 3.3.1-15, which credits the B.1.13 AMP. If the

filters/strainers in the safe shutdown makeup pump system are not evaluated with the service

water system, the applicant was requested to clarify how the strainer screens are managed. If

the pump suction strainers (shown in boundary diagram LR-QDC-M-70) are temporary startup

strainers that are replaced by a spool piece once in operation, the applicant was requested to

so clarify. If these suction strainers are permanent, the applicant was requested to identify their

appropriate AMR reference.

In its response dated October 3, 2003, the applicant stated that the safe shutdown room cooler

strainer is not evaluated with the service water system. The applicant clarified that the strainer

is evaluated with the safe shutdown makeup pump system, which was scoped as a subsystem

of the fire protection system. The applicant identified that this strainer is cleaned on a monthly

basis and the cleaning requirements are defined in a station procedure. This response also

stated that the AMP associated with Aging Management Reference 3.3.1.19 is B.1.19, Fire

Water System, and is appropriately assigned to this strainer.

The applicant further stated that the section of piping labeled "A spool piece for inline strainer'

in the suction of the safe shutdown makeup pump is not a strainer. No additional aging

management reference is required for this spool piece.

The staff finds that the applicant's response adequate and acceptable because the applicant

has clarified that the safe shutdown room cooler strainer is evaluated with the safe shutdown

makeup pump system, which was scoped as a subsystem of the fire protection system and this

strainer is cleaned on a monthly basis.

The aging effects identified in the LRA for the safe shutdown makeup pump system are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible the aging effects were identified and that the aging effects listed

are appropriate for the combination of materials and environments specified.

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Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the safe shutdown makeup pump system.

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Bolting Integrity Program (Section 3.0.3.5)

* Open-Cycle Cooling Water System Program (Section 3.0.3.6)

* Fire Water System Program (Section 3.3.2.3.4)

* One-Time Inspection Program (Section 3.0.3.10)

* Structures Monitoring Program (Section 3.0.3.14)

Except for the Fire Water System Program, these AMPs are credited with managing the aging

effects on components in several structures and systems and, therefore, are considered

common AMPs. The staff has evaluated these common AMPs and found them to be

acceptable for managing the aging effects identified for this system. The staff's evaluation of

these AMPs is documented in Sections 3.0.3.2, 3.0.3.3, 3.0.3.5, 3.0.3.6, 3.0.3.10, and 3.0.3.14

of this SER. The Fire Water System Program is evaluated in Section 3.3.2.3.4 of this SER.

After evaluating the applicant's AMR for each of the components in the demineralized water

makeup system, the staff evaluated the AMPs listed above to determine if they are appropriate

for managing the identified aging effects. For those components identified in Table 3.3-1 of the

LRA, the staff verified that the applicant credited the AMPs recommended by the GALL Report.

For the components identified in LRA Table 3.3-2, the staff verified that the applicant credited

AMPs that are appropriate for the identified aging effects.

The response to RAI 3.3-7 clarified that AMPs B.1.12, Bolting Integrity Program, B.1.13, OpenCycle Cooling Water Program, and B.1.30, Structures Monitoring Program are to be used to

manage aging effects in the safe shutdown makeup pump system.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the

demineralized water makeup system will effectively manage or monitor the aging effects

identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.5 General Aging Management Review Issues

This section discusses the staff's evaluation of nine general AMR issues that are applicable to

components in several auxiliary systems included in Section 3.3 of the LRA.

3.3.2.5.1 Galvanic Corrosion

This general AMR issue concerns aging management of loss of material due to galvanic

corrosion in auxiliary systems. The concern is associated with components identified by the

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applicant in LRA Table 3.3-2 that are not addressed in GALL.

Metals and alloys that are in contact with different, more cathodic metals or alloys in the

presence of an electrolyte fluid may be subjected to the aging effect of loss of material from

galvanic corrosion. Many systems/components of the auxiliary systems described by various

items in Table 3.3-2 of the LRA have materials/environment combinations to which loss of

material from galvanic corrosion may be an applicable aging effect/mechanism. By letter dated

August 4, 2003, the staff requested, in RAI 3.3-1, the applicant to provide the technical basis,

including plant operating experience, for determining whether loss of material due to galvanic

corrosion is an applicable aging effect/mechanism for the applicable components included in

the auxiliary systems.

In its response dated October 3, 2003, the applicant stated that design and installation

techniques were utilized at Dresden and Quad Cities, including galvanic corrosion control

mechanisms. The applicant clarified that, following good industry practices for the design of

power plant piping systems and heat exchangers, materials that would be in electrical contact

were selected from groups as close as possible in the galvanic series. Further, the applicant

stated that wherever practical, dissimilar metals were electrically insulated by the use of

insulated flanges or dielectric unions, and coatings were applied in many cases to address

potential galvanic corrosion concerns. The applicant concluded that, in general, these

techniques have been successful in preventing occurrences of galvanic corrosion. The

applicant further stated that there have been a few occurrences of galvanic corrosion identified

in the operating experience history of Dresden and Quad Cities piping systems and heat

exchangers due to design errors, and that these problems have been resolved through design

modifications.

In its response, the applicant stated that LRA Appendix B, B.2.6, uHeat Exchanger Test and

Inspection Activities," manages the "loss of materials" aging effect for both the control room and

diesel generator building air handling units by performing periodic inspections. The applicant

further stated that corrosion would be detected during these periodic inspections, regardless of

the mechanism involved. The staff was concerned that different types of corrosion (pitting,

crevice, galvanic, etc.) may be prevalent in different susceptible locations and requested the

applicant to clarify that periodic inspections for both the control room and diesel generator

building air handling units are conducted on locations that include those susceptible to galvanic

corrosion. By letter dated December 22, 2003, the applicant responded by stating that

locations that are potentially susceptible to galvanic corrosion are the copper cooling coil

interfaces with the aluminum cooling fins, the locations where the copper tubing penetrates the

galvanized steel housing, and the galvanized steel tube support interfacing with the copper

cooling coils. The applicant stated that these locations are inspected as part of the periodic

visual inspections. The staff finds that the applicant's response is acceptable because the

applicant has specifically identified locations in the air handling units that are susceptible to

galvanic corrosion and that these locations are to be inspected as part of the periodic visual

inspections.

The staff also identified a concern that AMP B.2.6 does not appear to include the diesel

generator building air handling units and requested the applicant to address this concern. By

letter dated December 17, 2003, the applicant clarified that the response to RAI 3.3-1 should

have read, "The air handlers identified in Aging Management Reference 3.3.2.14 of LRA Table

3.3-2 are the Quad Cities Units 1 and 2 station blackout diesel generator battery room heat

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exchangers." The staff verified that these heat exchangers are included as components

managed by AMP B.2.6, "Heat Exchanger Test and Inspection Activities," and, therefore, this

concern is considered resolved. The staff considers all issues related to RAI 3.3-1 to be

closed.

On the basis of its review, the staff finds the applicant's response adequate and acceptable

because the applicant has demonstrated that (1) loss of material due to galvanic corrosion is

controlled by following good design and installation practices, (2) these techniques have been

successful in preventing the occurrence of galvanic corrosion, (3) the few occurrences of

galvanic corrosion in the Dresden and Quad Cities operating experience have been resolved

through design modifications that follow good design practices, and (4) appropriate AMPs, such

as B.2.6, are credited for managing galvanic corrosion in heat exchangers.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of loss of material due to galvanic corrosion. The staff finds that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.5.2 Corrosion Mechanisms and Sampling of One-Time Inspections

For HVAC-main control room system, shutdown cooling system, and control rod drive

hydraulic system, the applicant identified in AMR Reference No. 3.3.2.130 of Table 3.3-2 the

material environment combination and applicable aging effects on components of NSR vents or

drains, piping, and valves. The description in Reference No. 3.3.2.130 lists 'Loss of

materialcorrosion" as aging effect/mechanism for carbon steel, stainless steel, and brass or

bronze components in an environment of "Air, moisture, humidity and leaking fluid." However,

the LRA does not specifically identify which type of corrosion is responsible for the loss of

material. The type of corrosion is important because it determines the susceptible locations to

be inspected. For example, the appropriate susceptible locations for inspection for general,

crevice, galvanic, and pitting corrosion may not be the same. In addition, the staff noted that in

the One-Time Inspection AMP (B.1.23), which is credited with managing the aging effects on

these components, the applicant stated that this AMP will inspect a sample of the NSR vents or

drains, piping, and valves in the shutdown cooling system (Dresden only) and the control rod

drive hydraulic system for general, crevice, galvanic, and pitting corrosion. By letter dated

August 4, 2003, the staff requested, in RAI 3.3-2, the applicant to provide a specific description

of the types of corrosion responsible for the aging effect of loss of materials for the relevant

components and the criteria for selecting these samples including susceptible locations for

inspections.

In its response dated October 3, 2003, the applicant stated that the aging mechanism

description for Aging Management Reference 3.3.2.130 of LRA Table 3.3-2 should have been

"General, pitting, and crevice corrosion," and the inspections to be performed as part of the

One-Time Inspection Program B.1.23 will include the appropriate inspection information. The

applicant also provided criteria used for selection of susceptible inspection locations. The

staff's evaluation of these criteria is discussed in Section 3.0.3.10 of this SER.

On the basis of its review, the staff finds the applicant's response to RAI 3.3.2 acceptable

because (1) it appropriately identified the aging mechanisms for the loss of materials due to

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corrosion, including its associated AMP, and (2) the staff found AMP B.1.23 to be acceptable as

described in Section 3.0.3.10 of this SER.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of corrosion mechanisms and sampling of one-time inspections. The

applicant's AMR results are otherwise consistent with the GALL report, the staff finds that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.5.3 Corrosion on Carbon Steel, Stainless Steel, Brass, and Bronze

Carbon steel and stainless steel components exposed to moist gas (moist nitrogen) or moist air

environment may experience aging effects of loss of material due to general (for carbon steel

only), pitting, and crevice corrosion (for both carbon steel and stainless steel) when pollutants

such as oxygen, SO2, NON, or CO are present in the moist air, particularly when the humidity is

greater than 60 percent. However, in Table 3.3-2, Reference No. 3.3.2.27 (for carbon steel),

and Reference No. 3.3.2.40 (for stainless steel) of the LRA, the applicant concluded that no

aging effects were identified for the external surfaces of the carbon steel and stainless steel

piping and fittings, accumulators, dampeners, filters/strainers, flow elements, pumps, orifices,

rupture discs, tanks, tubing, and valves components exposed to either the containment nitrogen

gas environment or air, moisture, humidity environment because these components "are not

subject to any viable aging mechanism in the absence of aggressive chemical species." In

addition, the LRA does not identify any aging effect for stainless steel, brass or bronze

components in "the air, moisture, and humidity < 1000C environment" for components in the

containment atmosphere monitoring system. The staff noted that the LRA identifies stainless

steel components in apparently similar environments (such as warm, moist air, wet gas, and

moist containment atmosphere in items Reference Nos. 3.3.2.166, 3.3.2.299, 3.3.2.195) as

being subjected to loss of materials from pitting and crevice corrosion.

By letter dated August 4, 2003, the staff requested, in RAI 3.3-3, the applicant to clarify whether

the pollutants, such as oxygen, NOR, SO2, or CO, are present and if so, to what extent in the

containment gas or air, moisture, humidity environments to justify the conclusions in Table

3.3-2, items Reference Nos. 3.3.2.27 and 3.3.2.40. In addition, the staff requested the

applicant to clarify why the LRA identifies stainless steel components in apparently similar

environments (such as warm, moist air, wet gas, and moist containment atmosphere in items

Reference Nos. 3.3.2.166, 3.3.2.299, 3.3.2.195) as being subjected to loss of materials from

pitting and crevice corrosion.

In its response dated October 3, 2003, the applicant stated that AMR Reference 3.3.2.27 of

LRA Table 3.3-2 is for the external surfaces of carbon steel components in containment

nitrogen environments. The conclusion in Aging Management Reference 3.3.2.27 that there

was no aging effect for carbon steel components exposed to containment nitrogen

environments was based on information provided in Appendix E of Non-Class 1 Mechanical

Implementation Guideline and Mechanical Tools, Revision 3, EPRI 1003056 regarding external

surfaces. EPRI 1003056 does not identify any applicable aging mechanisms for carbon steel in

a nonaggressive environment. A review of Dresden and Quad Cities operating experience was

conducted as part of the AMR for external surfaces. No site operating experience involving

age-related degradation of the external surfaces of carbon steel components in nitrogen

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environments was identified.

Aging Management Reference 3.3.2.40 of LRA Table 3.3-2 is for the external surfaces of

stainless steel components in indoor (sheltered) environments. The-conclusion in Aging

Management Reference 3.3.2.40 that there was no aging effect for stainless steel components

exposed to air, moisture, and humidity less than 100 0C (212 0F) was also based on

information provided in EPRI 1003056, Appendix E, regarding external surfaces. EPRI

1003056 does not identify any applicable aging mechanisms for stainless steel in the absence

of aggressive chemical species. No site operating experience involving age-related

degradation of the external surfaces of stainless steel components in indoor (sheltered)

environments was identified for Dresden or Quad Cities.

In the same letter, the applicant stated that pollutants in the form of oxygen, NOR, SO2, or CO

are present in the containment gas and air, moisture, humidity environments at minimal levels.

The nitrogen concentration of the containment gas environment is controlled, monitored, and

maintained at above 96 percent. The air, moisture, humidity environment is for areas that are

controlled indoor (sheltered) environments. EPRI 1003056, Appendix E, assumes that the level

of contaminants in external environments cannot be concentrated to levels that will promote

corrosion unless subjected to factors such as cyclic (wet-dry) condensation, contaminated

insulation, accidental contamination, or leakage. Neither of the environments associated with

Aging Management References 3.3.2.27 and 3.3.2.40 of LRA Table 3.3-2 are subjected to

these factors. However, LRA Table 3.3-2 does include items addressing materials in

aggressive environments. For example, Aging Management Reference 3.3.2.26, which

involves external surfaces of carbon steel components in air, moisture, humidity, and leaking

fluid environments, identifies loss of material due to general, pitting, and crevice corrosion as

applicable aging effects/mechanisms. The staff identified that EPRI Report 1003056, Appendix

E also indicates that copper and copper alloys are only susceptible to crevice, pitting, and

selective leaching if exposed to an aggressive environment. For aggressive environments,

AMP B.1.23 is credited for managing crevice and pitting corrosion and AMP B.1.24 is credited

for managing selective leaching in copper and copper alloys.

The staff reviewed the applicant's response to the issues raised in RAI 3.3-3. On the basis of

its review, the staff finds the applicant's response acceptable because (1) the applicant assured

that pollutants in the form of oxygen, NO., S02, or CO are present in the containment gas and

air, moisture, humidity environments at minimal levels, (2) the applicant has properly clarified

that both of the environments associated with Aging Management References 3.3.2.27 and

3.3.2.40 of LRA Table 3.3-2 conform to the assumptions in the EPRI 1003056, Appendix E (i.e.,

the level of contaminants in external environments cannot be concentrated to levels that will

promote corrosion unless subjected to factors such as cyclic (wet-dry) condensation,

contaminated insulation, accidental contamination, or leakage), and (3) the applicant verified

that there is no site operating experience involving age-related degradation of the external

surfaces of carbon steel components in nitrogen environments or stainless steel components in

indoor (sheltered) environments for Dresden or Quad Cities.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of corrosion on carbon steel, stainless steel, brass, and bronze. The

staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.3.2.5.4 Corrosion of Aluminum and Aluminum Alloys

Aluminum and aluminum alloy components may experience general, pitting, and crevice

corrosion when exposed to moisture and humidity environments, especially with the presence

of contaminants and water (condensation from moist air). However, AMR Reference No.

3.3.2.126 of Table 3.3-2 of the LRA, only identifies loss of material due to general and pitting

corrosion as plausible aging effects for aluminum components exposed to moist air. In Table

3.3-2, Ref No 3.3.2.21 of the LRA, the applicant concluded that there is no aging effect on

aluminum components of the air handlers heating/cooling system exposed to air, moisture, and

humidity environments.

By RAI 3.3-4, the staff asked the applicant to (1) explain the different conclusions on aging

effects described above, (2) provide the technical basis for not including loss of material due to

crevice corrosion as an applicable aging effect, and (3) clarify if there is any condensate on the

aluminum fins of cooling coils.

In its response dated October 3, 2003, the applicant stated that the difference between the

conclusions made in Aging Management References 3.3.2.126 and 3.3.2.21 of LRA Table 3.3-

2 is that Aging Management Reference 3.3.2.126 involves component internal surfaces and

Aging Management Reference 3.3.2.21 involves component external surfaces in indoor

(sheltered) environments.

Regarding whether crevice corrosion is a plausible aging effect on aluminum exposed to moist

air, in its response dated October 3, 2003, the applicant stated that the aging mechanisms

associated with Aging Management Reference 3.3.2.126 were derived from information

provided in Chapter 20 of Uhlig's Corrosion Handbook, 21 Edition. This source did not identify

crevice corrosion as a viable aging mechanism for internal surfaces of aluminum and aluminum

alloy components in moisture and humidity environments. Therefore, crevice corrosion was

excluded as a viable aging mechanism for this item.

Pertaining to the issue on whether there is any condensate on the aluminum fins of cooling coils

and the technical basis for conclusion in Table 3.3-2, Reference No. 3.3.2.21 of the LRA, in its

response dated October 3, 2003, the applicant stated that the external surfaces of aluminum

fins of cooling coils are exposed to condensate. The conclusion in Aging Management

Reference 3.3.2.21 that there was no aging effect on aluminum components of air handler

heating cooling systems exposed to air, moisture, and humidity environments was based on

information provided in Appendix E of Non-Class 1 Mechanical Implementation Guideline and

Mechanical Tools, Revision 3, EPRI 1003056, regarding external surfaces. EPRI 1003056

does not identify any applicable aging mechanisms for aluminum alloys in a nonaggressive

environment. The subject aluminum components are not exposed to an aggressive

environment. Furthermore, although aluminum is a reactive metal, it develops an aluminum

oxide film that protects it from further corrosion. Therefore, no viable aging effect exists in an

indoor environment with variable humidity and temperature less than 100 'C (212 'F) for this

item. The applicant stated that a review of Dresden and Quad Cities operating experience was

conducted as part of the AMR for external surfaces and no operating experience involving agerelated degradation of the external surfaces of aluminum fins in air, moisture, and humidity

environments was identified.

The staff reviewed the applicant's response to the issues raised in RAI 3.3.4. On the basis of

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its review, the staff finds the applicant's response acceptable because (1) the applicant

provided information on the differences between the environments in Reference Nos. 3.3.2.126

and 3.3.2.21 of the LRA, (2) the applicant asserted that the environment the aluminum alloy

components were exposed to is not an aggressive environment and satisfies the conditions

assumed in EPRI 1003056, Appendix E, Section 4.1, and (3) no operating experience involving

age-related degradation of the external surfaces of aluminum fins in air, moisture, and humidity

environments was identified.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of corrosion of aluminum and aluminum alloys. The staff finds that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.5.5 Stress-Corrosion Cracking

In LRA Table 3.3-2, Ref No 3.3.2.18, the applicant stated that high-strength, low-alloy steel

closure bolting components in the outdoor ambient conditions are subject to aging effects of

loss of material due to general corrosion and wear. However, the applicant did not include

crack initiation and growth due to SCC or other mechanisms as applicable aging

effects/mechanisms. By letter dated August 4, 2003, the staff requested, in RAI 3.3-5, the

applicant to provide the technical basis for not including crack initiation and growth due to SCC

as applicable aging effects/mechanisms for high-strength, low-alloy steel closure bolting

components in the outdoor ambient conditions.

In its response dated October 3, 2003, the applicant stated that for closure bolting in the highpressure or high-temperature portions of systems, the applicable aging effect is crack initiation

and growth due to SCC. The bolts associated with LRA Table 3.3-2, Aging Management

Reference 3.3.2.18, are on the portion of piping with low pressure and low temperature, which

are not subject to cyclic loading.

The applicant further stated that EPRI 1003056, Non-Class 1 Mechanical Implementation

Guideline and Mechanical Tools, Revision 3, Appendix F, Closure bolting, states that "stress

corrosion cracking is not an applicable aging effect for bolting material with a tensile strength of

less than 150 ksi." The bolts used are ASTM Al 93 Grade B7 with a tensile strength of 125 ksi.

EPRI 1003056 states, "The use of appropriate materials (such as ASTM Al 93, Gr. B7) for

bolting also reduces the potential for SCC of fasteners by maintaining fastener minimum yield

strengths below threshold values found in ['Degradation and Failure of Bolting in Nuclear Power

Plants," EPRI NP-5796]."

The applicant concluded that for bolting in the low-pressure or low-temperature portion of the

system (in the outdoor ambient condition), loss of material due to general corrosion or wear is

the only applicable aging effect and is covered by LRA Table 3.3-2, Aging Management

Reference 3.3.2.18.

On the basis of its review, the staff concurs with the applicant's assertion that for bolting in the

low-pressure, low-temperature portion of the system (in the outdoor ambient condition), which is

not subject to cyclic loading, SCC is not an applicable aging effect; therefore, the staff finds

this acceptable.

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On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of SCC. The staff finds that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.3.2.5.6 General, Pitting, and Crevice Corrosion on Carbon Steel Components Exposed to

Chemically Treated Demineralized Water

Loss of material due to general, pitting, and crevice corrosion may be an applicable aging effect

on carbon steel components exposed to chemically treated demineralized water. However, in

several AMR references, the applicant identified crack initiation and growth due to SCC and

IGSCC as the applicable aging effects/mechanisms instead of loss of material due to general,

pitting, and crevice corrosion. By letter dated August 4, 2003, the staff requested, in RAI 3.3-6,

the applicant to provide clarification.

In its response dated October 3, 2003, the applicant clarified that the loss of material due to

general, pitting, and crevice corrosion is addressed through AMR Reference 3.3.1.13, since this

AERM is covered by the GALL Report. The AMR references in question address crack

initiation growth of carbon steel in a nitrite-based chemically treated water environment. EPRI

1003056, Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Revision 3,

identifies this as an applicable aging effect/mechanism. The GALL does not address this

environment; therefore, the applicant included additional AMR references in LRA Table 3.3-2.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of general, pitting, and crevice corrosion on carbon steel components

exposed to chemically treated demineralized water. The staff finds that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

3.3.2.5.7 Detailed Breakdown on the Aging Management Programs for Loss of Material Due to

General, Pitting, and Crevice Corrosion, and MIC

For various in-scope components of the auxiliary systems, the applicant uses Reference No.

3.3.1.5 of Table 3.3-1 to describe the aging management of these components. Reference No.

3.3.1.5 refers to Section 3.3.1.1.7 of the LRA for further evaluation of loss of material due to

general, microbiologically influenced, pitting, and crevice corrosion. This section also describes

the AMPs that will be used to manage the above AERM for the various components; however,

the staff noted that the descriptions in Section 3.3.1.1.7 of the LRA of how AMPs would

manage the aging effects were not always consistent with the LRA description of the AMPs.

The staff also noted that the LRA did not provide sufficient information on which corrosion

mechanisms were applicable to the various equipment, or how the AMPs were adequate for

these particular mechanisms. By letter dated August 4, 2003, the staff requested, in RAI 3.3-7,

the applicant to clarify which specific AMP(s) is applicable for managing the AMR item 3.3.1.5

specific corrosion mechanism, and explain how the AMP(s) manage that corrosion mechanism

for components in various auxiliary systems.

In its response dated October 3, 2003, the applicant explained this aging management will be

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evaluated using several AMPs, as follows:

Bolting Integrity Program (B.1.12): This program includes routine system walkdowns that

manage system component external surfaces. These walkdowns check both the general

external surface condition of the system components and also the leakage integrity of the

components and bolted joints.

Structures Monitoring Program (B.1.30): This program uses a spaces approach, which

inspects a sampling of piping and component supports and the adjacent exposed piping and

component surfaces. This sampling provides confirmation that external surface aging

degradation of like materials in like environments are not occurring.

One-Time Inspection Program-Compressed Gas (B.1.23): This program uses VT-3 visual

inspections on a sample of components that represent or bound the piping system components

within the scope of license renewal to verify that there is no unacceptable loss of material in the

compressed gas systems.

Heat Exchanger Testing and Inspection Program (B.2.6): This program provides condition

monitoring, inspection, and performance testing activities to manage the aging effects of loss of

material, cracking, and buildup of deposits in heat exchangers.

One-Time Inspection Program-Ventilation System (B.1.23): This program uses VT-3 visual

inspections of a representative sample of ventilation system ductwork, equipment frames and

housings, valves, debris screens, access doors, and closure bolting to confirm that there is no

penetrating corrosion, which could indicate an unacceptable loss of material condition. Drip

pan drain piping will be inspected for corrosion that could result in a pipe wall perforation.

Open-Cycle Cooling Water Program (B.1.13): This program uses visual and NDE inspection of

components for detection of degradation and corrosion coupons for determining general

corrosion rates. This program also uses performance testing for flow rates, temperatures, and

pressures, and visual inspections for fouling and silting.

Buried Piping and Tanks Inspection Program (B.1.25): This program manages loss of material

(general, pitting, crevice, and MIC) through the use of piping and component coatings and

wrappings, periodic inspections, and pressure testing. The condition of the coatings, which

provide a mitigative function, is inspected whenever buried components are uncovered during

station excavation activities. Since this could be infrequent, additional periodic leak testing and

component inspections are being credited. These include ISI leakage testing for buried Class 3

piping, operational pressure monitoring for buried fire protection piping, periodic fuel oil storage

tank inspections, "one-time" UTs of the buried fuel oil storage tank internals and the internal

bottom surface of an outdoor aluminum tank (such as a CCST), and a "one-time" inspection of

buried piping.

Fire Protection Program (B.1.18): This program provides for managing the effects of aging of

the external piping and component surfaces of the station halon (Dresden only) and cardox

systems (both stations). The program is based on NFPA 12A and 72E standards and provides

for periodic system operability testing. While performing the operability testing, it is

recommended that visual aging degradation inspections also be performed.

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One-Time Inspection Program-NSRISR Inspection (B.1.23): This program uses a visual

inspection of a representative sample of component material-environment upairs" for the

presence of general, crevice, galvanic, and pitting corrosion to provide assurance that corrosion

of system components is not occurring or is occurring at an acceptable rate.

The staff's evaluation of these programs appears in the following sections of this SER:

* Bolting Integrity Program (Section 3.0.3.5)

* Structures Monitoring Program (Section 3.0.3.14)

* One-Time Inspection Program (Section 3.0.3.10)

* Heat Exchanger Testing and Inspection Program (Section 3.0.3.16)

* Open-Cycle Cooling Water Program (Section 3.0.3.6)

* Buried Piping and Tanks Inspection Program (Section 3.0.3.12)

* Fire Protection Program (Section 3.3.2.3.3)

The applicant's response dated October 3, 2003, also provided minor revisions and/or

clarifications of the system-specific AMR related to loss of material due to general, pitting, and

crevice corrosion, and MIC. These revisions/clarifications are addressed in the applicable

system writeups in Sections 3.3.2.4.1 to 3.3.2.4.28 of this SER.

The staff finds that the applicant's response to RAI 3.3-7 is acceptable because it has clarified

the management of loss of material due to general, pitting, and crevice corrosion, and MIC for

auxiliary system components.

On the basis of its review, the staff concludes that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.3.2.5.8 Verification of Water Chemistry Program

For several AMR items, LRA was not clear whether the applicant was verifying the

effectiveness of the Water Chemistry Program. By letter dated August 4, 2003, the staff

requested, in RAI 3.3-8, the applicant to clarify whether a one-time inspection should be

performed for these components to verify the effectiveness of the chemistry program. In its

responses to the staff's RAI, the applicant clarified the aging management of the components

and/or justified why inspections were not needed.

In its October 3, 2003, letter, the applicant stated that for AMR Item 3.3.2.120, the component

group "heat exchanger" also credits the Open-Cycle Cooling Water Program. The activities in

this AMP involve chemistry control, performance monitoring, periodic inspections, and periodic

flushing in order to control biofouling, verify heat transfer, monitor degradation, and to ensure

compliance with the CLB for affected heat exchangers. Performance monitoring, periodic

inspections, and flushing will verify the effectiveness of the chemistry program to ensure that

significant degradation is not occurring and the component intended function would be

maintained. The staff finds this acceptable because the Open-Cycle Cooling Water Program

activities will verify the effectiveness of the Water Chemistry Program.

For AMR Item 3.3.2.186, the applicant's October 3, 2003, letter noted that GALL Program

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Section XI.M2, 'Water Chemistry Program," states that the Water Chemistry Program is

effective in removing impurities from intermediate and high-flow areas. It also states that the

Water Chemistry Program may not be effective in low-flow or stagnant-flow areas. In low-flow

or stagnant-flow areas, verification of the effectiveness of the chemistry program is undertaken

to ensure that significant degradation is not occurring and the component intended function will

be maintained. In addition, the applicant stated that the component group "flow orifices" is not

typically in low-flow or stagnant areas. The applicant, therefore, concluded that verification of

the effectiveness of the chemistry program through a one-time inspection, B.1.23, is not

required. The staff was concerned that the term "typically" was not definitive and requested the

applicant to clarify whether any restricting orifices are in low-flow or stagnant flow-areas and to

discuss why a One-Time Inspection Program is-not needed to verify the effectiveness of the

Water Chemistry Program for these restricting orifices.

The applicant's response dated December 17, 2003, stated that the review of Item 3.3.2.186

determined that this component was inadvertently included and will be removed from the LRA

scope. The response also stated that the clean demineralized water and makeup

demineralized water systems did not identify any restricting orifices that are in a low-flow or

stagnant-flow area based on the system function. The applicant added that AMR references

3.3.2.72 and 3.3.2.188 will be managed with one-time inspection to verify the effectiveness of

the chemistry program. The staff finds that the applicant's response is acceptable because the

inspection will verify the effectiveness of the chemistry program. The staff considers all issues

related to RAI 3.3-8 to be closed.

For AMR Item 3.3.2.257, the applicant's October 3, 2003, letter stated that the components are

brass or bronze valves in clean demineralized water hose stations that are in scope of license

renewal for spatial interaction component intended function. The applicant stated that one-time

inspections are performed for carbon and stainless steel components to verify the effectiveness

of the chemistry program, and indicated that these would be leading indicators of the loss of

material in the brass and bronze valves. The staff agrees that inspections of the carbon and

stainless steel components would provide a leading indicator; therefore, the staff agrees that

inspections of the brass or bronze valves are not required to verify the effectiveness of the

Water Chemistry Program.

On the basis of its review, the staff finds the applicant's response adequate and acceptable

because the inspections and activities described above will verify the effectiveness of the Water

Chemistry AMP in preventing the identified aging effects.

3.3.2.5.9 Aging Management of Nonbolting Components Using Bolting Integrity Program

The applicant uses the Bolting Integrity Program (B.1.12) to manage general corrosion on

external surfaces of many auxiliary system nonbolting components. The staff notes that the

Bolting Integrity Program description states, "The program consists of visual inspections for

external surface degradation that may be caused by loss of material or cracking of the bolting,

or by an adverse environment," suggesting that only the bolting material will be inspected for

aging degradation. By letter dated August 4, 2003, the staff requested, in RAI 3.3-9, the

applicant to explain (including the acceptance criteria and inspection interval) how the Bolting

Integrity Program is used to manage general corrosion on external surfaces of nonbolting

components, such as piping, valves, mufflers, and others.

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In its response dated October 3, 2003, the applicant stated that Chapter Xl of NUREG-1 801,

Generic Aging Lessons Learned, does not contain any program to monitor the effects of aging

for the exterior surface of auxiliary system components. As such, Exelon made the decision to

include the aging management for nonbolting components, such as piping, valves, and

mufflers, within the Bolting Integrity Program. The Bolting Integrity Program (B.1.12) consists

of visual inspections, which rely on detection of visible leakage during preventive maintenance

and routine walkdowns (routine observation activities). The routine walkdowns are also

credited for detecting aging degradation (general corrosion) on the external surfaces of system

piping and piping components. Finally, the applicant stated that depending on the accessibility

of the systems or components, walkdown inspection intervals vary from quarterly to every

refueling outage, and the presence of component external surface corrosion requires

engineering evaluation.

The staff finds that the applicant has adequately explained how the Bolting Integrity Program is

used to manage general external corrosion for auxiliary system components. The staff's

evaluation of the Bolting Integrity Program is presented in Section 3.0.3.5 of this SER.

On the basis of its review, the staff concludes that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

3.4 Steam and Power Conversion Systems

This section addresses the aging management of the components of the steam and power

conversion systems (SPCS) group. The systems that make up the SPCS group are described

in the following SER sections:

* main steam system (Section 2.3.4.1)

* feedwater system (Section 2.3.4.2)

* condensate and condensate storage systems (Section 2.3.4.3)

* main condenser (Section 2.3.4.4)

* main turbine and auxiliary systems (Section 2.3.4.5)

* turbine oil system (Quad Cities only, Section 2.3.4.6)

* main generator and auxiliary system (Quad Cities only, Section 2.3.4.7)

As discussed in Section 3.0.1 of this SER, the components in the SPCS are described in

several LRA tables. LRA Table 3.4-1 discusses the treatment of SPCS components that are

evaluated in the GALL Report. LRA Tables 3.1-1 and 3.2-1 discuss the treatment of

components that the GALL Report evaluates as part of the RCS and ESF systems groups,

respectively; however, several of these components are scoped under SPCS at Dresden and

Quad Cities (these components are evaluated in Sections 3.1 and 3.2 of this SER,

respectively). LRA Tables 2.3.4-1 through 2.3.4-7 show all of the components in each system,

regardless of whether they are addressed in the GALL Report. For those system components

that are addressed in the GALL Report, LRA Tables 2.3.4-1 through 2.3.4-7 refer to LRA

Tables 3.1-1, 3.2-1, or 3.4-1 for additional information.

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3.4.1 Summary of Technical Information In the Application

In LRA Section 3.4, the applicant described its AMRs for the SPCS.

The description of the systems that comprise the SPCS group can be found in Section 2.3.4 of

the LRA.

The passive, long-lived components in these systems that are subject to an AMR are identified

in LRA Tables 2.3.4-1 through 2.3.4-7.

The applicant's AMRs included an evaluation of plant-specific and industry operating

experience. The plant-specific evaluation included reviews of condition reports and discussions

with appropriate site personnel to identify aging effects that require management. These

reviews concluded that the aging effects requiring management based on the plant's operating

experience were consistent with aging effects identified in GALL.

The applicant's review of industry operating experience included a review of operating

experience through 2002. The results of this review concluded that aging effects requiring

management based on industry operating experience were consistent with aging effects

identified in GALL.

The applicant's ongoing review of plant-specific and industry-wide operating experience is

conducted in accordance with Exelon's Operating Experience Program.

3.4.2 Staff Evaluation

In Section 3.4 of the LRA, the applicant described its AMR for the SPCS. The staff reviewed

Section 3.4 to determine whether the applicant has provided sufficient information to

demonstrate that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB throughout the period of extended

operation, in accordance with the requirements of 10 CFR 54.21 (a)(3), for the SPCS

components that are determined to be within the scope of license renewal and subject to an

AMR.

The applicant referenced the GALL Report in its AMR. The staff has previously evaluated the

adequacy of the aging management of SPCS components for license renewal as documented

in the GALL Report. Thus, the staff did not repeat its review of the matters described in the

GALL Report, except to ensure that the material presented in the LRA was applicable and to

verify that the applicant had identified the appropriate programs as described and evaluated in

the GALL Report. The staff evaluated those aging management issues recommended for

further evaluation in the GALL Report. The staff also reviewed aging management information

submitted by the applicant that was different from that in the GALL Report or was not

addressed in the GALL Report. Finally, the staff reviewed the UFSAR Supplement to ensure

that it provided an adequate description of the programs credited with managing aging for the

SPCS components.

In LRA Section 3.4, the applicant provided brief descriptions of the SPCS and summarized the

results of its AMR of the SPCS.

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Table 3.4-1 below provides a summary of the staff's evaluation of components, aging

effects/mechanisms, and AMPs listed in LRA Section 3.4 that are addressed in the GALL

Report.

Table 3.4-1 Summary of Aging Management Programs for Steam and Power Conversion

Systems Evaluated in Chapter VII of the GALL Report

Aging Effect/

Component Group Mechanism AMP in GALL Report AMP in LRA Staff Evaluation

Piping and fittings in Cumulative fatigue TLAA, evaluated in TLAA Consistent with GALL

main feedwater line, damage accordance with GALL recommends

steam line and AFW 10 CFR 54.21(c) further evaluation (see

piping (PWR only) 3.4.2.2.1 below).

Piping and fittings, Loss of material due to Water Chemistry and Water Consistent with GALL

valve bodies and general (carbon steel One-Time Inspection Chemistry with exceptions. GALL

bonnets, pump only), pitting, and (B.1.2), and recommends further

casing, tanks, tubes, crevice corrosion One-Time evaluation (see Section

tubesheets, channel Inspection 3.4.2.2.2 below).

head and shell (B.1.23)

(except main steam Programs

system)

Extemal surface of Loss of material due to Plant specific Water Consistent with GALL

carbon steel general corrosion Chemistry with exceptions. GALL

components (B.1.2) and recommends further

One-Time evaluation (see

Inspection Section 3.4.2.2.4

(B.1.23) below).

Programs

Carbon steel piping Wall thinning due to Flow-Accelerated Flow- Consistent with GALL

and valve bodies flow-accelerated Corrosion Accelerated with exceptions (see

corrosion Corrosion Section 3.4.2.1 below).

Program

(B.1.11)

Carbon steel piping Loss of material due to Water Chemistry Water Consistent with GALL

and valve bodies in pitting and crevice Chemistry with exceptions (see

main steam system corrosion Program (B.1.2) Section 3.4.2.1 below).

Closure bolting in Loss of material due to Bolting Integrity Bolting Integrity Consistent with GALL

high-pressure or general corrosion; (B.1.12) with exceptions (see

high-temperature crack initiation and Section 3.4.2.1 below).

systems growth due to cyclic

loading and/or SCC

Heat exchangers and Loss of material due to Open-Cycle Cooling Not applicable The components

coolers/condensers general (carbon steel Water System identified in GALL are

serviced by open- only), pitting, and not within the scope of

cycle cooling water crevice corrosion, license renewal.

MIC, and biofouling;

buildup of deposit due

to biofouling

Heat exchangers and Loss of material due to Closed-Cycle Cooling Not applicable The components

cooler/ condensers general (carbon steel Water System identified in GALL are

serviced by closed- only), pitting, and not within the scope of

cycle cooling water crevice corrosion license renewal.

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Aging Effect!

Component Group Mechanism AMP In GALL Report AMP In LRA Staff EvaluatIon

External surface of Loss of material due to Aboveground Carbon Not applicable The GALL specifies

aboveground general (carbon steel Steel Tanks carbon steel, however,

condensate storage only), pitting, and Dresden and Quad

tank crevice corrosion Cities have tanks

constructed of

aluminum.

External surface of Loss of material due to Buried Piping and Not applicable The components

buried condensate general, pitting, and Tanks Surveillance Identified in GALL are

storage tank and crevice corrosion and or not applicable.

AFW piping MIC Buried Piping and

Tanks Inspection

The staff's review of the SPCS for the Dresden and Quad Cities LRA is contained within four

sections of this SER. Section 3.4.2.1 is the staff review of components in the SPCS that the

applicant indicates are consistent with GALL and do not require further evaluation. Section

3.4.2.2 is the staff review of components in the SPCS that the applicant indicates are consistent

with GALL and GALL recommends further evaluation. Section 3.4.2.3 is the staff evaluation of

AMPs that are specific to the SPCS systems group. Section 3.4.2.4 contains an evaluation of

the adequacy of aging management for components in each system in the SPCS group and

includes an evaluation of components in the SPCS that the applicant indicates are not in GALL.

3.4.2.1 Aging Management Evaluations in the GALL Report That Are Relied on for License

Renewal, Which Do Not Require Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL does not recommend further evaluation, the staff sampled

components in these groups to determine whether the plant-specific components contained in

these GALL component groups were bounded by the GALL evaluation. The staff also sampled

component groups to determine whether the applicant had properly identified those component

groups in GALL that were not applicable to its plants. The staff also identified several areas

where additional information or clarification was needed.

On the basis of its review, the staff has verified the applicant's claim of consistency with the

GALL report. The staff finds that the applicant has demonstrated that the effects of aging will

be adequately managed so that the intended functions will be maintained consistent with the

CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.2 Aging Management Evaluations in the GALL Report That Are Relied on for License

Renewal, for Which GALL Recommends Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL recommends further evaluation, the staff reviewed the applicant's

evaluation to determine whether it adequately addressed the issues for which GALL

recommended further evaluation. In addition, the staff sampled components in these groups to

determine whether the plant-specific components contained in these GALL component groups

were bounded by the GALL evaluation.

The GALL Report indicates that further evaluation should be performed for the aging effects

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discussed in the following sections.

3.4.2.2.1 Cumulative Fatigue Damage

Fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in

accordance with 10 CFR 54.21 (c)(1). The applicant discussed this TLAA in LRA Section

4.3.3.2, "Reactor Coolant Pressure Boundary Piping and Components Designed to USAS

B31.1, ASME Section III Class 2 and 3, or ASME Section Vil Class B and C." The staff

reviewed the evaluation of this TLAA in Section 4.3 of this SER.

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

The SRP recommends further evaluation of programs to manage loss of material due to

general, pitting, and crevice corrosion of carbon steel piping and fittings, valve bodies and

bonnets, pump casings, pump suction and discharge lines, tanks, tubesheets, channel heads,

and shells (except for main steam system components), and for loss of material due to crevice

and pitting corrosion for stainless steel tanks and heat exchanger/cooler tubes to verify the

effectiveness of the Water Chemistry Program. The SRP states that an acceptable verification

program consistent of a one-time inspection of select components and susceptible locations in

the system. The GALL Water Chemistry Program relies on monitoring and control of water

chemistry, based on the guidelines in BWRVIP-29 (EPRI TR-1 03515) for water chemistry in

BWRs, to manage the effect of loss of material due to general, pitting, or crevice corrosion.

However, corrosion may occur at locations of stagnant flow conditions. Therefore, the GALL

Report recommends that the effectiveness of the Chemistry Control Program be verified to

ensure that corrosion is not occurring.

The staff reviewed the applicant's proposed program to ensure that corrosion is not occurring

and that the component intended function will be maintained during the period of extended

operation. If the applicant proposed a one-time inspection of select components and

susceptible locations to ensure that corrosion is not occurring, the staff verified that the

applicant's selection of susceptible locations is based on severity of conditions, time of service,

and lowest design margin. The staff also verified that the proposed inspection would be

performed using techniques similar to ASME Code and ASTM standards.

Section 3.4.1.1.2 of the LRA states that an inspection of selected components exposed to a

stagnant flow water environment will be conducted in accordance with the One-Time Inspection

Program (B. 1.23) to verify that significant degradation is not occurring and the component

intended function will be maintained during the extended period of operation. The LRA states

that examinations will be conducted on carbon and stainless steel components in an area

where typically stagnant flow is present but occasionally there is flow, which will cause

replenishment of the oxygen supply. Specifically, inspections will be conducted on the HPCI

torus suction check valves, the HPCI booster pumps, and the CRD scram valves. The carbon

steel HPCI torus suction check valves are exposed to torus water and will undergo a visual

exam followed by an ultrasonic exam if significant corrosion is observed, while the carbon steel

HPCI booster pumps and the stainless steel CRD scram valves are exposed to condensate

storage tank water and will undergo a visual examination. The applicant concluded that these

components provide representative samples of the aging effects seen in SPCS.

The staff concurs with the applicant's approach of using the One-Time Inspection Program to

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sample similar materials and environments to provide representative samples for the SPCS

components. The staff's review of the One-Time Inspection Program is in Section 3.0.3.10 of

this SER.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of loss of material due to general, pitting, and crevice corrosion, as

recommended in the GALL report. Since the applicant's AMR results are otherwise consistent

with the GALL report, the staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.2.3 Loss of Material Due to General Corrosion

The GALL Report recommends further evaluation of programs to manage loss of material due

to general corrosion for external surfaces of all carbon steel structures and components,

including closure bolting, exposed to operating temperatures less than 212 'F. Such corrosion

may be due to air, moisture, or humidity. The staff reviewed the applicant's proposed program

to ensure that an adequate program will be in place for the management of this aging effect.

Section 3.4.1.1.3 of the LRA states that aging management of the external surface of the main

steam, feedwater, condensate, and condensate storage system components in a sheltered

environment with moist, warm air will be managed either by the Structures Monitoring Program

(B.1.30) or by system engineer walkdowns performed by the Bolting Integrity Program (B.1.12)

aging management activities. The staff's review of these programs is in Section 3.0.3.14 and

3.0.3.5 of this SER, respectively.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of loss of material due to general corrosion, as recommended in the

GALL report. Since the applicant's AMR results are otherwise consistent with the GALL report,

the staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.3 Aging Management Program for the Steam and Power Conversion System

Components

The applicant credits nine AMPs to manage the aging effects associated with components in

the SPCS group. Of the nine, all but one of the AMPs are credited with managing aging for

components in other system groups (common AMPs). The staff's evaluation of the common

AMPs is provided in Section 3.0.3 of this SER. The common AMPs credited with managing

aging for SPCS components are listed below along with the corresponding SER section

numbers.

* ASME Section Xl Inservice Inspection Program, Subsection IWB, IWC, & IWD (Section

3.0.3.1)

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

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I

* Compressed Air Monitoring Program (Section 3.0.3.8)

* One-Time Inspection Program (Section 3.0.3.10)

* Structures Monitoring Program (Section 3.0.3.14)

The staff's evaluation of the SPCS-specific AMP is provided below.

3.4.2.3.1 Generator Stator Water Chemistry Activities (B.2.7)

Summary of Technical Information in the Application. The description of the Generator Stator

Water Chemistry Activity AMP can be found in Appendix B, Section B.2.7, "Generator Stator

Water Chemistry Activities (Quad Cities Only)," of the LRA. The program is designed to

prevent aging by maintaining a high purity level of the stator water cooling, in accordance with

General Electric guidelines for stator water cooling water systems. The applicant stated that

continuous conductivity monitoring and resin-bed filtration are used to maintain the water

quality. The applicant further stated that no age-related degradation of the stator water cooling

system components within the scope of license renewal has been observed.

The applicant concluded that the Generator Stator Water Cooling Water Chemistry Activities

program provides reasonable assurance that the intended functions of the Quad Cities stator

water cooling system components will be maintained consistent with the CLB during the period

of extended operation.

Staff Evaluation. In LRA Section AMP, B.2.7, "Generator Stator Water Chemistry Activities

(Quad Cities Only)," the applicant described its program for managing the loss of material aging

effects to piping and associated components in the main steam and main generator and

auxiliaries systems within the scope of license renewal. This program is not based on a GALL

program; therefore, the staff reviewed the program using the guidance in Branch Technical

Position RLSB-1 in Appendix A of the SRP-LR. The staff's evaluation focused on management

of aging effects through incorporation of the following 10 elements from RLSB-1: program

scope, preventive actions, parameters monitored or inspected, detection of aging effects,

monitoring and trending, acceptance criteria, corrective actions, confirmation process,

administrative controls, and operating experience. The applicant indicated that the corrective

actions, confirmation process, and administrative controls for license renewal are in accordance

with the site-controlled quality assurance program. The staff's evaluation of the applicant's

quality assurance program is provided separately in Section 3.0.4 of this SER, and the

evaluation of the remaining seven elements is provided below. The staff also reviewed the

UFSAR supplement to determine whether it provides an adequate description of the program.

[Program Scope] Section B.2.7 of the LRA states that this program is used to manage loss of

material and cracking of stainless steel components in the stator water cooling system. The

staff's review indicates that this is consistent with the components that credit this AMP in the

AMR tables; therefore, the staff finds this acceptable. By letter dated May 18, 2004, the

applicant expanded the scope of this program to include Dresden. The staff finds this change

acceptable, as discussed in SER Section 3.0.5.

[Preventive or Mitigative Actions] The LRA describes the Generator Stator Water Chemistry

Activities program as a mitigative program. This program relies on maintaining water chemistry

parameters in accordance with General Electric guidelines for preventing the identified aging

effects. The LRA states that the program mitigates loss of material through chemistry control.

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The LRA also states that SCC is prevented because the water impurity levels are low and

because the system operating temperature is less than 1400F. The staff agrees that

maintaining the stator water chemistry within the General Electric guidelines will effectively

mitigate the identified aging effects: therefore, the staff finds this acceptable.

[Parameters Monitored or Inspected] LRA Section B.2.7 states that the stator water cooling

system water is continuously monitored for purity by a conductivity cell, and that water

chemistry data is periodically logged. The staff finds these to be appropriate parameters to

monitor for managing the water chemistry; therefore, the staff finds this acceptable.

[Detection of Aging Effects] LRA Section B.2.7 states that the Generator Stator Water

Chemistry Activities program is a preventative program and does not include actions to detect

aging effects (other than corrective actions if parameters are outside the required band). Since

the program is designed to prevent aging, and since the water is maintained at high purity

levels in accordance with the General Electric guidelines, the staff finds this acceptable.

[Monitoring and Trending] As stated above, the water conductivity is continuously monitored via

an on-line conductivity monitor. In addition, chemistry data is periodically logged. The staff

finds this monitoring and trending to be appropriate for maintaining the water chemistry within

the required parameters; therefore, the staff finds this acceptable.

[Acceptance Criteria] Section B.2.7 of the LRA states that the water chemistry acceptance

criteria are in accordance with the General Electric guidelines. In its October 3, 2003, response

to RAI 3.0-1 related to the definitions of the environments used in the LRA, the applicant

provided additional information related to the conductivity, dissolved oxygen, silica, and copper

levels for this system. Since the water chemistry is maintained in accordance with the General

Electric guidelines, the staff finds this acceptable.

[Operating Experience] Section B.2.7 of the LRA states that no age-related degradation of

stator water systems components within the scope of license renewal has been observed. In

addition, in a conference call on November 26, 2003, the applicant stated that the plant

operating experience is consistent with industry operating experience (nuclear and non-nuclear

applications) with General Electric generators stator water cooling systems. The applicant

concluded that the current water chemistry activities have proven effective. The staff finds that

the operating experience supports the conclusion that the Generator Stator Water Chemistry

Activities program is effective at preventing aging of the stator water cooling system

components; therefore, the staff finds this acceptable.

Conclusions. On the basis of its review of the'applicant's program, the staff finds that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

3.4.2.4 Aging Management Review of the Steam and Power Conversion Systems

The staff reviewed the components listed in LRA Tables 2.3.4-1 through 2.3.4-7 to determine

whether the applicant had properly identified the applicable AMRs and AMPs needed to

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adequately manage the aging effects for the components. This portion of the staff review

involved identification of the aging effects for each component, ensuring that each aging effect

was evaluated using the appropriate AMR in Section 3, and that management of the aging

effect was captured in the appropriate AMP. The results of the staff's review are provided

below. The staff also reviewed the UFSAR Supplements for the AMPs credited with managing

aging in the SPCS components to determine whether the program description adequately

described the program.

The following sections provide the results of the staff's evaluation of the adequacy of aging

management for components in each SPCS.

3.4.2.4.1 Main Steam System

Summary of Technical Information in the Application. The description of the main steam

system can be found in Section 2.3.4.1 of this SER. The components, aging effects, and AMPs

are provided in LRA Tables 2.3.4-1, 3.1-1, 3.2-1, 3.4-1, and 3.4-2.

Aging Effects

Table 2.3.4-1 in the LRA lists the components for the main steam system as closure bolting,

dampeners, filters/strainers, flow elements, NSR vents or drains, piping and valves,

thermowells, tubing, valves, piping and fittings, restricting orifices, accumulators, flexible hoses,

rupture discs, and vacuum breakers.

The LRA identified the following applicable aging effects for the main steam system:

Low-alloy steel exposed to air with metal temperature up to 288 0C (550 OF) is subject to

cumulative fatigue damage due to fatigue. Low-alloy steel exposed to air, moisture, humidity,

and leaking fluid experiences loss of material due to general corrosion. Low-alloy steel

exposed to air, moisture, humidity, and leaking fluid is identified as experiencing crack initiation

and growth due to cyclic loading stress-corrosion cracking.

Carbon steel exposed to air, moisture, humidity and leaking fluid is subject to loss of material

due to corrosion. Carbon steel exposed to moist containment atmosphere (air/nitrogen), steam,

or demineralized water experiences loss of material due to general, pitting, and crevice

corrosion. Carbon steel exposed to 288 0C (550 OF) steam is subject to cumulative fatigue

damage due to fatigue. Carbon steel exposed to moist containment air, steam, or 288 OC

(550 OF) steam is identified as subject to loss of material due to general, pitting, and crevice

corrosion. Carbon steel exposed to steam or 288 0C (550 0F) steam experiences wall thinning

due to accelerated corrosion. Carbon steel exposed to 288 0C (550 0F) reactor coolant water is

subject to crack initiation and growth due to stress-corrosion cracking, intergranular stresscorrosion cracking, thermal, and mechanical stress. Carbon steel exposed to containment

nitrogen or air, moisture, and humidity where the surface is >100 0C (212 0F) experiences no

aging effects.

Stainless steel exposed to moist containment atmosphere (air/nitrogen), steam, or

demineralized water experiences loss of material due to general, pitting, and crevice corrosion.

Stainless steel exposed to 288 0C (550 0F) reactor coolant water or steam is identified as

experiencing crack initiation and growth due to stress-corrosion cracking and intergranular

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stress-corrosion cracking. Stainless steel 'exposed to saturated air or warm moist air is subject

to loss of material due to pitting and crevice corrosion. Stainless steel exposed to air, moisture,

humidity, and leaking fluid experiences loss of material due to corrosion. Stainless steel

external surfaces exposed to air, moisture, and humidity <100 0C (212 0F), or air, moisture, and

humidity where the surface temperature is >100 OC (212 OF), and containment nitrogen

experience no aging effects.

Brass and bronze exposed to air, moisture, humidity, and leaking fluid are subjected to loss of

material due to corrosion.

Elastomers, neoprene, and similar material exposed to saturated air or containment nitrogen

experiences hardening and loss of strength due to elastomer degradation.

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the main

steam system:

* ASME Section Xl Inservice Inspection Program, Subsection IWB, IWC, & IWD (B.1.1)

* Water Chemistry Program (B.1.2)'

* BWR Stress-Corrosion Cracking Program (B.1.7)

* Flow-Accelerated Corrosion Program (B.1.1 1)

* Bolting Integrity Program (B.1.12)

* One-Time Inspection Program (B.1.23)

* Compressed Air Monitoring Program (B.1.16)

* Structures Monitoring Program (B.1.30)

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, in the main

steam system. The staff also reviewed the applicable UFSAR Supplements for the AMPs to

ensure that the program descriptions adequately describe the AMPs.

Aging Effects

The staff reviewed the information in Section 2.3.4.1 and Tables 2.3.4-1, 3.1-1, 3.2-1, 3.4-1,

and 3.4-2 of the LRA. During its review, the staff determined that additional information was

needed to complete its review.

By letter dated August 4, 2003, the staff requested additional information, per RAI 3.4.1-1, to

resolve a discrepancy in Table 3.4-2, AMR Reference 3.4.2.51. In this reference, the

discussion column addresses crevice and pitting corrosion in a treated water environment, while

the aging effect/mechanism addresses crack initiation and growth/stress-corrosion cracking and

intergranular stress-corrosion cracking in a 288 0C steam environment. The staff asked the

applicant to verify that the aging effect is loss of material or to include the BWR StressCorrosion Cracking Program. In its response dated October 3, 2003, the applicant stated that

the discussion in Table 3.4-2, Reference 3.4.2.51, should have read uNUREG-1801 does not

address stress-corrosion cracking of stainless steel in a steam environment," indicating that the

reference is to cracking, not loss of material. Further, the applicant stated that GALL Program

XI.M7, "BWR Stress Corrosion Cracking," is not being used because it is applicable to stainless

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steel piping components that are part of the reactor coolant pressure boundary exposed to

reactor coolant at or above temperature of 93 0C. The components associated with Reference

3.4.2.51 are main steam system valves with an environment of 288 CC steam. Therefore, the

applicant stated that the appropriate AMP is the Water Chemistry Program (B.1.2), which

mitigates the effects of cracking in stainless steel by reducing the presence of impurities such

as sulfates and chlorides. The staff finds that the applicant has resolved the typographical

error. In addition, the staff agrees that GALL Program XL.M7 is not applicable to the

components or environment addressed by this reference, since historically intergranular stresscorrosion cracking of stainless steel in a steam environment has not been problematic, as

indicated by systems referenced in the GALL for which intergranular stress-corrosion cracking

has been identified. Further, the staff agrees that the Water Chemistry Program is appropriate

for managing the aging effect for these components; therefore, the staff finds this acceptable.

By letter dated August 4, 2003, the staff requested additional information, per RAI 3.4.1-2, to

clarify the information related to AMR Reference 3.2.1.3. The discussion column refers to

Section 3.2.1.1.3 of the LRA; however, Section 3.2.1.1.3 does not address the main steam

system. By letter dated October 3, 2003, the applicant stated that the difference results from

the use of GALL terminology. In GALL, the safety relief discharge piping is classified as part of

the automatic depressurization system, which is scoped in the ECCS group. However, at

Dresden and Quad Cities, the safety relief discharge piping is classified as part of the main

steam system. The staff finds the applicant's clarification to be acceptable. The staff notes that

this clarification is also applicable to the applicant's use of AMR Reference 3.2.1.5, which also

addresses the safety relief discharge piping. The GALL recommends further evaluation for

these AMR references. The staff's evaluation of these AMR references is in Sections 3.2.2.2.2

and 3.2.2.2.3 of this SER.

For flexible hoses in the main steam system, the LRA uses Ref. No. 3.4.2.18, which addresses

elastomers of neoprene and similar materials in a containment nitrogen environment, and

identifies no aging effects. Environmental conditions such as temperature and radiation can

affect the aging of neoprene and similar materials. Therefore, in RAI 3.4.1-3, the staff asked

the applicant clarify the environment with respect to temperature, radiation levels, and time

when the containment is not or has not been inerted, to justify that the neoprene hoses do not

require aging management. In its response dated October 3, 2003, the applicant stated that

the flexible hoses in question are in the main steam system attached to the air accumulators for

the MSIVs, and the LRA should have shown the aging effectlaging mechanism as hardening

and loss of strength due to elastomer degradation, and the aging management program

credited should have been B.1.23, "One-Time Inspection." The staff asked for further

information on the environmental conditions, including temperature and radiation levels, to

justify the use of a one-time inspection. In its response dated January 26, 2004, the applicant

stated that they believe the hoses are constructed of stainless steel with an overall stainless

steel outer braided jacket. In the one-time inspection, the applicant will verify that the hoses are

stainless steel and inspect for mechanical damage. If the hoses are found to be elastomer,

they will be replaced with stainless steel hoses. The applicant further clarified that the internal

environment is saturated air up to 135 IF, the outside environment is containment nitrogen up to

135 OF with up to 90 percent relative humidity, and the 60-year radiation dose is 1.65E07 Rads.

The staff finds that a one-time inspection of stainless steel flexible hoses in the above

environment is acceptable, since no significant degradation is expected to occur. The staff also

finds that replacement of the elastomer hoses with stainless steel hoses alleviates the concern

on elastomer degradation; therefore, the staff finds this acceptable.

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The aging effects identified in the LRA for the main steam system are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the main steam system:

* ASME Section Xl Inservice Inspection Program, Subsection IWB, IWC, & IWD (Section

3.0.3.1)

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* One-time Inspection Program (Section 3.0.3.10)

* Compressed Air Monitoring Program (Section 3.0.3.8)

* Structures Monitoring Program (Section 3.0.3.14)

* Periodic Inspection of Components Subject to Moist Environments Program (Section

3.0.3.18)

As part of RAI B.1.23.2-6, the staff questioned the use of one-time inspections to manage aging

for components in a moist air environment. In its response dated March 25, 2004, the applicant

credited the Periodic Inspection of Components Subject to Moist Environments program to

manage aging effects for stainless steel, carbon steel, cast iron, aluminum, copper, and brass

and bronze components exposed to moist air environments and subject to wetting. The staff's

evaluation of the Periodic Inspection of Components Subject to Moist Environments AMP is

contained in SER section 3.0.3.18.

After evaluating the applicant's AMR for each of the components in the main steam system, the

staff evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects for this system. For those components identified in Tables 3.1-1, 3.2-1,

and 3.4-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by

the GALL Report or that the AMPs credited are appropriate for the identified aging effects. For

the components identified in LRA Table 3.4-2, the staff verified that the applicant credited AMPs

that are appropriate for the identified aging effects.

For the component UNSR vents or drains, piping and valves" addressed by AMR Reference

3.4.2.30, the applicant has identified that the material-environment includes carbon steel

exposed to air, moisture, humidity, and leaking fluid. In its response to RAI B.1.23-2(b), the

applicant implies that the loss of material due to corrosion is expected to be sufficiently slow

that a one-time inspection can be used for aging management. This issue was identified as part

of Open Item B.1.23-2. The staff finds this acceptable, as discussed in Section 3.0.3.10 of this

SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the main steam

system will effectively manage or monitor the aging effects identified in the LRA.

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Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.4.2.4.2 Feedwater System

Summary of Technical Information in the Application. The description of the feedwater system

can be found in Section 2.3.4.2 of this SER. The components, aging effects, and AMPs are

provided in LRA Tables 2.3.4-2, 3.1-1, 3.4-1, and 3.4-2.

Aging Effects

Table 2.3.4-2 in the LRA lists the following components for the feedwater system-closure

bolting, NSR vents or drains, piping and fittings, and valves.

The LRA identified the following applicable aging effects for the feedwater system:

High-strength, low-alloy steel exposed to air with metal temperature up to 288 0C (550 OF)

experiences cumulative fatigue damage. Low-alloy steel exposed to air, moisture, humidity,

and leaking fluid is subject to loss of material due to general corrosion. Low-alloy steel exposed

to air, moisture, humidity, and leaking fluid is identified as experiencing crack initiation and

growth due to cyclic loading stress-corrosion cracking.

Carbon steel exposed to air, moisture, humidity, and leaking fluid is identified as subject to loss

of material due to corrosion. Carbon steel exposed to 288 'C (550 OF) reactor coolant water is

subject to crack initiation and growth due to stress-corrosion cracking and intergranular stresscorrosion cracking. Carbon steel exposed to 288 0C (550 OF) reactor coolant water or up to

225 OC (437 OF) reactor coolant water, or treated water experiences cumulative fatigue damage

due to fatigue. Carbon steel exposed to treated water is subject to loss of material due to

general, pitting, and crevice corrosion. Carbon steel exposed to 288 0C (550 OF) reactor

coolant water or up to 225 0C (437 OF) reactor coolant water, or treated water experiences wall

thinning due to accelerated corrosion. Carbon steel exposed to air, moisture, and humidity

where surface temperature is >100 0C (212 OF), and containment nitrogen experiences no

aging effects.

Stainless steel exposed to 288 'C (550 0F) reactor coolant water is identified as subject to

crack initiation and growth due to stress-corrosion cracking and intergranular stress-corrosion

cracking. Stainless steel exposed to 288 OC (550 OF) reactor coolant water is subject to

cumulative fatigue damage due to fatigue. Stainless steel exposed to air, moisture, humidity,

and leaking fluid experiences loss of material due to corrosion. Stainless steel exposed to

treated water is identified as subject to loss of material due to pitting and crevice corrosion.

Stainless steel exposed to air, moisture, and humidity <100 'C (212 OF); air, moisture and

humidity where surface temperature is >100 0C (212 OF); and containment nitrogen

experiences no aging effects.

Cast austenitic stainless steel exposed to 288 0C (550 0F) reactor coolant water is subject to

cumulative fatigue damage due to fatigue.

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Brass and bronze exposed to air, moisture, humidity, and leaking fluid are subject to loss of

material due to corrosion.

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the

feedwater system:

* ASME Section Xl Inservice Inspection Program, Subsection IWB, IWC, & IWD (B.1.1)

* Water Chemistry Program (B.1.2)

* BWR Stress-Corrosion Cracking Program (B.1.7)

* Flow-Accelerated Corrosion Program (B.1.1 1)

* Bolting Integrity Program (B.1.12)

* One-Time Inspection Program (B.1.23)

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects and the AMPs credited for managing the aging effects in the

feedwater system. The staff also reviewed the applicable UFSAR Supplements for the AMPs to

ensure that the program descriptions adequately describe the AMPs.

Aging Effects

The aging effects identified in the LRA for the feedwater system are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the feedwater system:

* ASME Section XI Inservice Inspection Program, Subsection IWB, IWC, & IWD (Section

3.0.3.1)

* Water Chemistry Program (Section 3.0.3.2)

* BWR Stress-Corrosion Cracking Program (Section 3.0.3.3)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* One-Time Inspection Program (Section 3.0.3.10)

After evaluating the applicant's AMR for each of the components in the feedwater system, the

staff evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects for this system. For those components identified in Tables 3.1-1 and

3.4-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by the

GALL Report or that the AMPs credited are appropriate for the identified aging effects. For the

components identified in LRA Table 3.4-2, the staff verified that the applicant credited AMPs

that are appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the feedwater

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system will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.4.2.4.3 Condensate and Condensate Storage Systems

Summary of Technical Information in the Application. The description of the condensate and

condensate storage systems can be found in Section 2.3.4.3 of this SER. The components,

aging effects, and AMPs are provided in LRA Tables 2.3.4-1, 3.4-1, and 3.4-2.

Aging Effects

Table 2.3.4-3 in the LRA lists the following components for the condensate and condensate

storage systems-closure bolting, piping and fittings, tanks, thermowells, tubing, and valves.

The LRA identified the following applicable aging effects for the condensate and condensate

storage system.

Low-alloy steel exposed to containment nitrogen experiences crack initiation and growth from

cyclic loading. Low-alloy steel exposed to air, moisture, humidity, and leaking fluid is subject to

loss of material due to general corrosion. High-strength, low-alloy steel exposed to outdoor

ambient conditions is identified as experiencing loss of material due to general corrosion and

wear.

Carbon steel exposed to treated water is subject to loss of material due to general, pitting, and

crevice corrosion. Carbon steel exposed to treated water is subject to loss of material due to

general and pitting corrosion. Carbon steel exposed to treated water is identified as subject to

wall thinning due to accelerated corrosion. Carbon steel exposed to outdoor ambient conditions

experiences loss of material due to general, pitting, and crevice corrosion. Carbon steel

exposed to soil and ground water is subject to loss of material due to general, pitting, crevice,

and microbiologically influenced corrosion.

Stainless steel exposed to treated water is subject to loss of material due to pitting and crevice

corrosion. Stainless steel exposed to outdoor ambient conditions, or soil or ground water,

experiences loss of material due to pitting and crevice corrosion. Stainless steel exposed to air,

moisture, and humidity <100 'C (212 'F) experiences no aging effects.

Aluminum exposed to <90 'C (194 'F) treated water experiences loss of material due to pitting

and crevice corrosion. Aluminum exposed to outdoor ambient conditions, or soil or ground

water, experiences loss of material due to pitting. Aluminum exposed to outdoor ambient

conditions experiences cracking due to stress-corrosion cracking. Aluminum exposed to air,

moisture, and humidity <100 'C (212 'F) experiences no aging effects.

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Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the

condensate and condensate storage systems:

* Water Chemistry Program (Section 3.0.3.2)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* One-Time Inspection Program (Section 3.0.3.10)

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects, and the AMPs credited for managing the aging effects, in the

condensate and condensate storage systems. The staff also reviewed the applicable UFSAR

Supplements for the AMPs to ensure that the program descriptions adequately describe the

AMPs.

Aging Effects

The staff reviewed the information in Section 2.3.4.3 and Tables 2.3.4-3, 3.4-1, and 3.4-2 of the

LRA. During its review, the staff determined that additional information was needed to

complete its review.

In RAI 3.4.3-1, issued on August 4, 2003, the staff asked why the high-strength, low-alloy steel

closure bolting in outdoor ambient conditions, covered by AMR Reference 3.4.2.2, are only

subject to loss of material due to general corrosion and wear. The GALL report, Chapter VIII

H.2-a&b, lists carbon steel low-alloy steel closure bolting in air, moisture, humidity, and leaking

fluid environments as being subject to loss of material due to general corrosion and crack

initiation, and growth due to cyclic loading and/or stress-corrosion cracking. This GALL

reference is used for other closure bolting in SPCS, as identified by Reference 3.4.1.6. By

letter dated October 3, 2003, the applicant responded that GALL Chapter VIII, H.2-b, refers to

closure bolting in high-pressure or high-temperature systems. For bolting in the high-pressure

or high-temperature portions of SPCS, the applicable aging effects are listed in Reference

3.4.1.6. The applicant stated that the bolts associated with LRA Reference 3.4.2.2 are on the

piping to the condensate storage tanks, which is low-pressure and low-temperature piping not

subject to cyclic loading. The applicant further stated that the bolts used are ASTM Al 93,

Grade B7 with a tensile strength of 125 ksi. EPRI 1003056, "Non-Class 1 Mechanical Guideline

and Mechanical Tools," Appendix F, "Closure Bolting," states that stress-corrosion cracking is

not an applicable aging effect for bolting material with a tensile strength of less than 150 ksi.

The applicant concluded that for bolting in the low-pressure, low-temperature portion of the

condensate and condensate storage system, loss of material due to general corrosion or wear

is the only applicable aging effect. The staff concurs that, based on the applicant's clarification

of the location, operating environment, and bolting materials, the bolting in question would not

be subject to crack initiation and growth due to cyclic loading and/or stress-corrosion cracking.

The staff concludes that the applicant has identified the appropriate aging effects for this

bolting; therefore, the staff finds this acceptable.,

The aging effects identified in the LRA for the condensate and condensate storage systems are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible the aging effects were identified and that the aging effects listed

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are appropriate for the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the condensate and condensate storage systems:

* Water Chemistry Program (Section 3.0.3.2)

* Flow-Accelerated Corrosion Program (Section 3.0.3.4)

* Bolting Integrity Program (Section 3.0.3.5)

* One-Time Inspection Program (Section 3.0.3.10)

After evaluating the applicant's AMR for each of the components in the condensate and

condensate storage systems, the staff evaluated the AMPs listed above to determine if they are

appropriate for managing the identified aging effects for these systems. For those components

identified in Table 3.4-1 of the LRA, the staff verified that the applicant credited the AMPs

recommended by the GALL Report or that the AMPs credited are appropriate for the identified

aging effects. For the components identified in LRA Table 3.4-2, the staff verified that the

applicant credited AMPs that are appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the condensate

and condensate storage systems will effectively manage or monitor the aging effects identified

in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.4.2.4.4 Main Condenser

Summary of Technical Information in the Application. The description of the main condenser

can be found in Section 2.3.4.4 of this SER. The components, aging effects, and AMPs are

provided in LRA Tables 2.3.4-4 and 3.4-2.

Aging Effects

Table 2.3.4-4 in the LRA lists the following components for the main condenser-main

condenser hotwells, false floors, main condenser tubes, tubesheets, main condenser

waterboxes, and hatches.

The LRA identified the following applicable aging effects for the main condenser:

Carbon steel and stainless steel exposed to steam or open-cycle cooling water (raw water side)

experience no aging effects. Carbon steel exposed to air, moisture, and humidity <100 'C

(212 'F) also experiences no aging effects.

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Aging Management Programs

The LRA did not credit any AMPs for the main condenser system because the applicant did not

identify any aging effects requiring management.

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects and the AMPs credited for managing the aging effects in the main

condenser.

Aging Effects

The staff reviewed the information in Section 2.3.4.4 and Tables 2.3.4-4 and 3.4-2 of the LRA.

During its review, the staff determined that additional information was needed to complete its

review.

In RAI 3.4.4-3, sent by letter dated August 4, 2003, the staff asked the applicant to explain the

conclusion that the components in the main condenser do not require aging management. The

material-environment combinations include carbon steel in steam, carbon steel in raw water,

stainless steel in raw water, and carbon steel in air, moisture, and humidity <100 0C. All of

these material-environment combinations are subject to aging degradation; however, the

applicant determined that no aging management was required. The staff asked the applicant to

provide justification. In its response dated October 3, 2003, the applicant stated that the license

renewal intended function of the main condenser is to provide post accident containment,

holdup, and plate-out of iodine for MSIV bypass leakage. This intended function is dependent

on the condenser's surface area, volume, and leakage integrity, and that aging degradation

would only impact the leakage integrity. The applicant argued that leakage integrity sufficient to

perform the post accident intended function is continuously confirmed by normal plant operation

because the main condenser must perform a significant pressure boundary function (maintain

vacuum) in support of normal plant operation. Therefore, the applicant concluded that there are

no creditable aging effects that would affect the intended function of the main condenser, and

no AMP is required. The staff has reviewed the applicant's response and concurs that the

condenser's intended function is continually verified during normal plant operation. Therefore,

the staff finds that there are no aging effects that require management for the main condenser.

By letter dated August 4, 2003, the staff requested two clarifications of apparent inconsistencies

between the component groups listed in LRA Table 2.4.4-4 and Table 3.4-2. The applicant

clarified the component groups that were included in the AMR references. Since all main

condenser components are associated with appropriate AMR references, the staff finds the

clarifications to be acceptable.

The aging effects identified in the LRA for the main condenser are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant did not identify any AMPs for the main condenser. The staff finds this acceptable

because there are no aging effects that require management for the main condenser.

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Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.4.2.4.5 Main Turbine and Auxiliary Systems

Summary of Technical Information in the Application. The description of the main turbine and

auxiliary systems can be found in Section 2.3.4.5 of this SER. The components, aging effects,

and AMPs are provided in LRA Tables 2.3.4-5, 3.4-1, and 3.4-2.

Aging Effects

Table 2.3.4-5 in the LRA lists the following components for the main turbine and auxiliary

systems-closure bolting, piping and fittings, tubing, valves, and accumulators.

The LRA identified the following applicable aging effects for the main turbine and auxiliary

systems:

Low-alloy steel exposed to air, moisture, humidity, and leaking fluid experiences loss of material

due to general corrosion. Low-alloy steel exposed to air, moisture, humidity, and leaking fluid is

subject to crack initiation and growth due to cyclic loading stress-corrosion cracking.

Stainless steel exposed to turbine EHC fluid is identified as subject to loss of material due to

pitting and crevice corrosion. Stainless steel exposed air, moisture, and humidity <100 0C

(212 OF) experiences no aging effects.

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the main

turbine and auxiliary systems:

* Bolting Integrity Program (B.1.12)

* One-Time Inspection Program (B.1.23)

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

AMR for the aging effects and the AMPs credited for managing the aging effects in the main

turbine and auxiliary systems. The staff also reviewed the applicable UFSAR Supplements for

the AMPs to ensure that the program descriptions adequately describe the AMPs.

Aging Effects

The aging effects identified in the LRA for the main turbine and auxiliary systems are consistent

with industry operating experience for the materials and environments listed. The staff finds

that all the plausible the aging effects were identified and that the aging effects listed are

appropriate for the combination of materials and environments specified.

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Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the main turbine and auxiliary systems:

* Bolting Integrity Program (Section 3.0.3.5)

* One-Time Inspection Program (Section 3.0.3.10)

* Lube Oil Monitoring Activities (Section 3.0.3.16)

After evaluating the applicant's AMR for each of the components in the main turbine and

auxiliary systems, the staff evaluated the AMPs listed above to determine if they are

appropriate for managing the identified aging effects for these systems. For those components

identified in Table 3.4-1 of the LRA, the staff verified that the applicant credited the AMPs

recommended by the GALL Report or that the AMPs credited are appropriate for the identified

aging effects. For the components identified in LRA Table 3.4-2, the staff verified that the

applicant credited AMPs that are appropriate for the identified aging effects.

In RAI B.1.23-2, the staff questioned the use of a one-time inspection as the only aging

management activity for components exposed to an environment of EHC oil. The staff's

concern was that proper maintenance of oil chemistry is critical to preventing any aging effects

in this environment. In its response dated January 26, 2004, the applicant stated that

monitoring of the EHC oil, which is already performed at the stations, will be credited under

AMP B.2.5, "Lubricating Oil Monitoring Activities." The staff finds that monitoring and

controlling the EHC oil quality will prevent significant aging of the system components in this

environment; therefore, the staff finds the use of a one-time inspection as a verification to be

acceptable. The staff's review of the Lubricating Oil Monitoring Activities program and the OneTime Inspection program are addressed in SER Sections 3.0.3.16 and 3.0.3.10, respectively.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the main turbine

and auxiliary systems will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.4.2.4.6 Turbine Oil System (Quad Cities Only)

Summary of Technical Information in the Application. The description of the turbine oil system

can be found in Section 2.3.4.6 of this SER. The components, aging effects, and AMPs are

provided in LRA Tables 2.3.4-6, 3.4-1, and 3.4-2.

Aging Effects

Table 2.3.4-6 in the LRA lists the following components for the turbine oil system-closure

bolting, filters/strainers, piping and fittings, valves, pump casing, and tanks.

The LRA identified the following applicable aging effects for the turbine oil system:

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Low-alloy steel exposed to air, moisture, humidity, and leaking fluid experiences loss of material

due to general corrosion. Low-alloy steel exposed to air, moisture, humidity, and leaking fluid is

subject to crack initiation and growth due to cyclic loading stress-corrosion cracking.

Carbon steel exposed to generator hydrogen seal oil is identified as subject to loss of material

due to pitting and crevice corrosion.

Cast iron exposed to generator hydrogen seal oil and air, moisture, and humidity <100 0C

(212 0F) experiences loss of material due to pitting and crevice corrosion.

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the turbine

oil system:

* Bolting Integrity Program (B.1.12)

* One-Time Inspection Program (B.1.23)

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's AMR for the aging effects and the AMPs credited for managing the aging effects in the turbine

oil system. The staff also reviewed the applicable UFSAR Supplements for the AMPs to ensure

that the program descriptions adequately describe the AMPs.

Aging Effects

The aging effects identified in the LRA for the turbine oil system are consistent with industry operating experience for the materials and environments listed. The staff finds that all the

plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the turbine oil system:

* Bolting Integrity Program (Section 3.0.3.5)

* One-Time Inspection Program (Section 3.0.3.10)

* Lube Oil Monitoring Activities (Section 3.0.3.16)

After evaluating the applicant's AMR for each of the components in the turbine oil system, the

staff evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects for this system. For those components identified in Table 3.4-1 of the

LRA, the staff verified that the applicant credited the AMPs recommended by the GALL Report

or that the AMPs credited are appropriate for the identified aging effects. For the components identified in LRA Table 3.4-2, the staff verified that the applicant credited AMPs that are

appropriate for the identified aging effects.

In RAI B.1.23-2, the staff questioned the use of a one-time inspection as the only aging

management activity for components exposed to an environment of generator hydrogen seal

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oil. The staff's concern was that proper maintenance of oil chemistry is critical to preventing

any aging effects in this environment. In its response dated January 26, 2004, the applicant

stated that monitoring of the generator hydrogen seal oil, which is already performed at the

stations, will be credited under AMP B.2.5, 'Lubricating Oil Monitoring Activities." The staff

finds that monitoring and controlling the generator hydrogen seal oil quality will prevent

significant aging of the system components in this environment; therefore, the staff finds the

use of a one-time inspection as a verification totbe acceptable. The staff's review of the

Lubricating Oil Monitoring Activities program and the One-Time Inspection program are

addressed in SER Sections 3.0.3.16 and 3.0.3.10, respectively.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the turbine oil

system will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.4.2.4.7 Main Generator and Auxiliaries (Quad Cities Only)

Summary of Technical Information in the ADplication. The description of the main generator

and auxiliaries can be found in Section 2.3.4.7 of this SER. The components, aging effects,

and AMPs are provided in LRA Tables 2.3.4-7, 3.4-1, and 3.4-2.

Aging Effects

Table 2.3.4-7 in the LRA lists the following components for the main generator and

auxiliaries-closure bolting, piping and fittings, pumps, valves, heat exchangers, housings, and

tanks.

The LRA identified the following applicable aging effects for the main generator and auxiliaries:

Low-alloy steel exposed to air, moisture, humidity, and leaking fluid experiences loss of material

due to general corrosion. Low-alloy steel exposed to air, moisture, humidity, and leaking fluid is

subject to crack initiation and growth due to cyclic loading stress-corrosion cracking.

Stainless steel exposed demineralized water or stator liquid cooling is identified as subject to

loss of material due to pitting and crevice corrosion. Stainless steel exposed to air, moisture,

and humidity <100 'C (212 OF) experiences no aging effects.

Aging Management Programs

The LRA credited the following AMPs with managing the identified aging effects for the main

generator and auxiliaries:

* Bolting Integrity Program (B.1.12)

* Main Generator Stator Cooling Water Chemistry Program (B.2.7)

Staff Evaluation. This section provides the results of the staff's evaluation of the applicant's

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AMR for the aging effects and the AMPs credited for managing the aging effects in the main

generator and auxiliaries. The staff also reviewed the applicable UFSAR Supplements for the

AMPs to ensure that the program descriptions adequately describe the AMPs.

Aging Effects

The aging effects identified in the LRA for the main generator and auxiliaries are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible the aging effects were identified and that the aging effects listed are appropriate

for the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the main generator and auxiliaries:

* Bolting Integrity Program (Section 3.0.3.5)

* Main Generator Stator Cooling Water Chemistry Program (Section 3.4.2.3.1)

After evaluating the applicant's AMR for each of the components in the main generator and

auxiliaries, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects for this system. For those components identified in Table

3.4-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by the

GALL Report or that the AMPs credited are appropriate for the identified aging effects. For the

components identified in LRA Table 3.4-2, the staff verified that the applicant credited AMPs

that are appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the main

generator and auxiliaries will effectively manage or monitor the aging effects identified in the

LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.5 Containment. Structures, and Component Supports

This section addresses the aging management of the structures and structural components.

The structures that make up this group are described in the following SER sections:

* primary containment-(Section 2.4.1)

* reactor building-(Section 2.4.2)

* main control room and auxiliary electric equipment room-(Section 2.4.3)

* turbine building-(Section 2.4.4)

* diesel generator building-(Section 2.4.5)

* station blackout building and yard structures-(Section 2.4.6)

* isolation condenser pump house (Dresden only)-(Section 2.4.7)

* makeup demineralizer building (Dresden only)-(Section 2.4.8)

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* radwaste floor drain surge tank-(Section 2.4.9)

* miscellaneous foundations- (Section 2.4.10)

* crib house-(Section 2.4.11)

* Unit 1 crib house (Dresden only)-(Section 2.4.12)

* station chimney-(Section 2.4.13)

* crane and hoists-(Section 2.4.14)

* component supports commodity group-(Section 2.4.15)

* insulation commodity group-(Section 2.4.16)

As discussed in Section 3.0.1 of this SER, the structures and structural components subject to

an AMR are included in one of two LRA tables. Table 3.5-1 of the LRA consists of structures

and structural components that are evaluated in the GALL Report. The Discussion column of

this table references LRA Section 3.5.1.1 for further evaluations of aging management, as

recommended by GALL, and also references LRA Section 3.5.1.2 for aging management

programs or evaluations that are different from GALL. Table 3.5-2 of the LRA consists of

structures and structural components that are not evaluated in the GALL Report.

3.5.1 Summary of Technical Information in the Application

The applicant presents the results of its AMRs for the containment, structures, and component

supports in LRA Section 3.5. The applicant's description of the containment, structures, and

component supports can be found in LRA Section 2.4. The passive, long-lived components in

these structures that are subject to an AMR are identified in LRA Tables 2.4-1 through 2.4-16.

The "Aging Management Ref column in these tables identifies the corresponding row of LRA

Table 3.5-1 or Table 3.5-2 that contains the applicable AMR results.

3.5.2 Staff Evaluation

In LRA Section 3.5, the applicant summarized the results of its AMR for structures and

structural components. The staff reviewed LRA Section 3.5 to determine whether the applicant

has provided sufficient information to demonstrate that the effects of aging will be adequately.

managed so that the intended function(s) will be maintained consistent with the CLB throughout

the period of extended operation, in accordance with the requirements of 10 CFR 54.21 (a)(3),

for structures and structural components that are determined to be within the scope of license

renewal and subject to an AMR.

The applicant referenced the GALL Report in its AMR. The staff has previously evaluated the

adequacy of the aging management of structures and structural components for license

renewal as documented in the GALL Report. Thus, the staff did not repeat its review of the

matters described in the GALL Report, except to ensure that the material presented in the LRA

was applicable, and to verify that the applicant had identified the appropriate programs as

described and evaluated in the GALL Report: The staff evaluated those aging management

issues recommended for further evaluation in the GALL Report. The staff also reviewed aging

management information submitted by the applicant that was different from that in the GALL

Report or was not addressed in the GALL Report. Finally, the staff reviewed the UFSAR

Supplements to ensure that they provided an adequate description of the programs credited

with managing aging for structures and structural components.

In LRA Section 3.0, under the heading 'Operating Experience," the applicant stated the

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following:

A review of plant-specific operating experience was conducted to Identify aging effects requiring

management. Industry-wide operating experience since the preparation of NUREG-1801 was also

reviewed to identify aging effects requiring management. These reviews concluded that the aging

effects identified by plant-specific and Industry-wide operating experience were consistent with

those identified in NUREG-1801. Ongoing review of plant-specific and industry operating

experience is performed in accordance with corrective action programs and operating experience

programs.

The applicant has not identified the source material utilized in the plant-specific operating

experience review or in the industry-wide operating experience review. The applicant was

requested in RAI 3.5-2 to submit details of its operating experience review, including the time

frame covered by the review, the information sources used, and any key findings that led to

exclusion of aging effects identified in NUREG-1 801.

In its response to RAI 3.5-2, the applicant stated the following:

The operating experience reviews Included a search of the Dresden and Quad Cities Corrective

Action databases, which contain Condition Reports (CR) and the predecessor program Problem

Identification Forms (PIF) (from 1993 to present), the work control database which contains

maintenance work orders and modifications (from 1984 to present), and a search of the NRC

website for regulatory correspondence, such as Generic Letters, Information Bulletins, and

Information Notices (from April 2001, the date NUREG-1801 was issued, to the present).

Additionally, the EPRI Electrical, Mechanical, and Structural Tools were used to identify relevant

industry operating experience.

The Dresden and Quad Cities License Renewal Application (LRA) identifies the exceptions to

aging effects identified by NUREG-1801 in the Chapter 3 Tables under the Discussion column.

These tables provide the basis for excluding the aging effect or a reference to further discussion of

why the aging effect is not applicable.

The staff finds the applicant's response to be acceptable and considers RAI 3.5-2 resolved.

Tables 3.5-1, 3.5-2, 3.5-3, and 3.5-4 below provides a summary of the staff's evaluation of

components, aging effects/mechanisms, and AMPs listed in LRA Table 3.5-1 for the

components addressed in the GALL Report.

Table 3.5-1. Staff Evaluation for Structures and Structural Components in NUREG-1801

(GALL): Common Components of All Types of PWR and BWR Containment

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LRA Ref No 3.5.1.1) Cumulative fatigue LAA evaluated in TLAA evaluated in Further evaluation of

damage (CLB fatigue ccordance with 10 accordance with cumulative fatigue

analysis exists) FR 54.21 (c) 10 CFR 54.21 (c) damage is provided in

LRA Section 3.5.1.1.4

and LRA Section 4.6.

See SER Section

3.5.22.1.)Penetration

sleeves, bellows, and

_issimilar metal welds

(LRA Ref No 3.5.1.2) Cracking due to cyclic Containment ISI and Containment ISI Consistent with

oading, or crack ontainment Leak B.1.26) and VUREG-1801, with

nitiation and growth due ate Test Containment Leak exceptions evaluated

o SCC Rate Test (B.1.28) n SER Sections

3.5.2.3.1.Penetration

sleeves, penetration

ellows, and dissimilar

etal welds

(LRA Ref No 3.5.1.3) Loss of material due to Containment ISI and Containment ISI Consistent with

corrosion ontainment Leak B.1.26) and VUREG-1801, with

ate Test 3ontain-ment Leak exceptions evaluated

Rate Test (B.1.28) n SER Section

3.5.2.3.1.

Personnel airlock and

quipment hatch

(LRA Ref No 3.5.1.4) Loss of material due to ontainment ISI and Containment IS Consistent with

orrosion ontainment Leak B.1.26) and VUREG-1801, with

ate Test Containment Leak exceptions evaluated

Rate Test (B.1.28) n SER Section

3.5.2.3.1.Personnel

irlock and equipment

atch

LRA Ref No 3.5.1.5) Loss of leak tightness in ontainment Leak Containment Leak Consistent with

losed position due to ate Test and plant Rate Test (B.1.28) and NUREG-1 801.

mechanical wear of echnical lant technical See SER Section

ocks, hinges, and pecifications pecifications 3.5.2.1.)Seals,

losure mechanism gaskets, and moisture

arriers

(LRA Ref No 3.5.1.6) oss of sealant and ontainment ISI and 3ontainment ISI Consistent with

eakage through ontainment Leak B.1.26) and NUREG-1801, with

Containment due to ate Test 3ontain-ment Leak exceptions evaluated

eterioration of joint Rate Test (B.1.28) n SER Section

eals, gaskets, and 3.5.2.3.1

moisture barriers

Table 3.5-2: PWR Concrete (Reinforced and Prestressed) and Steel Containment

BWR Concrete (Mark 11 and 111) and Steel (Mark 1, II, and 111) Containment

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(LRA Ref No 3.5.1.7) Aging of accessible and Containment ISI Not applicable aot applicable for a

naccessible concrete Mark I steel

areas due to leaching of containment

:alcium hydroxide, Concrete elements:

aggressive chemical oundation

ttack, and corrosion of

mbedded steel

LRA Ref No 3.5.1.8) racks, distortion, and Structures Monitoring ot applicable aot applicable for a

ncreases in component Mark I steel

tress level due to containment

ettlement Concrete elements:

foundation

(LRA Ref No 3.5.1.9) Reduction in foundation Structures Monitoring Not applicable aot applicable for a

trength due to erosion Mark I steel

A porous concrete containment

subfoundation Concrete elements:

oundation, dome, and

vall

(LRA Ref No 3.5.1.10) Reduction of strength Plant specific Not applicable aot applicable for a

and modulus due to Mark I steel

elevated temperature containment

Prestressed

ontainment: tendons

nd anchorage

omponents

(LRA Ref No 3.5.1.11) Loss of prestress due to LAA evaluated in Not applicable aot applicable for a

elaxation, shrinkage, accordance with Mark I steel

creep, and elevated 10 CFR 54.21(c) containment

emperature teel elements: liner

)late, containment

,hell

LRA Ref No 3.5.1.12) Loss of material due to Containment ISI and Containment 151 ansistent with

corrosion in accessible Containment Leak B.1.26) and UREG-1801, with

and inaccessible areas Rate Test ontainment Leak xceptions evaluated

ate Test (B.1.28) n SER Sections

3.5.2.4.1, 3.5.2.3.1,

and 3.5.2.2.1

Steel elements: vent

eader, drywell head,

orus, downcomers,

aol shell

LRA Ref No 3.5.1.13) Cumulative fatigue TLAA evaluated in TLAA evaluated in Further evaluation of

damage (CLB fatigue accordance with ccordance with cumulative fatigue

analysis exists) 10 CFR 54.21(c) 10 CFR 54.21(c) Damage is provided in

3ER Section 3.5.2.2.1

Steel elements:

rotected by coating

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(LRA Ref No 3.5.1.14) Loss of material due to Protective Coating Protective Coating Consistent with

-orrosion in accessible Monitoring and Monitoring and .UREG-1801, with

areas only Maintenance Maintenance (B.1.32) exceptions evaluated

n SER Section

3.5.2.4.1

restressed

ontainment: tendons

nd anchorage

omponents

(LRA Ref No 3.5.1.15) Loss of material due to Containment ISI Not applicable Not applicable for a

corrosion of Mark I steel

prestressing tendons containment

and anchorage Concrete elements:

omponents oundation, dome, and

.vall

(LRA Ref No 3.5.1.16) Scaling, cracking, and Containment ISI Not applicable Not applicable for a

palling due to Mark I steel

reeze-thaw; expansion Containment

and cracking due to Steel elements: vent

eaction with aggregate ine bellows, vent

eaders, downcomers

(LRA Ref No 3.5.1.17) Cracking due to cyclic Containment ISI and Containment ISI Consistent with

oads or crack Initiation Containment Leak B.1.26) and NUREG-1801, with

and growth due to SCC late Test Containment Leak Exceptions evaluated

Rate Test (B.1.28) n SER Sections

3.5.2.3.1 and 3.5.2.2.1

Steel elements:

suppression chamber

iner

(LRA Ref No 3.5.1.18) Crack initiation and Containment ISI and Not applicable Not applicable for a

rowth due to SCC Containment Leak Mark I steel

Rate Test containment Steel

3lements: drywell

head and downcomer

pipes

LRA Ref No 3.5.1.19) retting and lockup due Containment ISI ot applicable pplicant states that

o wear aterial does not exist

tDresden or Quad ._ Cities

Table 3.5-3: Class I Structures

Component Group Aging AMP in GALL AMP In LRA Staff Evaluation

Effect/echanism Report 4.11 groups except rroup 6: accessible

nterior/exterior

Ioncrete and steel

_omponents

3-397
I

(LRA Ref No 3.5.1.20) All types of aging effects Structures Structures Monitoring Consistent with

onitoring rogram (B.1.30) NUREG-1801 with

3xceptions evaluated

n SER Section

3.5.2.2.2

Groups 1-3, 5,7-9: ging of inaccessible lant specific lant specific Further evaluation of

naccessible concrete oncrete areas due to aging management of

Components, such as ggressive chemical naccessible areas is

3xterior walls below ttack and corrosion of described in LRA

Irade and foundation mbedded steel Section 3.5.1.1.7.

LRA Ref No 3.5.1.21) 'See SER Section

.5.2.2.2.)

roup 6: all

ccessiblelin-accessib

e concrete, steel, and

earthen components

(LRA Ref No 3.5.1.22) kI types of aging nspection of nspection of Consistent with

ffects, including loss of ater-Control Nater-Control NUREG-1 801, with

aterial due to tructures or tructures (B.1.31) or exceptions evaluated

brasion, cavitation, and 7ERC/US Army ERC/US Army Corps n SER Sections

orrosion orps of Engineers f Engineers Dam 3.5.2.4.2 and 2.4.11

am Inspections and nspections and Group 5: liners

aintenance aintenance

_rograms

LRA Ref No 3.5.1.23) rack initiation and ater Chemistry Aater Chemistry Consistent with

rowth from SCC and rogram and rogram (B.1.2) and UREG-1801.

oss of material due to onitoring of Spent nitoring of Spent See SER Section

revice corrosion uel Pool Water uel Pool Water Level .5.2.1.)Group 1-3, 5,

evel rograms : all masonry block

alls

(LRA Ref No 3.5.1.24) Crack due to restraint, Masonry Wall Masonry Wall Program onsistent with

hrinkage, creep, and B.1.29) UREG-1801.

ggressive environment See SER Section

.5.2.1.)Group 1-3, 5,

-9: foundation

(LRA Ref No 3.5.1.25) Zracks, distortion, and Structures Monitoring Structures Monitoring Consistent with

ncreases in component rogram (B.1.30) NUREG-1801

tress level due to

ettlement urther evaluation is

escribed in LRA

ection 3.5.1.1.1

See SER Section

.5.2.2.1.)

roup 1-3, 5-9:

oundation

LRA Ref No 3.5.1.26) :eduction in foundation Structures Monitoring Structures Monitoring Consistent with

trength due to erosion rogram (B.1.30) UREG-1801

f porous concrete

ubfoundation urther evaluation is

escribed in LRA

ection 3.5.1.1.1.

See SER Section

.5.2.2.1.)

roup 1-5: concrete

I

i

I

i

i

i

I

I

i

i

I

I

3-398
(LRA Ref No 3.5.1.27) Reduction of strength Plant specific Plant specific. Further evaluation is

and modulus due to described In LRA

elevated temperature Section 3.5.1.1.2.

(See SER Section

3.5.2.2.1.)

Groups 7, 8: liners

LRA Ref No 3.5.1.28) Crack initiation and Plant specific Plant specific. Exceptions to

growth from SCC and NUREG-1801

oss of material due to described in SER

crevice corrosion Section 3.5.2.4.2

Table 3.5-4: Component Supports

Component Group ging MP In GALL MP in LRA Staff Evaluation

ffect/Mechanism eport AII Groupssupport members: ging of component tructures Monitoring tructures Monitoring Consistent with

anchor bolts, concrete upport rogram (B.1.30) qUREG-1801.

surrounding anchor See SER Section

bolts, welds, grout 3.5.2.1.)Groups B13.1,

pad, bolted 31.2, and 81.3-

onnections, etc.

(LRA Ref No 3.5.1.29)

support members: Cumulative fatigue TLAA evaluated in TLAA evaluated in Further evaluation of

anchor bolts, welds damage (CLB fatigue accordance with accordance with umulative fatigue

LLRA Ref No 3.5.1.30) analysis exists) 10 CFR 54.21(c) I0 CFR 54.21(c) amage is provided in

ER Section 3.5.2.2.3.

I Groups-support

embers: anchor

olts, welds

All Groups: support Loss of material due to Boric Acid Corrosion Not applicable Not applicable for

members: anchor boric acid corrosion 3WRGroups 81.1,

bolts, welds 31.2, and

31.3-support

members: anchor

olts, welds, spring

angers, guides,

tops, and vibration

solators

(LRA Ref No 3.5.1.31) Loss of material due to ISI [SI (B.1.27) Consistent with

environmental VUREG-1801, with

orrosion; loss of exceptions evaluated

mechanical function due n SER Section

o corrosion, distortion, 3.5.2.4.5

irt, overload, etc. Group 813.1-highstrength low-alloy bolt

LRA Ref No 3.5.1.32) Crack initiation and Bolting Integrity Bolting Integrity Consistent with

growth due to SCC Program (B.1.12). tUREG-1801, with

Exceptions evaluated

n SER Sections

.5.2.4.5 and 3.0.3

3-399
3.5.2.1 Aging Management Evaluations in the GALL Report That Are Relied on for License

Renewal, Which Do Not Require Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL does not recommend further evaluation, the staff sampled

components in these groups to determine whether the plant-specific components contained in

these GALL component groups were bounded by the GALL evaluation. The staff also sampled

component groups to determine whether the applicant had properly identified those component

groups in GALL that were not applicable to its plants. The staff also identified several areas

where additional information or clarification was needed.

On the basis of its review, the staff has verified the applicant's claim of consistency with the

GALL report. The staff finds that the applicant has demonstrated that the effects of aging will

be adequately managed so that the intended functions will be maintained consistent with the

CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.2 Aging Management Evaluations in the GALL Report That Are Relied on for License

Renewal, for Which the GALL Report Recommends Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL recommends further evaluation, the staff reviewed the applicant's

evaluation to determine whether it adequately addressed the issues for which GALL

recommended further evaluation. In addition, the staff sampled components in these groups to

determine whether the plant-specific components contained in these GALL component groups

were bounded by the GALL evaluation.

The GALL Report indicates that further evaluation should be performed for the aging effects

discussed in the following sections.

3.5.2.2.1 Containments

Aging of Inaccessible Concrete Areas. The GALL Report recommends further evaluation of

programs to manage aging effects in inaccessible concrete areas of PWR and BWR

containments. Possible effects due to leaching of calcium hydroxide and aggressive chemical

attack are cracking, spalling, and increases in porosity and permeability. Possible effects due

to corrosion of embedded steel in PWR concrete and steel containments, BWR Mark II

concrete containments, and Mark IlIl concrete and steel containments are cracking, spalling,

loss of bond, and loss of material. Both Dresden and Quad Cities have BWR Mark I steel

containments; therefore, aging of inaccessible concrete areas does not apply.

Cracking, Distortion, and Increases in Component Stress Level due to Settlement and

Reduction of Foundation Strength Due to Erosion of Porous Concrete Subfoundations. If Not

Covered by Structures Monitoring Program. The GALL Report recommends aging

management of (1) cracking, distortion, and increases in component stress level due to

settlement for PWR concrete and steel containments, BWR Mark II concrete containments, and

BWR Mark IlIl concrete and steel containments, and (2) reduction of foundation strength due to

erosion of porous concrete subfoundations for all types of PWR/BWR containments. If a

dewatering system is relied upon for control of settlement and erosion, then proper functioning

3-400
of the dewatering system should be monitored for the period of extended operation. The GALL

Report also recommends further evaluation of cracks, distortion, and increase in component

stress level due to settlement for Groups 1-3, 5, and 7-9 Class I structures and reduction of

foundation strength due to erosion of porous concrete subfoundation for Groups 1-3 and 5-9

Class I structures.

Both Dresden and Quad Cities have BWR Mark I steel containments. The applicant addresses

aging related to settlement and erosion of porous concrete subfoundation for the reactor

building (GALL Group 2 structure). For Groups 1-3, 5, and 7-9 structures, the applicant states

in LRA Section 3.5.1.1.1 that cracks, distortion, and increase in component stress level due to

settlement are not applicable to Dresden and Quad Cities concrete structures, and no aging

management is required. The Dresden and Quad Cities licensing basis does not include a

program to monitor concrete for settlement nor is a dewatering system in place. Dresden and

Quad Cities structures are founded on rock or naturally compacted soil with no documented

changes in groundwater conditions or a history of settlement. Dresden and Quad Cities

evaluations of Information Notices 97-11 and 98-26 concluded that no porous materials were

used.

In LRA Table 3.5-1, Reference No. 3.5.1.25 and 3.5.1.26, the applicant credits the Structures

Monitoring Program (B.1.30) for managing aging due to settlement and erosion of porous

concrete subfoundation and indicates Consistent with NUREG-1 801." This appears to be

inconsistent with the further evaluations presented in LRA Section 3.5.1.1.1. The applicant was

requested in RAI 3.5-3 to clarify this apparent inconsistency.

In its response to RAI 3.5-3, the applicant stated the following:

Exelon concurs with the staff assessment of LRA Table 3.5-1, Aging Management References

3.5.1.25 and 3.5.1.26. Each reference should have stated the aging management evaluations

were 'Exception to NUREG-1801' as defined in section 3.0 of the LRA.

Since the applicant in its response to RAI 3.5-3 has addressed the inconsistency, the staff finds

the applicant's response to be acceptable and considers RAI 3.5-3 resolved.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of cracking, distortion, and increase in component stress level due to

settlement or reduction of foundation strength due to erosion of porous concrete

subfoundations, if not covered by the Structures Monitoring Program, as recommended in the

GALL report. Since the applicant's AMR results are otherwise consistent with the GALL report,

the staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature. The

GALL Report recommends further evaluation of programs to manage reduction of strength and

modulus of concrete structures due to elevated temperature for PWR concrete and steel

containments, BWR Mark II concrete containments, and BWR Mark l1l concrete and steel

containments. The GALL Report notes that the implementation of Subsection IWL

examinations and 10 CFR 50.55a would not be able to detect the reduction of concrete strength

and modulus due to elevated temperature and also notes that no mandated aging management

3-401
exists for managing this aging effect. The GALL Report also recommends further evaluation of

loss of strength and modulus of concrete structures due to elevated temperatures for Groups

1-5 structures.

The GALL Report recommends that a plant-specific evaluation be performed if any portion of

the concrete components exceeds specified temperature limits (for example, general

temperature 66 0C (150 OF) and local area temperature 93 0C (200 OF). The staff verifies that

the applicant's discussion in the renewal application indicates that the affected components are

not exposed to temperatures that exceed the temperature limits (operating temperature less

than 66 0C (150 OF), local area temperature less than 93 0C (200 OF)). For concrete

components that operate above these temperature limits, the staff reviews the applicant's

proposed programs to ensure that the effects of elevated temperature will be managed during

the period of extended operation.

Both Dresden and Quad Cities have Mark I steel containments; therefore, aging of concrete

due to elevated temperature does not apply to the containments. For Groups 1-5 structures,

the applicant states in LRA Section 3.5.1.1.2 that reduction of strength and modulus due to

elevated temperature is not applicable for Dresden and Quad Cities concrete structures, and no

aging management is required since Dresden and Quad Cities normal operating temperatures

are less than 150 OF general and less than 200 OF local. The staff requested in RAI 3.5-4 that

the applicant (1) clarify whether the local concrete temperature or the local ambient air

temperature was compared to the 200 OF limit and (2) describe what provisions exist to ensure

that the concrete surrounding hot piping penetrations does not exceed 200 OF.

In response to RAI 3.5-4, the applicant stated the following:

The Dresden and Quad Cities Groups 1-5 concrete structures were installed in accordance with

ACI 349-85, Code Requirements for Nuclear Safety-related Concrete Structures, Appendix A.

The operating temperature limits associated with these structures are consistent with the guidance provided in NUREG 1801 (which states that temperatures shall not exceed 150 'F except for local

areas which are allowed to have increased temperature not to exceed 200 OF).

All hot pipe penetrations at Dresden and Quad Cities Nuclear Power Stations are designed such

that the local area ambient temperature near the surrounding concrete does not exceed 200 "F.

Hot pipe air gaps through wall penetrations are large enough by design to maintain the area

concrete temperature below 200 OF. Dresden and Quad Cities normal operating ambient

temperature limits do not exceed 150 OF. The following provisions exist to ensure that the local

area temperature near concrete surrounding the hot piping penetrations do not exceed 200 OF.

Penetration sleeves are designed and installed to maintain the area concrete temperature below

200 'F, based on the penetrating piping temperature.

The Drywell Coolers support the Primary Containment by maintaining the Primary Containment

bulk temperature within limits during normal operation (an average temperature of approximately

135 TF).

The staff finds that appropriate design provisions to ensure that concrete does not exceed

prescribed American Concrete Institute code limits are identified in the applicant's response.

However, the statement "The Dresden and Quad Cities Groups 1-5 concrete structures were

installed in accordance with ACI 349-85, Code Requirements for Nuclear Safety-related

Concrete Structures, Appendix A' appears to be incorrect, given the dates of first commercial

operation for these units. Although the staff finds that the applicant has implemented the

appropriate design provisions to ensure that the concrete does not exceed the ACI code limits,

3-402
the applicant was requested to identify the correct code of record and the temperature limits

prescribed in that code. In a letter dated December 5, 2003, the applicant stated that Dresden

and Quad Cities Groups 1-5 concrete structures were designed to ACI 318-63, Building Code

requirements for reinforced concrete. The Adl 318-63, Building Code does not address

susceptibility of concrete to aging effects associated with elevated temperatures. Appendix A to

ACI 349-85 is specifically cited by NUREG-1 801 as providing temperature criteria to be used in

determining the susceptibility of concrete to aging effect. The applicant used the criteria of ACI

349-85 code to assess the temperature aging effect for Dresden and Quad Cities concrete.

The staff finds the applicant's response acceptable and considers RAI 3.5-4 resolved.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of reduction of strength and modulus of concrete structures due to

elevated temperatures, as recommended in the GALL report. Since the applicant's AMR

results are otherwise consistent with the GALL report, the staff finds that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

Loss of Material Due to Corrosion in Inaccessible Areas of Steel Containment Shell or Liner

Plate. The GALL Report identifies programs to manage loss of material due to corrosion of the

steel containment shell or the steel liner plate for all types of PWR and BWR containments.

The AMP consists of ASME Section Xl, Subsection IWE, and the requirements of 10 CFR

50.55a for inaccessible areas. Subsection IWE exempts from examination portions of the

containments that are inaccessible, such as embedded or inaccessible portions of steel liners

and steel containment shells, piping, and valves penetrating or attaching to the containment.

To cover the inaccessible areas, 10 CFR 50.55a(b)(2)(ix) requires that the licensee shall

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. In addition,

the GALL Report recommends further evaluation of plant-specific programs to manage the

aging effects for inaccessible areas if specific criteria defined in the GALL Report cannot be

satisfied. The staff reviewed the applicant's proposed AMP to verify that, where appropriate, an

effective inspection program has been developed and implemented to ensure that the aging

effects in inaccessible areas are adequately managed.

Section 3.5.1.1.3 of the LRA provides information on the AMR of loss of material due to

corrosion in inaccessible areas of the steel containment shell for both Dresden and Quad Cities.

The applicant provided the following information to address the criteria defined in the GALL

Report:

Corrosion of containment steel elements in inaccessible areas will be confirmed as insignificant in

accordance with AMP ASME Section Xl, Subsection IWE (B.1.26).

* Since Dresden Unit 3 had more water leakage In the sand pocket area than Quad Cities and Dresden Unit

2, ultrasonic test examinations were performed on Dresden Unit 3 sand pocket area in 1988. The

examinations Indicated that significant corrosion was not occurring, and it was concluded that corrosion is

insignificant at Dresden Unit 2 and Quad Cities as well. A UT examination of the same locations at

Dresden Unit 3 is conducted as an augmented inspection in accordance with AMP ASME Section Xl,

Subsection IWE (B.1.26) to confirm that significant corrosion is not occurring.

* A general visual inspection of the moisture barrier at the junction of the steel drywell shell and the concrete

3-403
floor is performed once each inspection period in accordance with AMP ASME Section Xi, Subsection IWE

(B.1 .26).

Dresden and Quad Cities documentation demonstrates that concrete meeting the requirements of ACI

318-63 and the guidance of ACI 201 .2R-77 was used for the concrete in contact with the embedded drywell

shell at the sand pocket location. The concrete is monitored for penetrating cracks that provide a path for

water seepage in accordance with Structures Monitoring Program (B.1.30).

In RAI 3.5-5, the staff requested the following additional information regarding this review:

(a) How was it determined that Dresden Unit 3 had more leakage in the drywell sand pocket

area than Dresden Unit 2 and Quad Cities?

(b) Define the quantitative basis for concluding that "significant corrosion was not occurring

in Dresden Unit 3.

(c) What is the technical basis for concluding that corrosion in the sand pocket area is

insignificant at Dresden Unit 2 and Quad Cities?

(d) What controls exist on all four units to limit future leakage into the sand pocket areas,

and how will the leakage be monitored?

(e) What were the. results of the augmented inspection of the sand pocket area for Dresden

Unit 3, which was scheduled for the second half of 2002?

(f) How often will the augmented UT inspection of the sand pocket area be conducted for

Dresden Unit 3, and what is the basis for not conducting similar inspections for Dresden

Unit 2 and Quad Cities?

(g) It is stated that a general visual inspection of the moisture barrier at the junction of the

steel drywell shell and the concrete floor is performed once each inspection period in

accordance with the B.1.26 AMP. Is the inspection conducted each inspection period

for all four units? If not, explain why not.

(h) Confirm that the concrete floor inside the drywell of all four units (1) meets Uthe

requirements of ACI 318-63 and the guidance of ACI 201.2R-77" and (2) "is monitored

for penetrating cracks that provide a path for water seepage in accordance with

Structures Monitoring Program (B.1.30)." This is the staff's interpretation of the fourth

paragraph of LRA Section 3.5.1.1.3.

In response to RAI 3.5-5, the applicant stated the following:

(a) Dresden Unit 3 had significant quantities of water introduced to the drywell annulus to

extinguish a fire in the drywell expansion foam. Additionally, the sand pocket drain lines

were found to be clogged at Dresden Units 2 and 3 when performing the initial investigation

in response to Generic Letter 87-05. When the drain lines were unclogged, there was

water present in the sand pocket region of both units. At Quad Cities, both units had three

of the four drain lines essentially dry and unplugged. This information was provided to the

NRC in response to Generic Letter 87-05 and is the only information that could be found in

the current licensing basis. Additional information provided in responses (b) through (h)

below provide justification for concluding that Dresden Unit 3 is the most limiting of the units

with respect to leakage.

3-404
(b) The design of the containment vessel Is such that margin exists between the required shell

thickness and the actual thickness of steel plate provided. A reevaluation of the required

shell thickness (based on loads and data compatible with the original certified containment

vessel stress report by Chicago Bridge & Iron Company) was performed on the containment

shell in the region of the sand pocket. The thickness of the plates in the sand pocket region

may be reduced to approximately 1/4-inch below nominal and still be within ASME Code

allowable stress limits.ln response to IE Information Notice 86-99 and NRC Generic Letter

87-05, an extensive review was conducted of the potential for drywell steel corrosion In the

area of the containment sand pocket. This review included an evaluation of the actual plate

thickness at Dresden Unit 3. Ultrasonic Test (UT) results indicated that in over 18 years of

operation of Dresden Unit 3, no detrimental corrosion occurred in the drywell steel plate at

the sand pocket level. This conclusion was further supported by the fact that all of the

thickness measurements were greater than the nominal 1.0625-inch thickness. The

initial drywell plate thickness measurements along with subsequent thickness

measurements are shown in the table below. The Initial thickness measurements

supported the conclusion that significant corrosion was not occurring.

Dresden Unit 3 Drywell Liner UT Thickness Measurements (Sand Pocket Region)

Sample

Location 1988 1997 1999 2000 2002

Measurement Measurement Measurement Measurement Measurement

Inches Inches Inches Inches Inches

1.12 1.15 1.1 1.12 1.13 112.5.1.1 A

1.12 1.12 1.09 1.08 1.09 112.5.1.1B

1.1 1.12 1.12 1.09 1.07 112.5.1.2A

1.08 1.08 1.08 1.12 1.13 112.5.1.2B

1.14 1.2 1.15 1.17 1.18 157.5.1.1A

1.14 1.16 1.14 1.15 1.11 157.5.1.1 B

1.14 1.18 1.14 1.14 1.13 157.5.1.2A

1.12 1.16 1.11 1.1 1.12 157.5.1.28

1.08 1.09 1.1 1.11 1.13 02.5.1.1A

1.08 1.1 1.08 1.1 1.11 02.5.1.1 B

1.1 1.12 1.08 1.12 1.09 2.5.1.1A

1.14 _ 1.1 1.12 1.15 1.12 .5.1.1 B

1.18 1.14 1.09 1.07 1.09 2.5.1.2A

1.1 1.12 1.1 1.06 1.04 2.5.1.28

1.18 1.16 1.1 1.08 1.1 92.5.1.1A

1.12 1.16 1.12 1.1 1.12 92.5.1.1 B

1.12 1.12 1.08 1.09 1.10 92.5.1.2A

1.26 1.12 1.12 1.14 1.15 92.5.1.2B

1.2 1.17 1.15 1.16 1.15 37.5.1.1A

1.08 1.11 1.1 1.09 1.09 37.5.1.118

1.12 1.14 1.12 1.08 1.04 37.5.1.2A

1.24 1.12 1.09 1.06 1.08 37.5.1.28

(c) In response to IE Information Notice 86-99 and NRC Generic Letter 87-05, an extensive

review was conducted of the potential for drywell steel corrosion in the area of the

containment sand pocket. This review included an evaluation of the actual plate thickness

at Dresden Unit 3. Ultrasonic Test (UT) results Indicated that in over 18 years of operation

of Dresden Unit 3, no detrimental corrosion occurred in the drywell steel plate at the sand

pocket level. This conclusion was further supported by the fact that all of the thickness

measurements were greater than the nominal 1.0625-inch thickness. These results have

been obtained in spite of the fact that substantial moisture has previously been found in the

sand pocket.

Since the as-found material thickness in Dresden Unit 3 was greater than or equal to

3-405
design thicknesses, there was no reason to expect a reduction in thickness on Dresden Unit

2. A surveillance procedure had been established to monitor sand pocket drain lines during

refuel activities and analysis of water samples taken from the lines reflected a non-corrosive

environment.

At Quad Cities, the drywell sand pocket detail is identical to the Dresden detail. The

moisture found at the [in the] sand pocket drains during inspections around the same time

period as Dresden in the late 1980s was considered negligible in comparison to Dresden

Unit 3. Therefore, it was not expected that any corrosion had occurred at either Quad Cities

unit and the ongoing surveillance program will ensure active assessment of future potential

problems. No leakage through the drywell liners was detected during the most recent refuel

outage inspections following cavity flood-up. Accordingly, Quad Cities continues to be

bounded by the routine UT results from Dresden Unit 3.

(d) No special controls exist at either station for limiting leakage. Formal inspections occur at

each station during refuel outages that monitor for leakage from the sand pocket drains

following reactor cavity flood-up. Corrective action is taken based on the results of these

inspections.

(e) The results of the last four Dresden Unit 3 drywell wall thickness measurements are

provided in the table shown above in the response to question (b). The augmented

inspection completed in October 2002 on Dresden Unit 3 was evaluated as acceptable with

no drywell liner degradation noted. The design of the containment vessel is such that

margin exists between the required shell thickness and the actual thickness of steel plate

provided. The thickness of the plates in the sand pocket region may be reduced to

approximately 1/4-inch below nominal (1.0625 inch) and still be within ASME Code

allowable stress limits. As shown in the table, all of the thickness measurements remain

above the minimum wall thickness allowed.

The augmented UT inspection for Dresden Unit 3 Is currently completed every refueling

outage. The frequency of future examinations will be evaluated based on inspection results.

This inspection was specially configured to accommodate UT inspections by drilling 22 core

holes for UT measurements. As long as Dresden Unit 3 remains the bounding condition for

corrosion potential, there is no need to drill holes and conduct routine UT measurements on

the remaining three units.

(g) A general visual inspection of the moisture barrier at the junction of the steel drywell shell and

the concrete floor is performed once each inspection period for Dresden Units 2 and 3 and

once each inspection interval for both Quad Cities units. The difference in the two inspection

periods is attributed to the ASME Section Xl Code edition in effect at each plant. Dresden

performs this inspection in accordance with the 1998 Edition of ASME Section Xl and Relief

Request MCR-02. Quad Cities performs the [inspection] In accordance with the 1992 Edition

of ASME Section Xl, 1992 Addenda, Table IWE-2500-1. The original Quad Cities drywell

moisture barriers in both units were replaced during outages in the year 2002 due to age

degradation.

(h) The concrete floor inside the drywell of all four units (1) was designed per ACI 318-63 and meets the

guidance of ACI 201.2R-77 and (2) is periodically monitored for penetrating cracks that provide a path

for water seepage, in accordance with the Structures Monitoring Program (B.1.30).

The staff's detailed evaluation of parts (a) through (f) of this RAI response is documented in the

Dresden SER Section 4.7.2.2, TLAA for Degradation Rates of Inaccessible Exterior Drywell

Plate Surfaces. The staff finds the applicant's response to parts (g) and (h) of RAI 3.5-5 to be

acceptable on the basis that it is consistent with the guidance provided in the GALL Report for

aging management of the inside surface of the embedded portion of the containment shell.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of loss of material due to corrosion in inaccessible areas of the steel

3-406
containment shell or liner plate, as recommended in the GALL report. Since the applicant's

AMR results are otherwise consistent with the GALL report, the staff finds that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

Loss of Prestress Due to Relaxation. Shrinkage. Creep, and Elevated Temperature. The GALL

Report identifies loss of prestress due to relaxation, shrinkage, creep, and elevated

temperature for PWR/BWR Mark II prestressed concrete containments as a TLAA to be

performed for the period of license renewal.

As the applicant notes in LRA Section 3.5.1.1.9, both Dresden and Quad Cities have BWR

Mark I steel containments; therefore, this aging effect does not apply.

Cumulative Fatigue Damage. If included in the CLB, fatigue analyses of containment steel liner

plates and steel containment shells (including welded joints) and penetrations (including

penetration sleeves, dissimilar metal welds, and penetration bellows) for all types of PWR and

BWR containments and BWR vent headers and downcomers are TLAAs as defined in 10 CFR

54.3. The TLAAs are required to be evaluated in accordance with 10 CFR 54.21 (c).

In LRA Section 3.5.1.1.4, the applicant states that fatigue analyses of BWR Mark I and Mark II

containment steel elements, penetration sleeves, and penetration bellows are TLAAs as

defined in 10 CFR 54.3. Dresden and Quad Cities are Mark I containments. Cumulative'

fatigue damage of BWR Mark I containment steel elements, penetration sleeves, and

penetration bellows is required to be evaluated in accordance with 10 CFR 54.21 (c). The TLAA

evaluation of cumulative fatigue damage is addressed in LRA Section 4.6. The staff evaluation

of this TLAA is addressed in SER Section 4.6.

Cracking Due to Cyclic Loading and Stress-Corrosion Cracking. The GALL Report

recommends further evaluation of programs to manage cracking of containment penetrations

(including penetration sleeves, penetration bellows, and dissimilar metal welds) due to cyclic

loading or SCC for all types of PWR/BWR containments. A similar recommendation for further

evaluation of programs to manage cracking of vent line bellows, vent headers, and

downcomers due to SCC is also provided for BWR containments. 'Containment ISI and leak

rate testing may not be sufficient to detect cracks. The staff evaluated the applicant's proposed

programs to verify that adequate inspection methods will be implemented to ensure that cracks

are detected.

In LRA Section 3.5.1.1.4, the applicant addressed cracking due to cyclic loading as a TLAA for

both Dresden and Quad Cities (see the discussion in SER Section 3.5.2.2.1). In LRA Section

3.5.1.1.5, the applicant provided the following information to address the criteria defined in the

GALL Report related to cracking due to SCC:

For Mark 1 containment steel elements and stainless steel containment penetrations (NUREG-1801, Items l.B1.1.1-d, and 11.B4.1-d), stress corrosion cracking (SCC) is a concern for

dissimilar metal welds, exposed to a corrosive environment. These components are in a sheltered

environment, outside containment and inside the reactor building, and are not exposed to a

corrosive environment. Therefore, existing requirements for Appendix J leak rate testing (B.1.28) and containment ISI plan surface inspections, in accordance with ASME Section XI, Subsection

IWE (B.1.26), are adequate to detect cracking. In addition, other factors associated with SCC with

regard to temperature, pressure, and concentrated chlorides are not at threshold levels at the

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I

installed locations.

ASME Section XI, Subsection IWE weld examination categories E-B and E-F have been removed

from the ASME Section XI, 1998 Edition. Both of these weld categories are considered to be part of

the containment boundary surface in the current Dresden Containment Inservice Inspection (CISI)

Program (ASME Section XI, Subsection IWE 1998 Edition) and Quad Cities CISI Programs and are

subject to the examination requirements of Category E-A.

Based on information provided in LRA Section 2.4 and referenced UFSAR sections, stainless

steel expansion bellows are utilized in (1) primary containment mechanical penetrations, (2)

vent line-to-suppression chamber connections, (3) the reactor vessel-to-drywell refueling seal,

and (4) the drywell-to-reactor building refueling seal. The LRA specifically identifies the

containment penetration and vent line bellows. The staff recognizes that loss of material due to

general corrosion is not an applicable aging effect for stainless steel. However, stainless steel

bellows and associated dissimilar metal welds are potentially susceptible to cracking due to

SCC when exposed to certain environmental conditions. Degradation of stainless steel bellows

has occurred at nuclear power plants; consequently, close attention to loss of intended

functions is warranted.

In LRA Section 3.5.1.1.5, the applicant has indicated that the stainless steel bellows at Dresden

and Quad Cities do not require augmented aging management beyond general visual

examination conducted under IWE Examination Category E-A and Appendix J leak rate testing.

The staff position is that the potential for cracking exists; that a crack would not be detected by

a general visual examination (i.e., VT-3) before intended function is compromised; and that

more detailed examination (e.g., IWE 1992 Examination Categories E-B and E-F) is warranted.

To complete its evaluation of the applicant's conclusion that augmented inspection of stainless

steel bellows and associated dissimilar metal welds is not necessary at Dresden and Quad

Cities, the applicant was requested, in RAI 3.5-6, to submit the following information for all

four units covered by this LRA:

(a) a detailed description of plant-specific operating experience for all stainless steel

bellows (including any not within the scope of license renewal that serve a similar

function in a similar environment), identifying all specific incidences of degradation, how

degradation was detected, the root cause, corrective actions taken, and current

inspection procedures

* (b) the environment (temperature, pressure, humidity, presence of aggressive agents) to

which stainless steel bellows are exposed, both on a continuing basis and on a periodic

or intermittent basis

(c) identification of the applicable aging effects requiring management for stainless steel

bellows at Dresden and Quad Cities

(d) the detailed technical basis, including identification of supporting reference material, for

concluding that Appendix J leak rate testing and IWE Examination Category E-A general

visual inspection are sufficient for managing aging of stainless steel bellows

In its response to RAI 3.5-6, the applicant stated the following:

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Expansion bellows are used at Quad Cities and Dresden on primary containment mechanical

penetrations, vent line-to-suppression chamber connections, on extraction steam piping that

penetrates the turbine casings, and as a refueling cavity area seal during flood up for refueling.

The Information that follows is provided to address stainless steel bellows assemblies and their

attachment welds.

(a) The refueling bellows are made of stainless steel and are not in scope of license renewal.

Justification for excluding the refueling bellows from the scope of license renewal Is discussed

in the response to RAI 2.4.3. The refueling bellows experience a different environment and

have a different function. As such, they are excluded from further discussion.

Extraction steam piping bellows are made of Inconel and experience different environments

than the primary containment penetration bellows. Additionally, the extraction steam piping

bellows are not included in the scope of license renewal. For these reasons, they are

excluded from further discussion.

Expansion bellows are installed on the Dresden and Quad Cities primary containment

mechanical penetrations on the following process lines. The list includes the vent

line-to-suppression chamber connections. All of the mechanical penetration expansion

bellows are in scope of license renewal.

(1) Main Steam (4 per unit)

(2) Steam Une Drain (1 per unit)

(3) Feedwater (2 per unit)

(4) RCIC Steam Supply (1 per unit, at Quad Cities only)

(5) Isolation Condenser Steam Supply (1 per unit, at Dresden only)

(6) Isolation Condenser Condensate (2 per unit, at Dresden only)

(7) Shutdown Cooling Suction (2 per unit, at Dresden only)

(8) RHR Suction from Reactor (1 per unit, at Quad Cities only)

(9) LPCI Injection (2 per unit, at Dresden only)

(10) RHR Injection (2 per unit, at Quad Cities only)

(11) Reactor Water Clean Up Supply (1 per unit)

(12) HPCI Steam Supply (1 per unit)

(13) RBCCW Supply (1 per unit)

(14) RBCCW Return (1 per unit)

(15) Vent from Drywell (1 per unit)

(16) Vent to Drywell (1 per unit)

(17) Core Spray Injection (2 per unit)

(18) Standby Uquid Control Injection (1 per unit)

(19) Head spray (1 per unit, at Dresden only)

(20) Drywell to Suppression Chamber Vent Unes (8 per unit)

There have been no recordable Indications identified on any bellows assemblies or

attachment welds at either Dresden or Quad Cities utilizing Examination Category E-A,

Containment Surfaces, of ASME Boiler and Pressure Vessel Code, Subsection IWE.

Degradation was detected on 16 bellows assemblies at Dresden and 8 bellows assemblies at

Quad Cities over the history of plant operation while conducting 10 CFR Part 50, Appendix J,

testing. The degradation was significant enough to require bellows replacement. Fifteen of

the 16 degraded bellows assemblies at Dresden were replaced. One penetration with a

degraded bellows assembly at Dresden was sealed inside containment as part of an unrelated

modification to remove the return line to the vessel for the control rod drive water. For this

reason, replacement of the sixteenth bellows was unnecessary. The eight degraded bellows

assemblies at Quad Cities were replaced.

The root cause of the bellows assembly degradation was attributed to cracking due to

transgranular stress corrosion cracking (TGSCC). Several degraded bellows that were

replaced were metallurgically analyzed. Quad Cities Unit 1 X-16A bellows, replaced in 1984,

was found to be contaminated with magnesium salts.' The corrosive species responsible for

the crack initiation on Quad Cities Unit 1 X-25 bellows was identified as chlorides, fluorides,

and sulfides. Since operating conditions do not introduce these materials, it has been

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concluded they were most probably introduced during construction. Additionally, the method

of bellows manufacturing introduces residual stresses in the bellows. Bellows are cold-formed

from cylinders fabricated from sheet stainless steel.

A listing of identified degraded bellows assemblies, Unit, and date replaced is provided below.

A discussion of current inspection procedures is included in part (d) to this question.

enetration at, Unit

-113 (Reactor Water Clean eptember, 1990 resden, Unit 2

p Supply)

-105A (Main Steam) ecember, 1991 resden, Unit 3

-107B (Feedwater) arch,1992 resden, Unit 3

-125 (Vent from Drywell) ay,1993 resden, Unit 2

-149A (Core spray Injection) ay, 1993 resden, Unit 2

-149B (Core Spray Injection) ay,1993 resden, Unit 2

-144 (Control Rod Drive ealed inside drywell resden, Unit 2

ater Retum)

-11 1A (Shutdown Cooling y, 1994 resden, Unit 3

uction)

-125 (Vent from Drywell) y, 1994 resden, Unit 3

-138 (Standby Uquid Control ay, 1994 resden, Unit 3

niectio n ) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

-149B (Core Spray Injection) ay, 1994 resden, Unit 3

-108A (Isolation Condenser ebruary, 1997 resden, Unit 2

team Supply)

-116A (LPCI Injection) ebruary, 1997 resden, Unit 2

X-126 (Vent to Drywell) February,1997 resden, Unit 2

-116B (LPCI Injection) anuary 2003 resden, Unit 2

-124 (RBCCW Retur) anuary,2003 resden, Unit 2

-16B (Core Spray Injection) eptember, 1983 uad Cities, Unit 2

-16A (Core Spray Injection) eptember, 1984 uad Cities, Unit 1

-16B (Core Spray Injection) ovember, 1989 uad Cities, Unit 1

-12 (RHR Suction from arch, 1991 uad Cities, Unit 1

eactor)

-25 (Vent from Drywell) arch, 1991 uad Cities, Unit 1

X-14 (Reactor Water Clean ay, 1993 uad Cities, Unit 2

p Supply) _

-7B (Main Steam) ugust, 1994 uad Cities, Unit 1

-12 (RHR Suction from ecember, 1996 uad Cities, Unit 2

eactor) _

(b) The bellows assemblies are exposed to two environments; inside containment (either drywell

or suppression chamber air space) on the inner surface of the bellows, and outside

containment on the outer surface of the bellows. Neither environment contains aggressive

agents. The environments are further described as follows.

Inside Containment

The drywell is made inert with nitrogen to render the primary containment atmosphere non-flammable

by maintaining the oxygen content below 4% by volume during normal operation. The drywell has an

average temperature of 135 F during normal operations. The relative humidity in the drywell ranges

from 20% - 90%. During normal operation, the drywell pressure is maintained at approximately one

psig. The suppression chamber air space above the water level, is also inerted to maintain the oxygen

content below 4% by volume during normal operation. The air temperature follows the normal,

maximum operating suppression chamber water temperature of 95 F and the relative humidity is

between 20 and 90%. During normal operation, the suppression chamber pressure is maintained at

approximately zero psig. Periodically, each entire containment is subjected to a pressure of 48 psig

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during the performance of a 10 CFR Part 50, Appendix J, Type A, Primary Containment Integrated

Leak Rate Test (ILRT).

Outside Containment

The Reactor Building (outside the drywell, suppression chamber, and steam tunnel) normal operating

area temperatures range from 65 F to 103 F for Dresden and 65 0F to 104 'F for Quad Cities, with

relative humidity ranging from 20% - 90%.

(a) The applicable aging effects requiring management for stainless steel bellows assemblies at

Dresden and Quad Cities are cumulative fatigue damage (NUREG 1801 line ll.B4.1-b and

LRA Reference 3.5.1.1) and crack Initiation and growth due to SCC (NUREG 1801 line

Il.B4.1-d and LRA Reference 3.5.1.2).

(b) Based on Dresden and Quad Cities operating experience, there Is potential for cracking in the bellows

assemblies, but not in the dissimilar welds associated with the assemblies. 10 CFR Part 50, Appendix

J testing has been effective in Identifying past bellows assembly degradation due to cracking.

The primary containment mechanical penetration expansion bellows assemblies originally

Installed at Quad Cities and Dresden were each constructed of two-plies of Type 304

Stainless Steel, formed together into a cylindrical corrugated bellows assembly. 10 CFR Part

50, Appendix J Type B LLRT testing was performed on them by pressurizing the volume

between the plies. In 1990, Quad Cities discovered that it was not always possible to quantify

the bellows assembly leakage rate due to the design and construction of the bellows

assemblies. This was reported to the NRC by Exelon and then communicated by the NRC to

the industry in IN 92-20. An exemption for certain Type B LLRT testing requirements for Quad

Cities and Dresden was requested from the NRC In 1991 and was granted In February, 1992.

A revision to the exemption was requested In October 1994, and was granted in February

1995. The exemptions apply to the original two-ply bellows assemblies. As they are replaced,

the new bellows fall under the full Type B LLRT testing requirements.

Replacement bellows are single ply. This ply becomes the primary containment pressure

boundary. Transition rings are added to the bellows assemblies to allow for the installation of

an outer bellows over the first one. The installation of this outer bellows allows for the

performance of a Type B LLRT test. Replacement bellows are cold-formed during

fabrication, as were the original bellows. To minimize the potential for contamination,

installation instructions for the replacement bellows include cleaning the entire outer surface

of the inner bellows after welding of the transition rings, and cleaning of the entire inner and

outer surfaces of the outer bellows before it is welded.

Degraded bellows assemblies identified since 1991 were identified utilizing the methodology

developed to comply with the exemptions. Briefly, this testing methodology is:

(a) All two-ply bellows assemblies are pressurized between the plies. Any bellows assembly with

leakage measuring 0.5 scfh are further tested with helium.

(b) The bellows assembly is pressurized between the plies with helium, and the inner and outer

plies are sniffed with a helium sniff detector.

(c) If helium is detected through both plies, the outer ply is examined with penetrant and/or snoop

testing. All flaws are measured and mapped.

(d) All indications are evaluated by Engineering to assess current and projected leakage rates,

and for structural integrity.

(e) The 1992 exemption required a Type A ILRT upon completion of all two-ply testing. The 1995

revision provides the option of performing a test in accordance with Type B LLRT

requirements on all bellows assemblies with leaks through both plies, or performing a Type A

ILRT.

(D) The 1992 exemption required that all two-ply bellows assemblies with demonstrated leakage

through both plies be replaced during the subsequent refueling outage. There is reasonable

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I

assurance that the leaking bellows assemblies will not degrade excessively during this period

because TGSCC is characterized by the slow development and propagation of cracks. The

1995 revision provides the option of performing a test in accordance with Type B LLRT

requirements to demonstrate license limits are met or replacing the bellows assemblies. The

bellows assembly welds at Dresden and Quad Cities are inspected utilizing Examination

Category E-A, Containment Surfaces, of ASME Boiler and Pressure Vessel Code, Subsection

IWE.

Based on the applicant's response to part (a) of this RAI, there are a total of 120 bellows within

the scope of license renewal (32 for each Dresden unit; 28 for each Quad Cities unit). Of the

120 total, 24 bellows have been identified as degraded due to transgranular stress-corrosion

cracking (TGSCC) over the period September 1990 through January 2003 and have been

replaced (23) or taken out of service (1). The applicant states in part (d) of its response,

'Degraded bellows assemblies identified since 1991 were identified utilizing the methodology

developed to comply with the exemptions.'

Since there are 96 original bellows still in place, and the period of extended operation will begin

in approximately 10 years, it is not clear to the staff that reliance on Appendix J Leak Rate

Testing and IWE Examination Category E-A to manage aging for license renewal is sufficient,

without an additional commitment to continue the pressurized testing methodology described in

(1) through (6) under part (d) of the RAI response. In a letter dated December 5, 2003, the

applicant stated that it would credit the pressurized testing methodology summarized above in

steps (1) through (6) under part (d) of the RAI 3.5.6 response for aging management of bellows

during the period of extended operation. This is part of Commitment #26 in Appendix A of this

SER. The staff finds the applicant's response acceptable and considers RAI 3.5-6 resolved.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of cracking due to cyclic loading and SCC, as recommended in the

GALL report. Since the applicant's AMR results are otherwise consistent with the GALL report,

the staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

Conclusions. The staff has reviewed the applicant's evaluation of the issues for which the

GALL Report recommends further evaluation of structural components in containment. On the

basis of its review, the staff finds that the applicant has provided sufficient information to

demonstrate that the issues for which the GALL Report recommends further evaluation have

been adequately addressed and that the subject aging effects will be adequately managed for

the period of extended operation.

3.5.2.2.2 Class I Structures

Aging of Structures Not Covered by Structures Monitoring Program. The GALL Report

recommends further evaluation of certain structure/aging effect combinations if they are not

covered by the Structures Monitoring Program. This includes (1) scaling, cracking, and spalling

due to repeated freeze-thaw for Groups 1-3, 5 and 7-9 structures; (2) scaling, cracking,

spalling, and increase in porosity and permeability due to leaching of calcium hydroxide and

aggressive chemical attack for Groups 1-5 and 7-9 structures; (3) expansion and cracking due

to reaction with aggregates for Groups 1-5 and 7-9 structures; (4) cracking, spalling, loss of

bond, and loss of material due to corrosion of embedded steel for Groups 1-5 and 7-9

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structures; (5) cracks, distortion, and increase in component stress level due to settlement for

Groups 1-3, 5 and 7-9 structures; (6) reduction of foundation strength due to erosion of porous

concrete subfoundation for Groups 1-3 and 5-9 structures; (7) loss of material due to corrosion

of structural steel components for Groups 1-5 and 7-8 structures; (8) loss of strength and

modulus of concrete structures due to elevated temperatures for Groups 1-5 structures; and

(9) crack initiation and growth due to SCC and loss of material due to crevice corrosion of

stainless steel liner for Groups 7 and 8 structures. Further evaluation is necessary only for

structure/aging effect combinations not covered by the Structures Monitoring Program.

Technical details of the aging management issue are presented in SER Section 3.5.2.2.1 for

items (5), (6) and (8).

The applicant stated in LRA Section 3.5.1.1.6 that the Structures Monitoring Program (B.1.30)

is required to manage the following structural aging effects for accessible concrete areas:

* loss of material and cracking due to freeze-thaw of concrete

* increase in porosity and permeability and loss of strength due to leaching of calcium

hydroxide of concrete

* increase in porosity and permeability, cracking, and loss of material (spalling, scaling) due

to aggressive chemical attack of concrete

* expansion and cracking due to reaction with aggregates of concrete

* cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded

steel [in] concrete

The applicant has included inspection of accessible concrete areas in the scope of its

Structures Monitoring Program; therefore, the GALL Report recommends no further evaluation.

In LRA Section 3.5.1.1.6, the applicant also stated that no aging management is required for

inaccessible areas:

1. For loss of material and cracking due to freeze-thaw of concrete in Inaccessible areas, no

aging management is required. Dresden and Quad Cities are located in severe weathering conditions. Dresden and Quad Cities have documented evidence to show that the concrete

air content is between 3% and 6%. Plant inspections did not show freeze-thaw degradation. Therefore, loss of material and cracking due to freeze-thaw of concrete in inaccessible areas

are not applicable and no aging management is require.

2. For increase in porosity and permeability and loss of strength due to leaching of calcium hydroxide of

concrete in inaccessible areas, no plant-specific aging management is required. Dresden and Quad

Cities concrete is not exposed to flowing water and there is documented evidence that the concrete

used was constructed in accordance with the recommendations in ACI 201.2R-77 for durability. Therefore, Increase in porosity and permeability and loss of strength due to leaching of calcium

hydroxide of concrete in inaccessible areas are not applicable and no plant-specific aging management

is required.

3. For expansion and cracking due to reaction with aggregates of concrete in inaccessible areas, no

aging management is required. Dresden and Quad Cities documented evidence demonstrates that the

concrete used meets the requirements of ACI 201.2R-77 with no evidence of reactive aggregates. Therefore, expansion and cracking due to reaction with aggregates of concrete in inaccessible areas

are not applicable and no aging management is required.

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4. For the drywell radial beam lubrite baseplates, aging management of loss of material due to galvanic

corrosion, lock-up or wear of lubrite baseplates will be performed by One-Time Inspection (B.1.23).

The torus saddle support lubrite baseplates will be visually inspected to verify unacceptable loss of

material due to galvanic corrosion, lock-up or wear has not occurred. The drywell radial beam lubrite

baseplates and torus saddle support lubrite baseplates are comprised of the same materials and are

exposed to similar environments. The drywell radial beam lubrite baseplates are not accessible for

inspection; therefore the inspection of the torus saddle support lubrite baseplates will be used as a

representative inspection for aging of the drywell radial beam lubrite baseplates.

The staff finds that the technical bases for the conclusions in items (1) through (3) above are

consistent with the GALL Report and, therefore, require no further evaluation.

Concerning loss of material in drywell radial beam lubrite baseplates (item (4) above), the staff

requested, in RAI 3.5-7, the following additional information:

(a) Describe the prior operating experience of the torus saddle support lubrite baseplates.

Under what program have they been inspected? Are lubrite baseplates used at any other

locations in Dresden and Quad Cities? If so, what has been the operating experience?

(b) The torus saddle support lubrite baseplates are covered under GALL Item IlIl B1.3.2-a, and

it is expected that they would be managed by ASME Section Xl, Subsection IWF. This

GALL item is part of LRA Table 3.5-1, Reference No. 3.5.1.31, which states that Dresden

and Quad Cities is consistent with GALL, with one exception. The only exception discussed

in LRA Table 3.5-1 for this item pertains to aging of downcomer bracing. Explain why aging

management of loss of material due to galvanic corrosion, lockup or wear of the torus

saddle support lubrite baseplates will be performed by One-Time Inspection (B.1.23) and

not by ASME Section Xl, Subsection IWF (B.1.27).

(c) What is the sample size for the inspection of the torus saddle support lubrite baseplates that

will be used to confirm the condition of the inaccessible drywell radial beam lubrite

baseplates?

(d) Confirm that all radial beam lubrite baseplates inside the drywell are inaccessible, and

explain the conditions that make them inaccessible.

(e) Discuss the environments that the torus saddle support lubrite baseplates and the drywell

radial beam lubrite baseplates are exposed to and explain why they are considered to be

similar.

In its response to RAI 3.5-7, the applicant stated the following:

Exelon has reviewed the LRA Section 3.5.1.1.6 and the following additional information is provided for

clarification.

(a) The torus saddle support lubrite baseplates have not been inspected to date and are

currently not included in the ASME Section Xl, Subsection IWF aging management

program. Exelon will revise this program to include the torus saddle support lubrite

baseplates. However, this program will not be revised before the end of the current

10-year ISI program interval expires. To ensure that a baseline inspection is performed

before the current operating license expires, a one-time inspection of the torus saddle

support lubrite baseplates will be performed. This initial inspection will be performed

under aging management program, B.1.23, One-Time Inspection. It will be replaced by

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aging management program B.1.7, ASME Section Xl, Subsection IWF, once it has'been

revised and approved by the NRC.

A historical review of the Exelon corrective action program did not identify any problems with the

torus saddle support lubrite baseplates. These plates are used on the torus column supports and

other piping systems and component supports to reduce friction between sliding supports and the

bearing plates.

(b) As stated above in item (a), torus saddle support lubrite baseplates will be managed by

ASME Section Xl, Subsection IWF, and are addressed under NUREG 1801 Item

Ill.B.1.3.1-a In the aging management review: The torus saddle support lubrite

baseplates are addressed in LRA Section 2.4.15, Table 2.4-15, under Component Group

wSliding Surfaces. LRA Table 3.5-1, Aging Management Reference 3.5.1.31, discusses

the aging management of the saddle support lubrite baseplate. A sample of the torus

saddle support lubrite baseplates has been selected for a one time Inspection that Is

representative of the inaccessible drywell radial beam'lubrite baseplates. The lubrite

baseplates are addressed In LRA Section 2.4.1, Table 2.4-1, under Component Group

"Beam Seats requiring aging management.

(c) The one-time inspection of the torus saddle support lubrite baseplate sample will consist

of one saddle support baseplate located in a dry area of the Reactor Building basement.

An additional Inspection will be performed on a saddle support lubrite baseplate in an

area that has experienced water exposure, If such a location can be found. Otherwise, a

second dry area inspection will be performed.'

(d) The drywell lubrite bearing plates are hidden behind the base plates of the radial floor

beams located on the main floor of the drywell. These radial floor beams are located

between the reactor vessel biological shield and the drywell shell and provide structural

support for the main floor grating and major components located on that elevation. -

Removal of the radial floor beams would jeopardize the structural integrity of the attached

equipment. For this reason, the primary containment radial lubrite beams are considered

inaccessible.

(e) The drywell radial beam lubrite baseplates are exposed to the Inside Drywell

Environment. The drywell is made inert with nitrogen to render the primary containment

atmosphere non-flammable by maintaining the oxygen content below 4% by volume

during normal operation. The drywell has an average temperature of 135 'F during

normal operation. The relative humidity in the drywell ranges from 20% - 90%.

The torus saddle support lubrite baseplates are exposed to the Outside Drywell

Environment which Is identical to that found in the Reactor Building. The Reactor Building

(which includes the area containing the torus saddle supports) normal operating area

temperatures range from 65 F to 103 F for Dresden and 65 F to 104 F for Quad Cities

with relative humidity ranging from 20% - 90%.'

The drywell radial beam lubrite baseplates are exposed to a milder environment than the

torus saddle support lubrite baseplates because of the lack of oxygen in the

nitrogen-inerted environment. The temperature of the Inside Drywell Environment Is

constant during power operation, reducing the likelihood of condensation accumulation on

the steel components. The higher temperature itself is not detrimental to the steel

components. For this reason, the torus saddle support lubrite baseplates are considered

to be representative and bounding of the drywell radial beam lubrite base plates.

Given the inaccessibility of the radial beam seats, the staff considers the applicant's approach

to be an acceptable alternative to direct inspection. This is part of Commitment #23 of

Appendix A of this SER. Therefore,'RAI 3.5-7 is resolved.

The 'Discussion column of LRA Table 3.5-1, Reference No. 3.5.1.20, states that "Dresden and

Quad Cities do not use stainless steel lined, carbon steel tanks as evaluated in NUREG-1801,

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line IlI.A8.2-a." The staff notes that NUREG-1801, line IlIl A8.2-a, addresses loss of material

due to corrosion for unlined carbon steel tanks, and that NUREG-1 801, line IlIl A8.2-b,

addresses stainless steel liners in steel tanks. The 'Discussion' column of LRA Table 3.5-1,

Reference No.3.5.1.28, states that 'Dresden and Quad Cities do not use steel tanks lined with

stainless as identified in NUREG-1801, line IlI.A8.2-b."

Based on the information provided in LRA Table 3.5-1, the staff cannot determine (1) whether

any unlined carbon steel tanks are included in the license renewal scope; and (2) if so, where

the AMR results are located in the LRA. The applicant was requested in RAI 3.5.8 to identify

any unlined carbon steel tanks in the license renewal scope and, if applicable, to describe the

AMR and the credited AMPs.-

In its response to RAI 3.5-8, the applicant stated the following:

The statement 'Dresden and Quad Cities do not use stainless steel lined, carbon steel tanks as

evaluated in NUREG-1801, line 1lI.A8.2-a in LRA Table 3.5-1, Aging Management Reference

3.5.1.20, was inadvertently placed in this line entry.

Tanks are evaluated with the primary system in which they were installed. Some examples of

carbon steel tanks can be found in LRA Table 2.3.2-1, High Pressure Coolant Injection, LRA Table

2.3.2-3. Containment Isolation Components and Primary Containment Piping System, and LRA

Table 2.3.3-6, Emergency Diesel Generator and Auxiliaries. None of the LRA Chapter 2

component tables requiring aging management containing tanks are linked to Chapter 3 Aging

Management Reference 3.5.1.20.

In its RAI response, the applicant also identified a revision to LRA Table 3.5.1, Reference No.

3.5.1.20, removing the statement in the "Discussion" column. The staff verified that all tanks

are evaluated with the primary system in which they are installed, and that there are no AMR

references to entry 3.5.1.20 in LRA Table 3.5-1. This review confirmed the applicants

assertion that, with one exception, the Radwaste Floor Drain Surge Tank is included in the

structures scope (LRA Section 2.4.9) and is evaluated as a structure (AMR reference LRA

Table 3.5-1). Therefore, RAI 3.5-8 is resolved.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of aging of structures not covered by the Structures Monitoring Program,

as recommended in the GALL report. Since the applicant's AMR results are otherwise

consistent with the GALL report, the staff finds that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by 10 CFR

54.21 (a)(3).

Agina Management of Inaccessible Areas. The GALL Report recommends further evaluation of

aging management for inaccessible concrete areas, such as foundation and exterior walls

below grade exposed to ground water, if specific criteria defined in the GALL Report cannot be

satisfied. The staff reviewed the AMP to ensure that the intended functions will be maintained

during the period of extended operation. The degradations managed are cracking, spalling,

and increases in porosity and permeability due to aggressive chemical attack; and cracking,

spalling, loss of bond, and loss of material due to corrosion of embedded steel for Group 1- 3,

5, and 7-9 structures.

In LRA Section 3.5.1.1.7, the applicant stated that no plant-specific aging management is

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required to manage the following structural aging effects for inacbessible areas:

* Increase in porosity and permeability, cracking, and loss of material (spalling, scaling) due to

aggressive chemical attack of concrete

* cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel

of concrete.

To support this conclusion, the applicant states in LRA Section 3.5.1.1.7 that Dresden and

Quad Cities ground- water test data obtained during construction, and for the 1980's, 1990's,

and 2000's shows that the below-grade environment is not aggressive based on NUREG-1 801

criteria (chlorides less than 500 ppm, sulfates less than 1500 ppm, and pH greater than 5.5).

Examination of representative samples of below- grade concrete, when excavated for any

reason, is included as part of the Structures Monitoring Program. To ensure conditions are

maintained throughout the period of extended operations, the Structures Monitoring Program

will be enhanced to include monitoring of below-grade water chemistry to demonstrate that the

environment remains non-aggressive. Existing plant procedures will be used to periodically

sample pH, chlorides, and sulfates.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of aging management of inaccessible areas, as recommended in the

GALL report. Since the applicant's AMR results are otherwise consistent with the GALL report,

the staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

Conclusions. The staff has reviewed the applicant's evaluation of the issues for which the

GALL Report recommends further evaluation of Class I structures. On the basis of its review,

the staff finds that the applicant has provided sufficient information to demonstrate that the

issues for which the GALL Report recommends further evaluation have been adequately

addressed and that the subject aging effects will be adequately managed for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.2.3 Component Supports

Aging of Supports Not Covered by Structures Monitoring Program. The GALL Report

recommends further evaluation of certain component support/aging effect combinations if they

are not covered by the Structures Monitoring Program. This includes (1) reduction in concrete

anchor capacity due to degradation of the surrounding concrete, for Groups BI -B5 supports;

(2) loss of material due to environmental corrosion, for Groups B2 - 85 supports; and (3)

reduction/loss of isolation function due to degradation of vibration isolation elements, for Group

B4 supports. Further evaluation is necessary only for structure/aging effect combinations that

are not covered by the Structures Monitoring Program.

The applicant addressed the above criterion defined in the GALL Report, regarding the need for

further evaluation to manage the potential aging of component supports, in LRA Table 3.5-1. In

row entry 3.5.1.29 of LRA Table 3.5-1, the applicant stated that it will use its Structures

Monitoring Program to manage the aging effects identified above in the preceding paragraph.

Since the applicant is managing the aging effect for the component supports covered by row

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entry 3.5.1.29 of LRA Table 3.5-1, as recommended by the GALL Report, the staff finds that

the applicant has adequately addressed this further evaluation criterion. The staff's evaluation

of the applicant's Structures Monitoring Program is found in Section 3.0.3.14 of this SER.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of aging of supports not cover by the Structures Monitoring Program, as

recommended in the GALL report. Since the applicant's AMR results are otherwise consistent

with the GALL report, the staff finds that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

Cumulative Fatigue Damage due to Cyclic Loadina. Fatigue of support members, anchor bolts,

and welds for Groups B1.1, B1.2, and B1.3 component supports is a TLAA as defined in 10

CFR 54.3, only if a CLB fatigue analysis exists. The TLAAs are required to be evaluated in

accordance with 10 CFR 54.21 (c).

In LRA Section 3.5.1.1.8, the applicant states that Dresden and Quad Cities piping and

component supports were designed to ASME Section VIII and ANSI USAS B31.1. Dresden

Unit 3 ASME IlIl Class I replacement piping was analyzed to Subsection NB, 1980 Edition

including Summer 1982 Addenda. None of these codes required formal fatigue analysis of

supports or design of supports for fatigue effects. Some ASME IlIl Class MC support

components were the subject of fatigue analysis in support of the Mark I "New Loads" program.

Cumulative fatigue damage of ASME IlIl Class MC support components is required to be

evaluated in accordance with 10 CFR 54.21 (c)(1). The TLAA evaluation of the ASME IlIl Class

MC support components is addressed in LRA Section 4.6. The staff's evaluation of this TLAA

is in DSER Section 4.6 of this SER.

Conclusions. The staff has reviewed the applicant's evaluation of the issues for which the

GALL Report recommends further evaluation for component supports. On the basis of its

review, the staff finds that the applicant has provided sufficient information to demonstrate that

the issues for which the GALL Report recommends further evaluation have been adequately

addressed and that the subject aging effects will be adequately managed for the period of

extended operation.

3.5.2.3 Aging Management Programs for Containment, Structures, and Component Supports

In LRA Section 3.5, the applicant credits a total of 10 AMPs to manage the aging effects

associated with structures and structural components. Five of the AMPs are credited with

managing aging for components in other system groups (common AMPs); and five AMPs are

credited with managing aging only for structures and structural components. The staff's

evaluations of the common AMPs are provided in the following sections of this SER:

* Water Chemistry Program (B.1.2)-(Section 3.0.3.2)

* Bolting Integrity Program (B.1.12)-(Section 3.0.3.5)

* One-Time Inspection Program (B.1.23) -(Section 3.0.3.1 0)

* Appendix J, Containment Leak Rate Test Program (B.1.28)-(Section 3.0.3.13)

* Structures Monitoring Program (B.1.30)-(Section 3.0.3.14)

The staff's evaluations of the five AMPs credited with managing aging only for the containment,

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structures, and component supports are provided in this section of the SER.

3.5.2.3.1 ASME Section Xl, Subsection IWE (B.1.26)

Summary of Technical Information in the ApDlication. The Quad Cities program complies with

Subsection IWE for steel containments (Class MC) of ASME Section XI, 1992 Edition including

1992 Addenda. The Dresden program utilizes a relief request. The relief request permits

utilization of the 1998 Edition of Subsection IWE of ASME Section Xl in its entirety instead of

the 1992 Edition and Addenda. The applicant states that the ASME Section XI, Subsection

IWE aging management program is consistent with the ten elements of aging management

program XI.S1 *ASME Section Xl, Subsection IWE,u specified in NUREG-1 801 (GALL), with

the following exceptions:

NUREG-1 801 indicates that ASME Section Xl, Subsection IWE and the additional

requirements specified in 10 CFR 50.55a(b)(2) constitute an existing mandated program

applicable to managing aging of a steel containment. The NUREG-1 801 evaluation

covers both the 1992 Edition with the 1992 Addenda and the 1995 Edition with the 1996

Addenda of ASME Section Xl, Subsection IWE, as approved in 10 CFR 50.55a. The

Dresden program utilizes a relief request. The Dresden program is based on the 1998

Edition of Subsection IWE of ASME Section Xl as provided for in Relief Request

MCR-02.

, * NUREG-1801 indicates that pressure retaining weld visual examinations and pressure

! retaining dissimilar metal welds surface examinations are optional. These requirements

are not part of the Dresden program because it is based on the 1998 Edition of

Subsection IWE of ASME Section Xl as provided for in Relief Request MCR-02.

* NUREG-1 801 indicates that bolt preload is checked by either a torque or tension test.

The Dresden and Quad Cities programs do not provide for checking of bolt preload by

either torque or tension test because acceptance is based on Appendix J testing of

associated bolted components and general visual examination. This practice is

consistent with Dresden Relief Request MCR-02 and Quad Cities Relief Request

CR-24.

* NUREG-1801 indicates that the program provides for examination of seals, gaskets and

moisture barriers by visual methods prescribed in ASME Section Xl, Subsection IWE

* The Dresden program uses Relief Request MCR-02 and the Quad Cities program uses

Relief Request CR-21 as the basis for not routinely inspecting seals and gaskets, and

the extent of surface examination of moisture barriers. Aging management program 10

CFR Part 50, Appendix J (B.1.28) provides for monitoring of seals and gaskets. Seals

and gaskets are inspected only when sealed or gasketed components are disassembled

for maintenance. Moisture barriers, which are accessible, are examined for tears, cracks

or other damage that would allow intrusion of moisture, using general visual criteria.

As described in LRA Section B.1.26, the ASME Section Xl, Subsection IWE aging management

program is credited with managing aging of the primary containment for loss of material. The

basic program requires visual examination. Limited surface or volumetric examination is

conducted when IWE requires augmented examination. It is implemented through station plans

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and procedures and covers steel containment shells and their integral attachments;

containment hatches and airlocks; seals, gaskets and moisture barriers; and pressure-retaining

bolting.

The applicant stated that the operating experience of the inservice inspection (ISI) programs at

Dresden and Quad Cities, which includes ASME Code, Section Xl, Subsection IWE aging

management program activities, has not shown any adverse trend of program performance.

Periodic self-assessments of the ISI programs have been performed to identify the areas that

need improvement to maintain program quality.

Inspections were conducted on Dresden Unit 3 drywell in response to NRC Generic Letter (GL)

87-05, "Request for Additional Information Assessment of Licensee Measures to Mitigate and/

or Identify Degradation of Mark I Drywells," and Information Notice 86-99, "Degradation of Steel

Containments," which addressed the potential for corrosion of boiling water reactor (BWR) Mark

I steel drywells in the "sand pocket region." The results of these inspections and analysis of the

results concluded that ultrasonic examinations showed evidence of no apparent corrosion of

liner in the "sand pocket region." The conclusions were found to also apply to Dresden Unit 2

and both Quad Cities units, as Dresden Unit 3 conditions were determined to be bounding

based on more occasions of moisture in its sand pocket region. Dresden Unit 3 has

experienced leakage from the drywell sand pocket drains during refueling outages in 1997 and

2000. As a result, an augmented UT inspection of the Unit 3 drywell sand pocket area is

scheduled for the second half of 2002.

The applicant concluded that the ASME Code, Section Xl, Subsection IWE aging management

program provides reasonable assurance that the loss of material aging effects are adequately

managed so that the intended functions of primary containment components are maintained

during the period of extended operation.

Staff Evaluation. In LRA Section B.1.26, 'ASME Section Xl, Subsection IWE", the applicant

described its AMP to manage aging of the steel containment. The LRA stated that this AMP is

consistent with GALL AMP XI.S1, with the exceptions described above in Section 3.5.2.3.1 of

this report. The staff confirmed the applicant's claim of consistency during the AMR inspection.

Furthermore, the staff reviewed the exceptions to determine whether the AMP, with the

exceptions, remains adequate to manage the aging effects for which it is credited. In addition,

the staff determined whether the applicant properly applied the GALL program to its facility. The

staff also reviewed the UFSAR supplements for both Dresden and Quad Cities to determine

whether they provide an adequate description of the revised program.

The staff notes that the exceptions described by the applicant are different for Dresden and for

Quad Cities; and for each exception, the applicant references a current Relief Request granted

by the staff.

The staff position is that current Relief Requests granted by the staff have no bearing on

License Renewal commitments, because the basis for the relief request and the period of time

during which the relief request is applicable generally will not carry over to the period of

extended operation. Consequently, for license renewal the staff expects a commitment to IWE

and supplemental requirements consistent with 10 CFR 50.55a. The staff notes that 10 CFR

50.55a was updated in 2002 to include the 1998 edition with the 1999 and 2000 Addenda of

Subsection IWE, with the additional requirements of paragraphs (b)(2)(ix) (A), (B), and (F)

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through (I).

Therefore, the applicant was requested in RAI B.1.26 to (1) describe the extent of its

commitment to the IWE requirements specified in the most recent issuance of 10 CFR 50.55a;

(2) specifically identify any exceptions takern'to these requirements, for the extended period of

operation; and (3) submit a detailed technical basis for each exception taken.

In its response to RAI B.1.26 dated October 3, 2002, the applicant stated:

LRA Appendix B.1.26 describes the current 'ASME Section Xl, Subsection IWE' aging

management program and its exceptions as defined by Relief Requests. This program was

developed In response to the August 8, 1996 Federal Register posting of the final rulemaking,

mandating a comprehensive containment Inservice inspection program. This program is valid for

120-month inspection interval. At the end of this 120-month interval, the program must be updated

to comply with 10 CFR 50.55a(g)(4)(ii).

Exelon agrees that the current Relief Requests do not have a bearing on the period of extended

operation. Based on the requirements of 10 CFR 50.55a(g)(4)(ii), the program will be based on

the latest edition and addenda, which Is approved by the NRC 12 months prior to the end of the

current 120-month inspection Interval.

Based on these requirements, the program will be updated by 2008 (prior to the beginning of the

extended period of operation) and then again by 2018 and 2028 (both during the period of

extended operation).

Exelon will continue to follow the regulations as established in 10 CFR 50.55a, which include a

commitment to IWE and the established supplemental requirements.

The additional information provided by the applicant in its RAI response is consistent with the

staff's position on Relief Requests. The staff accepts the applicant's commitment for license

renewal to IWE and supplemental requirements'consistent with 1 OCFR50.55a. This is part of

Commitment #26 in Appendix A of this SER.

Conclusions. On the basis of its review and audit of the applicants program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. In addition, the staff has reviewed the

exceptions to the GALL program and finds that the applicant has demonstrated that the effects

of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB during the' period of extended operation, as required by 10 CFR

54.21 (a)(3). The staff also reviewed the UFSAR supplement for this AMP and finds that it

provides an adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.5.2.3.2 ASME Section Xl, Subsection IWF (B.1.27)

Summary of Technical Information in the Application. The applicant stated in LRA Section

B.1.27 that, with enhancements, the ASME Section Xl, Subsection IWF aging management

program is consistent with the ten elements of aging management program XI.S3, "ASME

Section Xl, Subsection IWF," specified in NUREG-1801.

The ASME Code, Section Xl, Subsection IWF aging management program is credited for visual

examination of component and piping supports within the scope of license renewal for loss of

material and loss of mechanical function aging effects. The program is implemented through

station procedures, which provide for visual examination of inservice inspection Class 1, 2, and

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3 supports in accordance with the requirements of ASME Code, Section Xl, Subsection IWF,

1989 Edition and Code Case N-491-1.

The applicant stated that, for license renewal, the program will be enhanced to provide for

inspection of Class MC component supports consistent with NUREG-1 801, Chapter III, Section

B13.3. This enhancement is scheduled for implementation prior to the period of extended

operation.

In its discussion on operating experience, the applicant stated that the operating experience of

the inservice inspection (ISI) programs at Dresden and Quad Cities, which include ASME

Section Xl, Subsection IWF aging management program activities, has not shown any adverse

trend of program performance. Periodic self-assessments of the ISI programs have been

performed to identify the areas that need improvement to maintain program quality.

The applicant concluded that the aging management program provides reasonable assurance

that the loss of material and loss of mechanical function aging effects are adequately managed

so that the intended functions of component and piping supports within the scope of license

renewal are maintained during the period of extended operation.

Staff Evaluation. In LRA Section B.1.27, "ASME Section Xl, Subsection IWF," the applicant

described its AMP to manage aging in ASME Code, Section XI Class 1, 2, 3 and MC supports.

The LRA stated that this AMP is consistent with GALL AMP XI.S3, when enhanced to provide

for inspection of Class MC component supports. The staff confirmed the applicant's claim of

consistency during the AMR inspection. Furthermore, the staff reviewed the enhancement to

determine whether the AMP, with the enhancement, is adequate to manage the aging effects

for which it is credited. In addition, the staff determined whether the applicant properly applied

the GALL program to its facility. The staff also reviewed the UFSAR supplements for Dresden

and Quad Cities to determine whether they provide an adequate description of the revised

program.

In its description of this AMP, the applicant specifically stated "The program is implemented

through station procedures, which provide for visual examination of inservice inspection Class

1, 2, and 3 supports in accordance with the requirements of ASME Section Xl, Subsection IWF,

1989 Edition and Code Case N-491-1." Inspection of Class MC supports is identified as an

"enhancements that is "scheduled for implementation prior to the period of extended operation."

This is part of Commitment #27 of Appendix A of this SER.

The staff considers the applicant's program to be consistent with GALL, except for the element

of "Scope". GALL presents a generic evaluation of IWF, an existing mandated program for

inspection of ASME Class 1, 2, 3, and MC supports. The applicant's existing IWF program is

not consistent with GALL in that it does not include the inspection of Class MC supports. The

staff's acceptance of IWF (or any other existing program) for aging management during the

license renewal period is substantially based on the assumption that the components covered

by the scope of the existing program are being periodically inspected during the current

licensing term and any problems affecting performance of intended function(s) have been

detected and corrected.

Therefore, the applicant was requested in RAI B.1.27 to describe the plant-specific operating

experience for the aging of Class MC supports in terms of: (1) the current inspection method,

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frequency, scope, and acceptance criteria; and (2) any observed degradation and subsequent

corrective actions taken to manage the aging of these components.

In its response to RAI B.1.27 dated October 3, 2003, the applicant stated:

10 CFR 50.55a(g)(4) states in part '...components (including supports) which are classified as ASME Code

Class 1, Class 2 and Class 3 must meet the requirements, ...set forth in Section Xi... It later states,

"Components which are classified as Class MC pressure retaining components and their integral

attachments, and components which are classified as Class CC pressure retaining components and their

integral attachments must meet the requirements, ...set forth in Section Xl..."

The CFR statement above specifically requires Class 1,2, and 3 supports to meet the requirements of

Section Xl. However, other than Integral attachments, there Is no mention of the Class MC supports. The

Dresden and Quad Cities Inservice Inspection programs have complied with the requirements of 10 CFR

50.55a. Therefore, containment supports are not required to be examined in accordance with Subsection

IWF.

There are no Inspections required by Subsection IWF that will not be performed by the use of

Subsection IWE. Perthe 1989 Edition and the 1992 Edition, with the1992 Addenda of ASME

Section XI, Table IWE-2500-1, Item E1.11, the Class MC integral attachments are subject to a

General Visual Examination (as described In IWE-3510.1) prior to each Type A Test. Additionally,

per Item E1.12, these integral attachments are subject to a VT-3 each Inspection interval. Per the

1995 Edition, with the 1996 Addenda of ASME Section Xl, Table IWF-2500-1, supports are subject

to a VT-3 each inspection interval.

The containment inservice inspection (CISI) program was developed in response to a recently

mandated final rulemaking per an amendment to the Code of Federal Regulations (10 CFR

50.55a). This rulemaking incorporates, by reference, the requirements of the 1992 Edition with the

1992 Addenda of the ASME Boiler and Pressure Vessel Code, Section Xl, Division 1, Subsections

IWE and IWL with specified modifications. The final rulemaking was published on August 8,1996

and specified an effective date of September 9, 1996 as well as an expedited implementation of

these requirements within five years of the effective date (September 9, 2001). In response, theDresden and Quad Cities CISI program included integral attachments as part of the IWE

examination boundary.

As there is no inspection history of containment supports, there is no site operating experience

related to this program to provide.

The applicant's response to RAI B.1.27 did not address the staff's concern, but served to

reinforce the concern regarding the inspection of Class MC Supports. The applicant's existing

IWF program is not consistent with GALL in that it does not include the inspection of Class MC

supports. In its response to RAI B.1.27, the applicant states that "containment supports are not

required to be examined in accordance with Subsection IWF." Furthermore, the response

states that "as there is no inspection history of containment supports, there is no site operating

experience related to this program to provide." Since there is no existing program to inspect

Class MC supports, the staff cannot accept the use of IWF in the license renewal period without

further information or actions by the applicant. Furthermore, the staff is confused as to which

Class MC supports the applicant is proposing to inspect under IWF in the license renewal

period. The response to RAI 2.4-2 lists at least three items that appear to be Class MC

supports (items c, d and j), but the LRA Table number and component group referenced for

each item leads to the Structures Monitoring program, not IWF. The response to RAI 2.4-2 also

lists a number of items that appear to be Class 1 supports (items a, b, and f (regarding anchor

bolts)), but the LRA Table number and component group referenced for each item leads to the

Structures Monitoring Program, not IWF. Some of the same components discussed in the

response to RAI 2.4-10 reference IWF, so there is an inconsistency between the two RAI

responses.

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The applicant's response to RAI 3.5-14 provides a justification for inspecting downcomer

bracing (a Class MC support) using IWE. This raised an additional staff concern as to how

many other Class MC supports the applicant intends to inspect using IWE rather than IWF.

Some of the Class MC supports discussed by the applicant in the above RAI responses seem

to be inaccessible. Therefore, the staff needed to better understand how the applicant is

treating these supports. This was identified as Open Item 3.5.2.3.2-1.

To resolve the concerns, the staff requested the applicant to provide the following information:

(a) Identify each type of Class MC support by name and confirm whether the support will be

inspected under IWF during the period of extended operation. Provide a technical

explanation for those supports that are proposed to be inspected under another program

(such as IWE or Structures Monitoring) or for cases where no inspection is planned.

(b) Since Class MC supports are not currently being inspected, provide a commitment to

perform a baseline inspection of typical samples of each type of Class MC component

support prior to the period of extended operation, to identify and correct any problems

affecting performance of intended functions.

(c) Describe how the performance of Class MC component supports in inaccessible areas

is currently being managed and how the supports will be managed during the period of

extended operation. Clarify the commitment to the provisions of 10 CFR 50.55(a)

covering inaccessible areas.

(d) Review the response to RAI 2.4-2 and identify the aging management program

applicable to each item (a) through (k). Also verify the consistency of this RAI response

with the response to RAI 2.4-10.

The applicant submitted the responses, dated April 9, 2004. After reviewing the applicant's

responses, the staff accepts the applicant's proposed use of its Structures Monitoring Program

as an alternate AMP to the GALL's ASME IWF program for its Class MC piping supports, with

the following modifications.

Modification #1 states that the sample size of the Class MC piping supports should be 15% of

the support population, as stipulated in Table IWF-2500-1, because the ten sample supports

proposed by the applicant is insufficient.

Modification #2 states that the person, who performs the inspection, should have demonstrated

knowledge of inspection attributes on Class MC piping supports and under oversight guidance

from the administrator or his designee during the initial inspection activity.

Modification #3 states that a baseline inspection should be performed on the sample supports

prior to the period of extended operation.

The applicant submitted its revised responses in a letter dated June 22, 2004. The responses

satisfactorily resolve the sample size and inspector's qualification issues. However, the staff

was not sure whether the applicant intended to only revise its Structures Monitoring Program

prior to the period of extended operation or actually have the MC supports and MC piping

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sample supports inspected prior to the period of extended operation. In a telephone

conference with the applicant on July 13, 2004, the applicant clarified that a baseline inspection

would be performed for these supports prior to the period of extended operation. The staff

considers the Open Item 3.5.2.3.2-1 resolved. This is part of Commitment #30 of Appendix A

of this SER.

Conclusions. On the basis of its review and audit of the applicant's program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. Since the GALL program is acceptable to the

staff since the applicant has demonstrated that the effects of aging will be adequately managed

so that the intended functions will be maintained consistent with the CLB during the period of

extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR

supplement for this AMP and finds that it provides an adequate summary description of the

program, as required by 10 CFR 54.21 (d).

3.5.2.3.3 Masonry Wall Program (B.1.29)

Summary of Technical Information in the Application. The applicant states in LRA Section

B.1.29 that the masonry wall program is consistent with the ten elements of aging management

program XI.S5, "Masonry Wall Program," specified in NUREG-1 801.

The masonry wall program, which is part of the structures monitoring program, is based on

guidance provided in 1. E. Bulletin 80-11, Masonry Wall Design,' and Information Notice 87-67,

Lessons Learned from Regional Inspections of Licensee Actions in Response to 1. E. Bulletin

80-11," and is implemented through station procedures. The program provides for inspections

of masonry-walls within the scope of license renewal for cracking. The program includes all

masonry walls that perform intended functions in accordance with 10 CFR 54.4, and is credited

for management of aging effects so that the established evaluation basis for each masonry wall

within the scope of license renewal remains valid through the period of extended operation.

In its discussion on operating experience, the applicant states that the masonry wall program

has provided for detection of cracks, and other minor aging effects in masonry walls. The

corrective action process has ensured timely repair in order to prevent continued degradation.

Maintenance history revealed minor degradation of masonry block walls. In response to 1. E.

Bulletin 80-11, "Masonry Wall Design,' and Information Notice 87-67, "Lessons Learned from

Regional Inspections of Licensee Actions in Response to 1. E. Bulletin 80-11," various actions

were taken. Actions included program enhancements, follow-up inspections to substantiate

masonry wall analyses and classifications, and the development of procedures for tracking and

recording changes to the walls. These actions addressed all concerns raised by 1. E. Bulletin

80-11 and Information Notice 87-67, namely unanalyzed conditions, improper assumptions,

improper classification, and lack of procedural controls. Operating history shows that the

program was and continues to be assessed for its effectiveness based on program specific

corrective actions that addressed issues such as inspection schedules and program database

discrepancies.

The applicant concludes that the masonry wall program provides reasonable assurance that the

aging effects of cracking are adequately managed so that the intended functions of masonry

walls within the scope of license renewal are maintained during the period of extended

operation.

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Staff Evaluation. In LRA Section B.1.29, Masonry Wall Program," the applicant described its

AMP to manage aging in masonry walls. The LRA stated that this AMP is consistent with GALL

AMP XI.S5. The staff confirmed the applicant's claim of consistency during the AMR inspection.

In addition, the staff determined whether the applicant properly applied the GALL program to its

facility. The staff also reviewed the UFSAR supplements for Dresden and Quad Cities to

determine whether it provides an adequate description of the program.

Conclusions. On the basis of its review and audit of the applicant's program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. The GALL program is acceptable to the staff

since the applicant has demonstrated that the effects of aging will be adequately managed so

that there is reasonable assurance that the intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The

staff also reviewed the UFSAR Supplement for this AMP and finds that it provides an adequate

summary description of the program, as required by 10 CFR 54.21 (d).

3.5.2.3.4 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear

Power Plants

Summary of Technical Information in the Application. The applicant states in LRA Section

B.1.31 that, with enhancements, the RG 1.127 aging management program is consistent with

the ten elements of aging management program XI.S7, *RG 1.127, Inspection of Water-Control

Structures Associated with Nuclear Power Plants," specified in NUREG-1 801.

The RG 1.127, *Inspection of Water-Control Structures Associated with Nuclear Power Plants,"

aging management program is part of the structures monitoring program and consists of

procedures that provide for condition monitoring of structural steel elements and concrete. With

enhancements, the program provides for visual inspections of structural steel and concrete

components within the scope of license renewal that are in the Unit 1 and Unit 2 and 3 crib

houses at Dresden, and the Unit 1 and 2 crib house and discharge canal weir structure

supporting the ultimate heat sink at Quad Cities. The program is credited for aging

management of concrete and structural steel elements exposed to raw water and aging

management of concrete not exposed to raw water, and is based on Regulatory Guide 1.127,

Revision 1.

For license renewal, the following enhancements will be made. Enhancements are scheduled

for implementation prior to the period of extended operation.

* The program will provide for monitoring of crib house concrete walls and slabs with an

opposing side in contact with river water and the Quad Cities discharge canal weir.

* Procedures will be revised to emphasize inspecting for structural integrity of concrete and

steel components and identify specific types of components to be inspected.

In its description of operating experience, the applicant stated that the operating history of crib

houses at Dresden and Quad Cities indicates that structural components are not experiencing

any significant degradation. Minor degradation of concrete has been detected such as cracks

with water stains, pitting, and leaching. These types of degradation were evaluated and

addressed. The effective use of the corrective action process has provided significant

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quantitative and qualitative data on performance, extent of degradation, and effects of

operating and environmental conditions ensuring timely identification and correction of

degraded conditions. The program has been assessed for its effectiveness based on program

specific corrective actions that addressed issues such as inspection schedules and program

database discrepancies.

The applicant concluded that the RG 1.127, "Inspection of Water-Control Structures Associated

with Nuclear Power Plants,' aging management program provides reasonable assurance that

the aging effects are adequately managed so that the intended functions of concrete and

structural steel components in water control structures within the scope of license renewal are

maintained during the period of extended operation.

Staff Evaluation. In LRA Section B.1.31, ERG 1.127, Inspection of Water-Control Structures

Associated with Nuclear Power Plants,' the applicant described its AMP to manage aging of

structural steel and concrete components within the scope of license renewal that are in the

Unit 1 and Unit 2 and 3 crib houses at Dresden, and the Unit 1 and 2 crib house and discharge

canal weir structure supporting the ultimate heat sink at Quad Cities. The LRA stated that this

AMP is consistent with GALL AMP XI.S7 with the enhancements described in the previous

section. The staff will confirm the applicant's claim of consistency during the AMR inspection.

Furthermore, the staff reviewed the enhancements to determine whether the AMP, with the

enhancements, is adequate to manage the aging effects for which it is credited. In addition, the

staff determined whether the applicant properly applied the GALL program to its facility. The

staff also reviewed the UFSAR supplements for both Dresden and Quad Cities to determine

whether they provide an adequate description of the revised program.

In its description, the applicant stated that this program "is part of the structures monitoring

program and consists of procedures that provide for condition monitoring of structural steel

elements and concrete."

Based on the applicant's description of this aging management program, it is not readily

apparent to the staff that it is consistent with the ten'elements of GALL XI.S7. The staff cannot

determine whether this is an existing program, and cannot identify the specific structures and

structural components, environments, and aging effects that are managed by this program. In

RAI 2.4-7, the staff has questioned the apparent omission from the scope of license renewal of

many structures that appear to be essential elements of the ultimate heat'sinks at Dresden and

Quad Cities. These structures are typically monitored using the guidance in RG 1.127, and for

license renewal should be included in the scope of an aging management program consistent

with GALL AMP XI.S7.

To complete its evaluation of this aging management program, the staff requested the applicant

to submit the following additional information:

(a) Clarify whether the program described in LRA Appendix B.1.31 is an existing program.

If so, explain what structures and structural components, environments, and aging

effects are currently inspected under this program at Dresden and Quad Cities. If not,

explain how the condition of water-control structures is currently monitored at Dresden

and Quad Cities.

(b) Describe the plant-specific operating experience with regard to the inspection of all

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essential structural elements of the ultimate heat sink, including (as applicable) the

intake and discharge canals and on-site ponds.

(c) Under the first Enhancement, the applicant stated that 'The program will provide for

monitoring of crib house concrete walls and slabs with an opposing side in contact with

river water and the Quad Cities discharge canal weir." Clarify whether the sides of the

crib house concrete wall and slabs that are exposed to raw water are inspected under

this program? If not, explain why not. Also, verify that the underwater surfaces of the

Quad Cities discharge canal weir are inspected under this program, or explain why they

are not.

(d) Under the second "Enhancement", the applicant stated that NProcedures will be revised

to emphasize inspecting for structural integrity of concrete and steel components and

identify specific types of components to be inspected." Describe the procedures that

already exist and provide a more detailed description of the revisions that will be made.

(e) Describe any additional enhancements to this program that may be required as a result

of the response to staff RAI 2.4-7, related to the scope of water-control structures that

serve an intended function for license renewal.

In its response to RAI B.1.31 dated October 3, 2003, the applicant stated:

(a) The program described in LRA Appendix B.1.31 is an existing program. The structures

currently monitored include the Dresden Unit 1 and 2/3 Crib Houses intake and discharge

canal, and the Quad Cities Unit 1/2 Crib House. The parameters monitored at these

concrete structures include cracking, movements, settlement, deflection, cavitation,

in-leakage, abrasion, spalling, scaling, leaching of calcium hydroxide, corrosion of embedded

steel, and others. For further details see the clarifications provided in (d) below.

(b) The Dresden intake and discharge canals were determined to be in the scope of license renewal and

the Dresden cooling lake was determined to out of scope of license renewal (Reference RAI 2.4-7). A

search of the corrective action database indicated that there have been several leaks found in the

cooling lake dike by various means including the bimonthly dike inspection, and operator and security

rounds. Corrective actions were taken to resolve the leaking such as installing sheet piling. However

there were no conditions of canal wall degradation found. It should be noted that the canal walls are

not subject to the same failure mechanisms as the cooling lake dike walls. The canals are trenched in

existing ground topography, where the cooling lake dike walls were built above the grade of the

surrounding topography.

(c) The program does inspect the crib house concrete walls and slabs exposed to raw water. The

existing program does not include the Quad Cities discharge canal weir. However, the discharge

canal weir is being added as an enhancement as noted in (d) below.

(d) The current structural monitoring program procedures inspect concrete beams, floor and roof slabs,

columns and walls. This program inspects concrete surfaces for the following conditions: leaching

and chemical attack; abrasion, erosion, and cavitation; drummy areas (poorly consolidated concrete

with past deficiencies); pop-outs and voids; scaling; spalling; signs of corrosion in reinforcing steel or

anchorage components; corrosion of exposed embedded metal surfaces and corrosion stains around

the embedded metal; and detached embedments or loose bolts. The program inspects steel

elements for the following conditions: excessive deflection, cross-section distortion, or member

misalignment; significant corrosion; cracks, tears, and laminations; loose or missing bolts on bolted

connections. The enhancements to be made to this procedure as it applies to water control structures

include the following:

(a) Enhance the Monitoring and Trending section to include review of previous inspection

reports, photos, etc. of elements to be inspected at the next inspection interval/period.

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(b) Clarify scope to include inspections of all Crib House interior concrete walls with an

opposing side in contact with river water and all Crib House concrete slabs with an

opposing side in contact with river water.

(c) Add inspection parameters for joints, and structural isolation gaps.

(d) Add a task to review ground water chemistry data to ensure limits are not exceeded

and Include task frequency.

(e) Clarity scope for Dresden Unit 1 Crib House.

(0) Clarify scope to include the discharge canal weir at Quad Cities.

(g) Clarify Inspection scope is to include condition monitoring of concrete below water

line.

(h) Add requirements for qualifications for personnel performing inspections and

personnel evaluating results.

(e) The additional component groups added to the scope of License Renewal in response to RAI

2.4-7 are already being inspected through structural monitoring program or had no viable

aging mechanisms requiring aging management. The additional existing activity to be

credited as license renewal commitments is monitoring the earthen structures (canal) at

Dresden.

The additional information provided by the applicant in its response to RAI B.1.31 did not

completely address all of the staff's request for information and raised some additional

concerns as discussed below. Therefore, the applicant was requested to provide the following

additional information to supplement its initial RAI response:

(1) The response to RAI B.1.31 (a) states the parameters monitored for the concrete structures

(Dresden Unit 1 and 2/3 Crib House and Quad Cities Unit 1 /2 Crib House) included in

the existing B.1.31 program. However, the RAI response also indicates that the Dresden

intake and discharge canals are currently monitored under this existing program. Based

on the information provided in the response to RAI 2.4-7, the staff understands that

these canals are earthen structures. Therefore, the staff asked the applicant to explain

what parameters are monitored for the earthen structures under this existing program.

(2) The response to RAI B.1.31 (a) did not explain how the condition of water control

structures within the scope of license renewal that are not included in the existing

program are currently monitored at Dresden and Quad Cities. The staff asked the

applicant to provide this information for all structures and components identified in the

response to RAI 2.4-7 as being within the scope of license renewal, as well as any other

applicable structures and components that may not have been listed by the staff as part

of RAI 2.4-7.

(3) The response to RAI B.1.31 (b) only described the operating experience with regard to

the Dresden intake and discharge canals and the Dresden cooling lake (which is stated

as being out of the scope of license renewal). The staff asked the applicant to describe

the operating experience with regard to the inspection of all essential structural

elements of the ultimate heat sink for both Dresden and Quad Cities as identified in the

response to RAI 2.4-7.

(4) The response to RAI 8.1.31 (d) does not discuss any existing procedures or planned

enhancements related to the inspection of earthen structures. The staff asked the

applicant to describe these procedures since it is clear that earthen structures are being

monitored under the 8.1.31 program.

(5) The response to RAI B.1.31 does not address the Quad Cities intake flume/canal. The

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response to RAI 2.4-7 discusses the intake flume/canal boundaries, but does not specify

whether the flume/canal is included in the license renewal scope, and does not provide

a reference for the aging management review of the topographic basin. The staff

requested the applicant to clarify whether the Quad Cities flume/canal, including the

topographic basin, is monitored under the B.1.31 program. If it was, the staff asked the

applicant to describe the monitoring procedures used . If it was not, the staff asked the

applicant to explain the technical basis for its exclusion.

(6) For the structures and components of the ultimate heat sink that are not currently being

inspected under an existing program, the staff requested the applicant to provide a

commitment to perform a baseline inspection of typical portions of each structure or

component prior to the period of extended operation, to identify and correct any

problems affecting performance of intended functions.

(7) The staff notes that in LRA Section A.1.31 for both Dresden and Quad Cities there is no

mention of earthen structures in the description of the RG 1.127 program for the UFSAR

Supplement. The staff requested the applicant to revise these supplements to

specifically identify earthen structures as being within the scope of this program, and

also to include a discussion of any other significant changes in the scope of this

program that have occurred as a result of the applicant's responses to the staff RAls

related to this program.

In its response to the staff's request for additional information dated December 5, 2003, to

supplement the initial RAI response, the applicant stated

(1) The canals are earthen structures that require aging management. Specifically, these

structures are vulnerable to the buildup of sedimentation. Existing station procedures monitor the

aging effect, 'Loss of Form due to Sedimentation", to ensure that the required volume of water is

available in the ultimate heat sink to support emergency cooling conditions. This includes the

forebay at Dresden and the forebay at Quad Cities. (Note the 'Dresden Only' annotation in table

2.3.3-22 for Component Group 'Earthen Structures' provided RAI 2.4-7 was incorrect and has

been deleted.)

The Quad Cities Earthen Structure consists of a bay excavated from the river front area down and

into the existing bedrock up to the in-scope concrete structures. The sidewalls of this structure are

engineering designed earthen slopes and are covered with rip-rap, both above and below the

water line.

The Dresden Earthen Structure was excavated through the soil. The actual canals are excavated

from bedrock. The soil portions above the canals are capped with concrete.

The aging management review of these structures found that 'Loss of Form' was the only

applicable aging effect, and sedimentation the only applicable aging mechanism contributing to

this effect based on the design and configuration of these structures.

(2) The existing Aging Management activities for the in-scope Quad Cities components as

discussed in RAI 2.4-7 are:

' Intake Flume - Aging management of the earthen portion of this structure is discussed in the

response to (1) above. Concrete portions are addressed in LRA Table 2.4-11, under Component Group, 'Concrete Walls', and Aging Management Reference 3.5.22, RG 1.127, Inspection of

Water Control Structures Associated with Nuclear Power Plants, Program B.1.31.

* 16' diameter discharge piping - This piping is addressed in LRA Table 2.3.3-22, under

Component Group, 'Piping and Fittings', and Aging Management Reference 3.3.1.15, Open Cycle

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Cooling Water Program B.1.1 3.-;-

* 96' Ice Melting Une, including Gate - The ice melt line is addressed in LRA Table 2.3.3-22, under

Component Group, 'Piping and Fittings", and Aging Management Reference 3.3.1.15, Open Cycle

Cooling Water Program B.1.13. The gate Is addressed in LRA Table 2.3.3-22, under Component

Group, 'Valves" and Aging Management Reference 3.3.2.278, Open Cycle Cooling Water

Program B.1.13 and Aging Management Reference 3.3.2.300, Bolting Integrity Program B.1.12.

* Discharge Flume/Canal - This structure is addressed in LRA Table 2.4-11, under Component

Group, 'Concrete Walls", and Aging Management Reference 3.5.1.22, RG 1.127, Inspection of

Water Control Structures Associated with Nuclear Power Plants, Program B.1.31. However, these

aging management activities are an enhancement and are not currently Implemented.

* Weir Gate In discharge canal - This component is addressed In LRA Table 2.4-11, under

Component Group, "Concrete Walls", and Aging Management Reference 3.5.1.22, RG 1.127,

Inspection of Water Control Structures Associated with Nuclear Power Plants, Program B.1.31.

However, these aging management activities are an enhancement and are not currently

implemented.

The existing Aging Management activities for the in-scope Dresden components as discussed in

RAI 2.4-7 are:

* Intake flume/canal - Aging management of the earthen portion of this structure is discussed in the

response to (1) above. Concrete portions are addressed in LRA Table 2.4-11, under Component

Group, "Concrete Walls", and Aging Management Reference 3.5.1.22, RG 1.127, Inspection of

Water Control Structures Associated with Nuclear Power Plants, Program B.1.31.

* Crib House Stop Logs - These components are addressed In LRA Table 2.3.3-22, Component

Group "Stop Logs" and Aging Management Reference 3.3.2.304, with no aging management

required (as supplied in RAI 2.4-7 response).

* Crib house dewatering valves and trash rake refuse pit - The valves are addressed in LRA Table

2.3.3-22, under Component group, "Valves", and Aging Management Reference 3.3.2.278, Open

Cycle Cooling Water Program B.1.13 and Aging Management Reference 3.3.2.300, Bolting

Integrity Program B.1.12. The refuse pit is addressed in LRA Table 2.4-11 under component

groups "Concrete Walls and Concrete Slabs" and Aging Management Reference 3.5.1.22, RG

1.127, Inspection of Water Control Structures Associated with Nuclear Power Plants, Program

B.1.31.

* Discharge Outfall Structure - This structure is addressed in LRA Table 2.3.3-22, under

Component Groups, 'Concrete Walls and Concrete Slabs", and Aging Management Reference

3.5.1.22, RG 1.127, Inspection of Water Control Structures Associated with Nuclear Power Plants,

Program B.1.31 (as supplied in RAI 2.4-7 response). However, these aging management activities

are an enhancement and are not currently implemented.

* 8' Diameter Ice Melt Recirculating Pipe, including ice melt gate - The ice melt pipe is addressed

In LRA Table 2.3.3-22, under Component Group, "Piping and Fittings", and Aging Management

Reference 3.3.1.15, Open Cycle Cooling Water Program B.1.13. The gate is addressed in LRA

Table 2.3.3-22, under Component Group, "Valves", and Aging Management Reference 3.3.2.278,

Open Cycle Cooling Water Program B.1.13. and Aging Management Reference 3.3.2.300, Bolting

Integrity Program B.1.12.

* Discharge flume/canal - The aging management for this earthen structure is discussed in the

response to (1) above.

(3) Section B.1.31 of the LRA does list the operating experience for concrete structures. Section

B.1.13 of the LRA lists the operating experience for the piping components covered by the Open

Cycle Cooling Water Program.

The operating experience for the earthen structures:

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Dresden has performed inspections of the intake and discharge canals and has not found any

appreciable silting. However, minor silting was found at the intake structure near the bar racks.

This silting was removed prior to loss of function of the ultimate heat sink.

Quad Cities, taking suction directly off the Mississippi River, has found significant levels of silting in

the earthen structure of the intake flume as well as at the intake structure on several occasions.

Timely corrective actions (dredging or cleaning) were completed prior to the loss of function of the

ultimate heat sink, indicating an effective monitoring program.

(4) The only enhancement needed is to annotate the existing requirements of the Exelon

procedures that monitor the aging effect, Loss of Form due to Sedimentation', to ensure that the

required volume of water is available in the ultimate heat sink to support emergency cooling

conditions as license renewal commitments. This requirement Is implemented through a site

Predefine Activity for scheduling and tracking purposes at Quad Cities. A similar Predefine Activity

will be developed for Dresden.

(5) The Quad Cities intake flume is in the scope of license renewal. Management of this earthen

structure is discussed in the response to (1) above.

(6) A baseline inspection will be performed prior to the period of extended operation for the Quad

Cities Discharge Flume/Canal and Weir Gate and the Dresden Outfall Structure. Any problems

affecting performance of intended functions will be identified and corrected.

Note that there are no current aging management activities performed for the Dresden Stop Logs.

As there has been no viable aging mechanism identified, the stop logs will not be included in the

baseline inspection.

(7) LRA Section A.1.31 for Dresden and Quad Cities will be updated to specifically indicate the

applicable in-scope earthen structures (Dresden intake/discharge flumes and Quad Cities

intake/discharge flumes) and the aging management activities associated with these structures.

The baseline inspection of item (6) above is Commitment #31 of Appendix A of this SER.

Based on the initial and supplemental information provided by the applicant, the staff finds that

the water control structures in the scope of license renewal have been appropriately evaluated

in the applicant's AMR, and that AMP B.1.31 - 'RG 1.127, Inspection of Water-Control

Structures Associated with Nuclear Power Plants has been appropriately credited and

enhanced to manage aging of water control structures for the period of extended operation.

Therefore, RAI B.1.31 is resolved.

Conclusions. On the basis of its review and audit of the applicant's program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. Since the GALL program is acceptable to the

staff, the applicant has demonstrated that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB during the period of

extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR

supplement for this AMP and finds that it provides an adequate summary description of the

program, as required by 10 CFR 54.21 (d).

3.5.2.3.5 Protective Coating Monitoring and Maintenance (B.1.32)

Summary of Technical Information in the Application. The applicant states in LRA Section

B.1.32 that, with enhancements, the protective coating monitoring and maintenance program is

consistent with the ten elements of aging management program XI.S8, "Protective Coating

Monitoring and Maintenance Program," specified in NUREG-1 801.

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For license renewal, the following enhancements will be made. Enhancements are scheduled

for implementation prior to the period of extended operation.

* Procedure revisions will provide for thorough visual inspections of Service Level I

coatings near sumps or screens associated with the emergency core cooling system.

* Procedure revisions will provide for pre-inspection reviews of previous reports so that

trends can be identified.

* Procedure revisions will provide for analysis of suspected reasons for coating failure.

This is Commitment #32 of Appendix A of the SER. The protective coating monitoring and

maintenance program is credited for aging management of Service Level I coatings inside

primary containment. Service Level I coatings are used in areas where the coating failure could

adversely affect the operation of post-accident fluid systems and thereby impair safe shutdown.

The program provides for visual inspections to identify any condition that adversely affects the

ability of the coating film to function as intended. It is implemented through procedures based

on the technical and quality requirements of Regulatory Guide 1.54, Revision 0, "Quality

Assurance Requirements for Protective Coatings Applied to Water Cooled Nuclear Power

Plants," and ANSI N101 4-1972, Quality Assurance for Protective Coatings Applied to Nuclear

Facilities," and the guidance provided in EPRI TR-1 09937, 'Guidelines on Nuclear

Safety-Related Coating."

In its discussion on operating experience, the applicant stated that examinations of the Dresden

internal drywell accessible steel surfaces during refueling outages revealed that the original

coatings were acceptable other than exhibiting minor surface rust, paint flaking and

discoloration. The applicant identified no significant degradation in the corrective action

process records. The internal surfaces of the torus for each of the Dresden units were

re-coated with an epoxy coating in the late 1980's during refuel outages D2R1 1 and D3R1 0.

Surveillance of the coated torus internal surfaces during refueling outages has resulted in local

coating repairs. A review of past inspections of the torus shells indicates the majority of the

problems have been attributed to blistering of coating in small areas, localized pitting, and

mechanical damage. Since the application of the epoxy protective coating on the internal

surfaces, torus wall thinning has not been an issue. Inspections of drywell steel at Quad Cities

have not identified any significant coating or corrosion problems requiring repair of the torus. In

1994 the Quad Cities Unit 1 torus internal surface corrosion was removed and the base metal

was re-coated. During the subsequent refueling outage the torus shell immersion area was

: inspected. Coating deficiencies, such as mechanical damage, burrs and projections were

identified and repaired. Minor local repairs to the coating on the inside of the Quad Cities Unit 2

torus were performed in March 1974. Inspections are conducted each outage, with local coating

repairs performed as required.

The applicant concludes that the protective coating monitoring and maintenance program

provides reasonable assurance that aging effects are adequately managed so that the intended

functions of Service Level 1 coatings inside primary containment are maintained during the

period of extended operation.

Staff Evaluation. In LRA Section B.1.32, "Protective Coating Monitoring and Maintenance

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Program," the applicant described its AMP to manage Service Level 1 coatings inside primary

containment. The LRA stated that this AMP is consistent with GALL AMP XI.S8 with the

enhancements described in the previous section. The staff confirmed the applicant's claim of

consistency during the AMR inspection. Furthermore, the staff reviewed the enhancements to

determine whether the AMP, with the enhancements, is adequate to manage the aging effects

for which it is credited. In addition, the staff determined whether the applicant properly applied

the GALL program to its facility. The staff also reviewed the UFSAR supplements for both

Dresden and Quad Cities to determine whether they provide an adequate description of the

revised program.

In order to complete its evaluation, the applicant was requested in RAI B.1.32 to submit the

following information:

(a) It is the staff's understanding that this program is being credited for prevention/mitigation

of loss of material due to corrosion of steel structural components inside containment,

including the accessible inside surfaces of the containment drywell and torus. In

addition, it is the staff's understanding that this program augments, but does not

replace, inspections conducted under IWE, IWF, and structures monitoring program.

Please confirm that these understandings are correct, or provide additional explanatory

information to clarify the scope and purpose of the Protective Coating Monitoring and

Maintenance program.

(b) Does the scope of this program include monitoring and maintenance of anti-corrosion'

coatings applied to the sand pocket region of the drywell? If not, what program monitors

the condition of these coatings?

(c) In the third paragraph under "Operating Experience," the LRA states 'Inspections of

drywell steel at Quad Cities have not identified any significant coating or corrosion

problems requiring repair of the torus." Please clarify what is meant by this statement.

In its response to RAI B.1.32 dated October 3, 2003, the applicant stated:

(a) The Protective Coating Monitoring and Maintenance program is being credited for Ucense

Renewal to prevent/mitigate loss of material due to corrosion of steel structural components inside

containment, including the accessible inside surfaces of the containment drywell and torus. In

addition, the program does augment, but does not replace, inspections conducted under the

ASME Section Xl, Subsection IWE program (LRA Section B.1.26), the ASME Section Xl,

Subsection IWF program (LRA Section B.1.27), and the structures monitoring program (LRA

Section B.1.30).

(b) The scope of the program does not include monitoring and maintenance of anti-corrosion

coatings applied to the sand pocket region of the drywell. There is no program that monitors the

condition of the coatings in the sand pocket region of the drywell. However, UT inspections of the

drywell shell of the bounding unit (Dresden Unit 3) in the sand pocket region are performed each

refueling outage as part of the ASME Section Xl, Subsection IWE program. These UT inspections

ensure drywell shell thickness at these locations is maintained above the minimum allowable.

(c) The subject sentence in the third paragraph under 'Operating Experience' inadvertently made

reference to the torus. The sentence involves drywell steel and should have read as follows:

Inspections of the drywell steel at Quad Cities have not identified any significant coating or

corrosion problems requiring repair of the drywell steel.

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t'. .I".........

The additional information provided by the applicant in its RAI response confirms the staff's

understanding of the scope and purpose of the Protective Coating Monitoring and Maintenance

program. The staff accepts thai the scope of the program does riot include monitoring and

maintenance of anti-corrosion coatings applied to the sand pocket region of the drywell.

Conclusions. On the basis of its review and audit of the applicant's program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. Since the GALL program is acceptable to the

staff, the applicant has demonstrated that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB during the period of

extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR

supplement for this AMP and finds that it provides an adequate summary description of the

program, as required by 10 CFR 54.21(d).

3.5.2.4 Aging Management Review of Plant-Specific Structures and Structural Components

In this section of the SER, the staff presents its evaluation of the applicant's aging management

review of specific structures and structural components. To perform its evaluation, the staff

reviewed the components listed in LRA Tables 2.4-1 through 2.4-16 to determine whether the

applicant properly identified the applicable AMRs and AMPs needed to adequately manage the

aging effects for the components. The staff also reviewed the Aging Management Review Aid'

submitted by the applicant as a supplement to the LRA. This element of the staff review

involved identification of the aging effects for each component, ensuring that each aging effect

was evaluated using the appropriate AMR in LRA Section 3, and that an appropriate AMP was

credited for management of the aging effect. The results of the staff's review are provided

below.

3.5.2.4.1 Primary Containment

Summary of TechnicaFlnformation in the ApDplication. The applicant's description of the primary

containment (Dresden and Quad Cities) is in LRA Section 2.4.1. The applicant has defined

primary containment" to include not only the steel containment shell, but also all structures and

structural components inside containment. The component groups requiring aging

management review are identified in LRA Table 2.4-1. For each component group listed, LRA

Table 2.4-1 specifies a reference to LRA Section 3 for the AMR results. For the primary

containment component groups, the AMR results are provided in LRA Tables 3.5-1 and 3.5-2,

with one exception: -walls, ceilings, and floors that serve as fire barriers reference LRA Table

3.3-1 (Reference No. 3.3.1.28). The applicant used the SRP-LR report format in LRA Table

3.5-1 to present its AMR for the containment components that are addressed in the GALL

Report. Further evaluation of aging management, as recommended by GALL, is discussed in

LRA Section 3.5.1.1. Aging management programs or evaluations that are different from those

in GALL are described in LRA Section 3.5.1.2. In LRA Table 3.5-2, the applicant identified the

containment component groups that are not addressed in the GALL Report and provided the

following information: on (1) material, (2) environment, (3) aging effect(s)/mechanism(s), and

(4) AMP(s).aging management program(s).

Utilizing the Dresden and Quad Cities Aging Management Review Aid (February 2003), the

staff identified the following applicable materials for the primary containment, including the

structures inside containment: as carbon steel, stainless steel, reinforced concrete, grout,

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lubrite base plates, polyurethane expansion foam, and various materials for seals, gaskets, and

moisture barriers. The staff also identified the following applicable environments as (1) inside

containment, (2) outside containment, (3) and inside containment, and exposed to aggressive

environment.

Aging Effects

The LRA identified the following applicable aging effects:

* cracking, loss of material, and change in material properties for concrete components

and grout

* cumulative fatigue, cracking, and loss of material for steel elements, penetrations, and

hatches

* loss of seal for elastomers

* lock-up for beam seats

* hardening of drywell expansion foam

Aging Management Programs

The LRA credits the following AMPs for managing the identified aging effects:

* ASME Section Xl, Subsection IWE Program

* 10 CFR Part 50, Appendix J Inspection Program

* Protective Coating Monitoring and Maintenance Program

* Structures Monitoring Program

* Fire Protection Program

A description of these AMPs is provided in LRA Appendix B. The applicant concluded that the

effects of aging will be adequately managed by these AMPs, such that the intended functions

will be maintained during the period of extended operation.

Staff Evaluation. This section provides the staff's evaluation of the applicant's AMR for the

primary containment and the applicability of the AMPs credited to manage the aging effects.

Table 3.5-1 of this SER provides a summary of the staff's evaluation of components, aging

effects/mechanisms, and AMPs listed in LRA Table 3.5-1, for the components that are

addressed in the GALL Report. Section 3.5.2.1 of this SER provides the staff's evaluation of

the aging management evaluations in the GALL Report that are relied on for license renewal,

which do not require further evaluation. Section 3.5.2.2 of this SER provides the staff's

evaluation of the aging management evaluations in the GALL Report that are relied on for

license renewal, for which the GALL Report recommends further evaluation.

The staff's evaluations of the aging management evaluations for the primary containment that

are different from those described in the GALL Report, or are not addressed in GALL, are

discussed below.

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Aging Effects

Steel: Table 3.5-2 of the LRA, Reference No. 3.5.2.15, OThermowellso, states that stainless

steel thermowells are installed in the torus. Section Xl, Subsection IWE, of ASME is credited

with managing the stainless steeldissimilar metal welds for thermowells, inside or outside

containment, for loss of material due to general galvanic pitting and crevice corrosion. The

applicant was requested to (1) describe the location of all the stainless steel components and

identify the specific environments to which they are exposed; (2) identify all aging

effects/mechanisms that were evaluated, including those not requiring aging management, and

provide the technical basis for each conclusion; and (3) discuss the technical basis for the

selection of the AMP used to manage the applicable aging effects. This is part of RAI 3.5-16.

In response to the applicable part of RAI 3.5-16, the applicant stated the following:

(1) The thermowells are installed In the suppression chamber shell. All are located below the

waterline, with the exception of four thermowells at Ouad Cities, two on each unit, that are

located in the air space above the water line. The suppression chamber air space above the

suppression chamber water level is made Inert with nitrogen to maintain the oxygen content

below 4% by volume during normal operation. The air temperature follows the normal,

maximum operating suppression chamber water temperature of 95 F and the relative

humidity is between 20 and 90%.

The suppression chamber air space environment encompasses the following NUREG-1 801

environment description:

Moist Containment Atmosphere (air/nitrogen), steam, or demineralized water

The suppression chamber water environment encompasses the following NUREG-1801

environment description: 25-288 OC (77 0 - 550 OF) demineralized water.

(2) All aging effects/mechanisms that were evaluated for the suppression chamber thermowells

are described below along with the technical basis used to determine whether aging

management was required. EPRI 1003056, "Non-Class 1 Mechanical Implementation

Guideline and Mechanical Tools (EPRI Mechanical Tools), Appendix A, Tables 4-1 and 4-2

and Figures 1 and 2, were utilized to identify potential aging effects/mechanisms for the

thermowells and are the bases for the following discussions.

Loss of material/general, pitting, and crevice corrosion: This is applicable to the thermowells

installed in either the suppression chamber water or air space environments. While stainless

steel itself is not susceptible to general corrosion, it was conservatively assumed to be an

applicable aging mechanism for the installation due to the fact that thermowells are welded to

carbon steel half-couplings, which are in turn welded to the suppression chamber shell.

Loss of material/galvanic corrosion: The stainless steel thermowells are welded to carbon

steel half-couplings or sleeves, which are welded to the exterior of the suppression chamber

shell. This dissimilar metal weld is outside the suppression chamber where an electrolytic

environment does not exist. However, an electrolytic environment does exist between the

half-coupling/sleeves and the thermowell. For this reason, this aging effect/mechanism Is

considered applicable to the thermowell installations.

Crack initiation and growth/SCC: This Is not considered applicable to the thermowells

installed in either the suppression chamber water or air space environments. Stress

Corrosion Cracking (SCC) has been observed in high purity water at temperatures greater

than 200 OF and dissolved oxygen levels greater than 100 ppb. The normal, maximum

operating suppression chamber water temperature is 95 F. Suppression chamber water

quality is maintained within EPRI recommended levels. Therefore, suppression chamber

thermowells are not susceptible to SCC.

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(3) The stainless steel thermowells installed in the suppression chamber are included in ASME

Section Xl, Subsection IWE ISI Program. This aging management program is credited with

managing the loss of material due to corrosion for these thermowells. The program provides

for the inspection of ASME Class MC pressure retaining components and their integral

attachments and is also credited for managing the loss of material aging effects due to

corrosion for NUREG-1801 Section ll.B components with dissimilar metal welds.

The staff finds the applicant's AMR and selection of the AMP for thermowells installed in the

suppression chamber shell to be acceptable, based on consistency with the guidance in the

GALL Report for similar material and environment. Based on the information provided, the staff

accepts the applicant's conclusion that the thermowells are not susceptible to SCC. This part of

RAI 3.5-16 is resolved.

Miscellaneous Materials (expansion foam): In LRA Table 3.5-2, Reference No. 3.5.2.8,

"Drywell Expansion Foam," the applicant referenced a plant-specific TLAA that is described in

LRA Section 4.7.4. The polyurethane drywell expansion foam installed on the outside of the

containment was originally evaluated for hardening due to radiation exposure assuming a

40-year operating life. As discussed in Section 6.2.1.2.1.1 of the Dresden UFSAR, this foam

has caught fire twice in Dresden Unit 3 (January 20, 1986, and June 4, 1988). The staff

requested the applicant, in RAI 3.5-10, to submit the following information for all four units:

(a) Describe any other instances of fires or other degradation experiences related to the

drywell expansion foam.

(b) Describe the programs and procedures put in place to prevent future fires in the drywell

expansion foam. If none, explain why they are not necessary.

(c) Describe any investigations that determined whether there was any significant change in

material properties due to the fires, or other operating experiences, that would prevent

the foam from performing its intended function. If none, explain the technical basis for

concluding that there has been no change in material properties.

(d) Identify all the environments that the expansion foam may be exposed to, including

leaking water, and discuss what effect each environment may have on the material

properties of the foam.

(e) Concerning the January 26,1986, fire, Dresden UFSAR Section 6.2.1.2.1.1 states, "The

polyurethane in the gap burned for several hours resulting in a postulated upper

bounding temperature of 500 degree F for both the steel containment and the primary

containment shield wall." It also states, "Structural integrity of both the concrete and

containment steel were determined not to be impaired to perform as designed in the

event of a design basis accident (DBA)." Concerning the June 4, 1988, fire, it was

determined that "this fire was bounded by the analyses conducted for the 1986 fire and

no further analyses were conducted." The staff asked the applicant to provide a detailed

technical basis demonstrating that the evaluation of the concrete and containment steel

for the effects of the fires remains valid for the period of extended operation.

In response to RAI 3.5-10, the applicant stated the following:

(a) The polyurethane foam is installed on the outside of the steel drywell containment vessel,

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but inside the surrounding concrete shield, providing an expansion gap between the steel

and concrete surfaces. No other Instances of degradation of Drywell Expansion Foam

other than those discussed in the Dresden UFSAR could be found.

(b) Procedures originally developed to prevent recurrence of these fires Include Dresden

Maintenance Procedure DMP 4100-1 and Dresden Administrative Procedure DAP 3-2,

which have been superceded by, OPAA'201-004, 'Fire Prevention For Hot Work'. This

new procedure still emphasizes the requirement for a Fire Watch during hot work

(welding, cutting, grinding and open flame operations) for 30 minutes after completion or

suspension of the hot work.

(c) The fires were evaluated as part of the Initial event and the results accepted by the NRC

in "Safety Evaluation Report By The Office of Nuclear Reactor Regulation of The

Expansion Gap Fire on January 20, 1986 at Dresden Station Unit 3' dated August 31,

1987. The foam's intended function(s) is Expansion/Separation - Provides for thermal

expansion and/or seismic separation'. Test results from the burning of polyurethane

foam samples showed that the residuals are easily crushed by finger pressure and would

therefore allow the thermal expansion of the drywell liner for the period of extended

operation. Additionally, Section 4.7.4 of the LRA provides the basis for concluding that no

change in material properties Is expected for the extended term of operation.

(d) The expansion foam was evaluated as exposed to an 'Outside Containment'

environment. This environment Is defined as: The Reactor Building (outside the drywell,

torus, and steam tunnel) normal operating area temperatures range from 65 F to 103 F

- for Dresden and 65 F to 104 F for Quad Cities with relative humidity ranging between

20% and 90%. As discussed In LRA Section 4.7.4, this environment In addition to the

expected radiation exposure will not affect the resilient characteristics of this polyurethane

foam. This foam is not typically exposed to leaking fluid.

(e) The original function of the foam was to provide separation between the drywell steel liner

and the concrete as the concrete was poured. The remaining function of the foam is to

allow thermal expansion of the steel liner. Test results from the burning of polyurethane

foam samples showed that the residuals are easily crushed by finger pressure and would

therefore allow the thermal expansion of the drywell liner for the period of extended

operation. The structural integrity of the containment steel and surrounding concrete was

not affected by the drywell fires. Temperatures experienced by the drywell liner fires

never approached 850 'F, which is the minimum temperature that steel begins to lose

tensile strength. The surrounding concrete was also not affected as concrete spalling

does not occur below 1000 'F.

The staff finds the applicant's response acceptable and RAI 3.5-10 is resolved.

Fire Barrier Materials: In the LRA, Table 2.4-1 references LRA Table 3.3-1 for the AMR

related to cracking and spalling and loss of material for concrete and reinforcement of

fire barrier walls, ceilings, and floors. The AMPs credited for these components are the,

Fire Protection and Structures Monitoring Programs. The discussion column on this

item states that it is consistent with the GALL Report, with the following exception:

The exceptions to structural aging effects due to aggressive chemical attack, reaction

with aggregates, freeze-thaw and corrosion of embedded steel are described in LRA

Section 3.3.1.2.1. The exceptions to Fire Protection are described in LRA Section

B.1.18.

Section 3.3.1.2.1 of the LRA states that no aging management is required to manage the

following structural aging effects for concrete in inaccessible areas:

* cracking and spalling due to aggressive chemical attack

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* cracking and spalling due to reaction with aggregates

* cracking and spalling due to freeze-thaw

* loss of material due to corrosion of embedded steel

The technical bases provided for these exceptions are the same as those described in LRA

Sections 3.5.1.1.6 and 3.5.1.1.7. The staff's evaluation of these exceptions is included in SER

Section 3.5.2.2.2. The staff concluded that these exceptions are acceptable.

The exceptions to the GALL Fire Protection AMP are described in LRA Section B.1.18. These

exceptions primarily relate to the frequency of inspection of various fire protection component

groups. With respect to concrete walls, floors, and ceilings that serve a fire barrier intended

function, the inspection frequency is consistent with the Structures Monitoring AMP, which the

applicant credits to manage aging of all concrete structural components, including those that

serve a fire barrier intended function. Therefore, from the standpoint of structural integrity, the

staff finds this acceptable. The staff review of the applicant's Fire Protection AMP is presented

in SER Section 3.3.2.3.

The aging effects identified in the LRA for the primary containment are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs with managing the aging effects described

above for the primary containment:

* ASME Section Xl, Subsection IWE Program

* 10 CFR Part 50, Appendix J Inspection Program

* Protective Coating Monitoring and Maintenance Program

* Structures Monitoring Program

* Fire Protection Program

In the LRA, Section 3.5.1.2.9 discusses an exception to the GALL Report for evaluation of the

ECCS suction header identified under Reference Nos. 3.5.1.12 and 3.5.1.14 in LRA Table

3.5-1. The applicant stated that this item is evaluated with GALL item V.D2.1-a, with the results

presented in Reference Nos. 3.2.1.2 and 3.2.1.4 in LRA Table 3.2-1. Table 3.2-1 references

the Water Chemistry and One-Time Inspection Programs as the AMPs for these items. In

accordance with GALL item ll.B13.1.1 -a, aging of the ECCS suction header should be managed

by ASME Section Xl, Subsection IWE. The applicant was requested in RAI 3.5-9 to (a) explain

why the ECCS suction header was evaluated as part of the ECCS piping and not as part of the

containment, and (b) submit a detailed technical basis demonstrating that an equivalent level of

safety is achieved with the applicant's approach, when compared to Subsection IWE

requirements.

In its response to RAI 3.5-9, the applicant stated the following:

NUREG-1801 addresses the ECCS Suction Headers in two locations. Item lI.B.1.1.1-a addresses

the Primary Containment (ASME Class MC components) and manages Loss of Material due to

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Corrosion. Item V.D2.1.a addresses Piping and Fittings, (generally ASME Class 2 components)

and manages Loss of Material due to General, Pitting, and Crevice Corrosion.

The current design bases for the bresden and Quad Cities ECCS Su6ti6n Headers classify these

as ASME Class 2 components. This is reflected on boundary diagrams LR-DRE- -29 (drawing

coordinates C-3 to C-6), LR-DRE--360-1 (drawing coordinates C-3 to C-6), LR-QDC-39-1

(drawing coordinates E-3 and E-7), and LR-ODC-81-9 (drawing coordinates E-3 and E-7). The

ASME Code Class flags are defined on boundary diagrams LR-DRE-1 1-2 and LR-QDC-1 2-3.

Since both NUREG-1 801 line items provide an NRC-accepted method to manage the loss of

material due to corrosion in carbon steel components, the Dresden and Quad Cities LRA selected

the applicable NUREG-1 801 line item based on current design bases. For this reason, the ECCS

Suction Headers are managed by the Water Chemistry (B.1.2) and One-time Inspection (B.1.23)

aging management programs.

Note: The ECCS Suction Header shown on boundary diagram LR-DRE-29 is shown in black.

It should have been shown in green as an in-scope component.

The staff acknowledges the applicant's basis for the exception to GALL Item lI.B13.1.1-a. Since

the applicant has included the ECCS suction headers under V.D2.1 ECCS Piping and Fittings,

and the staff has accepted the applicant's AMR for the ECCS, including the suction headers,

RAI 3.5-9 is resolved.

The 10 CFR Part 50, Appendix J Inspection and Structures Monitoring Programs are

considered common AMPs. The staff's evaluation of the common AMPs is in SER Section

3.0.3. The staff's evaluation of the ASME Section Xl, Subsection IWE and the Protective

Coating Monitoring and Maintenance Programs is in SER Section 3.5.2.3. The staff's

evaluation of the Fire Protection AMP is in SER Section 3.3.2.3. The staff finds that the

applicant has credited the appropriate AMPs with managing aging of the primary containment.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the primary

containment will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.5.2.4.2 Other Class I Structures

Summary of Technical Information in the Application. This section addresses the other Class 1

structures. The applicant's description of each structure and the component groups requiring

AMR is in the LRA section and table shown in parentheses.

* reactor building (LRA Section 2.4.2 and Table 2.4-2)

* main control room and auxiliary electric equipment room (LRA Section 2.4.3 and Table

2.4-3)

* turbine building (LRA Section 2.4.4 and Table 2.4-4)

* diesel generator building (LRA Section 2.4.5 and Table 2.4-5)

* station blackout building and yard structures (LRA Section 2.4.6 and Table 2.4-6)

* isolation condenser pump house (Dresden only) (LRA Section 2.4.7 and Table 2.4-7)

* makeup demineralizer building (Dresden only) (LRA Section 2.4.8 and Table 2.4-8)

* radwaste floor drain surge tank (LRA Section 2.4.9 and Table 2.4-9)

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* miscellaneous foundations (LRA Section 2.4.10 and Table 2.4-10)

* crib house (LRA Section 2.4.11 and Table 2.4-11)

* Unit 1 crib house (Dresden only) (LRA Section 2.4.12 and Table 2.4-12)

For each component group listed, LRA Tables 2.4-2 through 2.4-12 specify a reference to LRA

Section 3 for the AMR results. The applicant used the SRP-LR report format in LRA Table

3.5-1 to present its AMR for the Class 1 structures components addressed in the GALL Report.

Further evaluation of aging management, as recommended by GALL, is discussed in LRA

Section 3.5.1.1. Aging management programs or evaluations that are different from those in

GALL are described in LRA Section 3.5.1.2. In LRA Table 3.5-2, the applicant identified the

Class 1 structures component groups that are not addressed in the GALL Report and provided

the following information on material, environment, aging effect(s)/mechanism(s), and AMP(s).

Utilizing the Dresden and Quad Cities Aging Management Review Aid, the staff identified the

applicable materials for Class 1 structures components as carbon steel; stainless steel;

galvanized or coated carbon steel; aluminum; reinforced concrete; grout; concrete block;

silicone rubber; polyethylene; and vapor barrier, coal tar pitch, rigid insulation, felt, gravel, or

single-ply hypalon pavers for roofing. The staff also identified the applicable environments as

outside containment, exposed to aggressive environment, indoor, outdoor, weather exposed,

flowing water, exposed to water, ambient inside building, and fluid (water, fuel).

Aging Effects

The LRA identifies the following applicable aging effects:

* loss of material

* change in material properties

* cracking

* separation and water in-leakage

* hardening

* reduction in concrete anchor capacity

Tables 2.4-2 through 2.4-12 of the LRA reference LRA Section 3.5 for the AMR results, except

for the following:

* boral and boraflex neutron absorbing sheets in chemically treated oxygenated water

(LRA References 3.3.1.9 and 3.3.1.12)

* steel fire doors (LRA References 3.3.2.4 and 3.3.1.18)

* cementitious fire proofing and ceramic fiber fire wrap (LRA References 3.3.2.62 and

3.3.2.63)

* concrete block fire barriers (LRA Reference 3.3.2.129)

* fire barrier and flood barrier penetration seals (LRA Reference 3.3.1.18)

* stainless steel spent fuel storage racks in chemically treated oxygenated water (LRA

Reference 3.3.1.11)

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* fire barrier walls, ceilings and floors (LRA Reference 3.3.1.28)

* carbon steel piles exposed to soil and ground water (LRA Reference 3.3.2.207)

Aging Management Programs

The LRA credits the following AMPs for managing the identified aging effects:

* Structures Monitoring Program

* Masonry Wall Program

* RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power

Plants," Program

* Water Chemistry Program

* Fire Protection Program

* Boraflex Monitoring Program

A description of these AMPs is provided in LRA Appendix B. The applicant concluded that the

effects of aging will be adequately managed by these AMPs such that there is reasonable

assurance that the intended functions will be maintained during the period of extended

operation.

Staff Evaluation. This section provides the staff's evaluation of the applicant's AMR for other

Class I structures and the applicability of the AMPs credited with managing the aging effects.

Table 3.5-1 of this SER provides a summary of the staff's evaluation of components, aging

effects/mechanisms, and AMPs listed in LRA Table 3.5-1 for the components that are

addressed in the GALL Report. Section 3.5.2.1 of this SER provides the staff's evaluation of

the aging management evaluations in the GALL Report that are relied on for license renewal,

which do not require further evaluation. Section 3.5.2.2 of this SER provides the staff's

evaluation of the aging management evaluations in the GALL Report that are relied on for

license renewal, for which the GALL Report recommends further evaluation.

The staff's evaluations of the aging management evaluations for the other Class 1 structures

that are different from those described in the GALL Report, or are not addressed in GALL, are

discussed below.

Aging Effects

Concrete: In entry 3.5.1.22 in LRA Table 3.5-1, the applicant identifies a number of exceptions

to the GALL Report for Group 6 structures (water-control structures). These exceptions are

discussed in LRA Sections 3.5.1.2.1 through 3.5.1.2.7.

In LRA Section 3.5.1.2.1, the applicant discussed an exception to aging of concrete due to

settlement. The applicant stated the following:

The Dresden and Quad Cities licensing basis does not include a program to monitor concrete for

settlement nor is a de-watering system in place. Dresden and Quad Cities structures are founded

on rock or naturally compacted soil with no documented changes in groundwater conditions or a

history of settlement. Cracks, distortion and increase in component stress level due to settlement

are not applicable and no aging management is required.

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The staff finds the applicant's explanation to be acceptable because there has been no

requirement to monitor settlement as part of the licensing basis for all four units, and there are

no de-watering systems in place.

In LRA Sections 3.5.1.2.2 through 3.5.1.2.7, the applicant states that the aging management

program RG 1.127, "Inspection of Water-Control Structures Associated with Nuclear Power

Plants," Program (B.1.31) is credited for managing concrete in accessible areas for the

following aging effects/mechanisms:

* loss of material and cracking due to freeze-thaw

* increase in porosity and permeability and loss of strength due to leaching of calcium

hydroxide of concrete

* expansion and cracking due to reaction with aggregates

* loss of material due to abrasion and cavitation of concrete

* cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded

steel

* increase in porosity and permeability, cracking, and loss of material (spalling, scaling) due

to aggressive chemical attack

The staff finds that this aspect of the applicant's AMR is consistent with the GALL Report, and

therefore is acceptable. For the first three aging effects/mechanisms identified above, the

applicant stated that no aging management is required for concrete in inaccessible areas. In

LRA Sections 3.5.1.2.2 through 3.5.1.2.4, the applicant provides the following technical bases

for this conclusion:

* Dresden and Quad Cities have documented evidence to show that the concrete air

content is between 3 percent and 6 percent.

* Plant inspections did not show freeze-thaw degradation.

* Dresden and Quad Cities have documented evidence that the concrete used was

constructed in accordance with the recommendations in ACI 201.2R-77 for durability

and with no evidence of reactive aggregates.

The staff finds this aspect of the applicant's AMR to be consistent with the GALL Report and

therefore acceptable.

Section 3.5.1.2.5 of the LRA states that loss of material due to abrasion and cavitation of

concrete in accessible areas is managed by the RG 1.127, "Inspection of Water-Control

Structures Associated with Nuclear Power Plants," Program. The applicant further stated that

the Dresden and Quad Cities water flow velocity (3.68 ftls) is less than the industry abrasion

erosion threshold velocity of 4 ftls, and also less than the industry cavitation threshold velocity of 25 ftls. The applicant concluded that loss of material due to abrasion and cavitation of

concrete in inaccessible areas is not applicable and no aging management is required. As

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discussed under GALL Item IlIl A6.1 -h, the staff expects that for Gro-up 6 structures

(water-control structures), loss of material due to abrasion and cavitation of reinforced concrete

in a flowing water environment will be managed by the RG 1.127 program. This applies to all

concrete-exterior above and below grade, foundation, and interior slab. In RAI 3.5-11, the

staff requested that the applicant (1) clarify what is meant by "accessible and Ninaccessible"

areas for all Group 6 components, (2) identify the reference for the stated industry abrasion

erosion and cavitation threshold velocities, and (3) provide the technical basis for the reported

Dresden and Quad Cities water flow velocity.

In response to RAI 3.5-11, the applicant stated the following:

(1) For Group 6 Structures, the term inaccessible applies to those structures and portions of

structures that are either buried or submerged under water where the confined area access or

high flow rates make diver entrance unsafe without a dual unit outage.

(2) Abrasion and cavitation are limited to concrete exposed to flowing water containing abrasives.

Industry sources use an abrasion erosion threshold velocity for concrete of 4.0 feet per second (Ref.: EPRI TR-1 10025, Concrete Structural Aging References Manual of Nuclear

Power Plants) and a cavitation threshold velocity for concrete of 25 fps when abrupt changes

occur in closed conduits and 40 fps In continuously flowing water (Refs. EPRI TR-1 14881,

Aging Effects for Structures and Structural Components (Structural Tools), Final Report and

EPRI TR-103842, Class-I Structures - Ucense Renewal Industry Report). Cavitation is not

applicable for concrete structures continuously exposed to flowing water if the water velocity is

less than these values.

(3) The maximum water velocity in the crib houses for Dresden and Quad Cities Is based on

the velocity of the circulating water pump combined with the diesel generator cooling

water pump, due to their close proximity and the reduced flow area in the intake tunnel

where these pumps are located. The circulating water pump capacity is 157,000 gpm and the diesel generator cooling water pump capacity ranges from 1 1 00 gpm to 1304

gpm. Flow area In the Intake tunnel adjacent to the circulating water pump is

conservatively 8 ft x 12 ft or 96 ft2.

Velocity in fps = (158,304 gaVmin) x (1 min/60 sec) x (0.134 ft3/gal) I (96 ft2) = 3.68 fps < 4.00

fps.

Since underwater accessible areas will be inspected, any occurrences of abrasion erosion or

cavitation will be detected in these areas. However, the staff is unclear about the applicant's

justification that abrasion erosion and cavitation do not require aging management for

inaccessible areas. Part of the definition of inaccessible areas', in part (1) of the response, is

"where...high flow rates make diver entrance unsafe without a dual unit outage." These would

appear to the areas most susceptible to abrasion erosion and possibly cavitation. The applicant

was requested to quantify "high flow rates.' In addition, it is unlikely that the water velocity is a

uniform 3.68 ft/sec across the entire flow area in the intake tunnel, adjacent to the circulating

water pump. The applicant was requested to consider a realistic velocity profile in estimating

the maximum water velocity. In a letter dated December 5, 2003, the applicant stated that the

inaccessible areas are better described as those areas where continuous flow makes diver

entrance unsafe without a dual unit outage. The highest velocities experienced in the

underwater structures will be in the individual circulating water bays, adjacent to the circulating

water pumps. The 3.68 ft/sec flow velocity corresponds to the velocity at the pump suction

centerline, which is considered to be a high value. The individual circulating water pump bays

are accessible and will be inspected since they can be taken out of service during the

applicable unit outage. Since the limiting locations for flow velocities and potential erosion

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effects are to be inspected, the inaccessibility of the areas of lower flow velocity is not

detrimental to aging management. The staff finds the applicant's response acceptable. RAI

3.5-11 is resolved.

For Group 6 structures (water-control structures), LRA Section 3.5.1.2.6 indicates that cracking,

loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel of

concrete is managed by RG 1.127, Inspection of Water-Control Structures Associated with

Nuclear Power Plants, only for accessible areas. Similarly, LRA Section 3.5.1.2.7 indicates that

increase in porosity and permeability, cracking, and loss of material (spalling, scaling) due to

aggressive chemical attack of concrete is managed by RG 1.127, Inspection of Water-Control

Structures Associated with Nuclear Power Plants, only for accessible areas. Sections 3.5.1.2.6

and 3.5.1.2.7 of the LRA indicate that aging management is not required for these aging

effects/mechanisms in inaccessible areas because Dresden and Quad Cities ground-water test

data show that the below-grade environment is not aggressive based on NUREG-1 801 criteria

(chlorides less than 500 ppm, sulfates less than 1500 ppm, and pH greater than 5.5);

examination of representative samples of below-grade concrete, when excavated for any

reason, is included as part of the Structures Monitoring Program; and to ensure conditions are

maintained throughout the period of extended operation, the Structures Monitoring Program

(B.1.30) will be enhanced to include monitoring of below-grade water chemistry to demonstrate

that the environment remains nonaggressive.

As indicated in GALL Items IlIl A6.1-d and e, for Group 6 structures (water-control structures),

these aging effects/mechanisms are managed by the RG 1.127 program for all concrete. In the

special case of water-control structures, the applicant's technical bases for excluding

inaccessible areas from aging management may be applied only to concrete buried in the

ground. In RAI 3.5-12, the staff requested that the applicant (a) define the term inaccessible

areaso as it relates to the subject aging effects/mechanisms in water-control structures and

specifically discuss whether below-grade and below-water concrete in water-control structures

is being excluded from aging management; and (b) if applicable, submit a detailed technical

justification for not managing aging of below-grade/below-water concrete in water-control

structures, in light of past industry operating experience indicating there is a significant potential

for degradation.

In its response to RAI 3.5-12, the applicant stated the following:

(a) The term inaccessible applies to those structures and portions of structures that are either

buried or submerged under water where the confined area access makes diver entrance

unsafe without a dual unit outage. The term accessible applies to those structures and

portions of structures that are interior, above-grade exterior, or under water accessible.

(b) Aging Management Reference 3.5.1.22 states that this aging management evaluation is

'Consistent with NUREG 1801, with exception'. The exceptions to NUREG-1 801 are

described in LRA sections 3.5.1.2.6 and 3.5.1.2.7. The technical bases for exceptions

3.5.1.2.6 and 3.5.1.2.7 apply to the below-grade and inaccessible under water

environments.

This technical justification for Group 6 structures is the same as the evaluation for Groups 1, 2,

and 3 structures as discussed under NUREG-1801, Items IlIl Al. 2, 3.1-e and IlIl Al, 2, 3.1-g.

Dresden and Ouad Cities ground water test data obtained during construction, in the 1980's, 1990

's, and 2000's shows that the below-grade environment is not aggressive based on NUREG-1801

criteria with chlorides less than 500 ppm, sulfates less than 1500 ppm, and pH greater than 5.5.

The specified aging effects are not significant and no aging management is required of

components in inaccessible areas. As recommended in the letter from Christopher I. Grimes to

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Alan Nelson dated 4/5/02, Subject: 'Staff response to industry's proposed revisions of chapters 11

and Ill of generic aging lessons learned (GALL) report on aging management of concrete

elements' that further evaluation of concrete components in inaccessible areas is not required for

which non-aggressive environment can be demonstrated. Therefore, Exelon is In compliance with

the Interim Staff Guidance (ISG) on concrete for inaccessible area concrete components. To

ensure conditions are maintained throughout the period of extended operations, the Structures

Monitoring Program (B.1.30) includes monitoring of below-grade water chemistry to demonstrate

that the environment remains non-aggressive.

The applicant has not specifically addressed a key element of this RAI. The ultimate heat sink

raw water is considered aggressive by its nature, and all concrete exposed to it needs to be

managed for these aging effects/mechanisms. In light of past industry operating experience

indicating there is a significant potential for degradation, the applicant was requested to

specifically discuss whether below-water concrete in water-control structures is being excluded

from aging management, and if applicable, submit a detailed technical justification for not

managing aging of below-water concrete in water-control structures. The applicant was also

requested to submit its AMR for concrete exposed to the ultimate heat sink raw water, and

either identify the credited AMPs or submit a detailed technical justification for not managing the

aging of concrete exposed to raw water. In a letter dated December 5, 2003, the applicant

stated that all in-scope below-water concrete (submerged) exposed to the ultimate heat sink

raw water environment will be managed for aging except the inaccessible common area in the

crib house intake outside of the individual bays to the circulating water pumps where continuous

flow makes diver entrance unsafe without dual unit outage. Aging management program

B.1.31 provides for managing the aging effects of in-scope accessible concrete exposed to the

ultimate heat sink raw water environment at Dresden and Quad Cities. The staff finds the

applicant's response acceptable and considers RAI 3.5-12 resolved.

Steel: Under Reference No. 3.5.1.28 in LRA Table 3.5-1, the applicant identified an exception

to the GALL Report for cracking due to crack initiation and growth due to SCC and loss of

material due to crevice corrosion. This exception applies to the stainless steel liners in the

Dresden and Quad Cities radwaste floor drain surge tanks. In LRA Section 3.5.1.2.8, the

applicant states the following:

Stainless steel liners in the Dresden and Quad Cities floor drain surge tanks are not susceptible to

cracking due to crack initiation and growth due to SCC or loss of material due to crevice corrosion

and do not require aging management.

The floor drain surge tanks are vented and constructed of reinforced concrete with a stainless steel

liner. The floor drain surge tank liner Is not considered susceptible to SCC, since the tanks are

vented (low service pressure), concentrated chlorides in the effluent are not expected, and the

temperature of effluents would be ambient (less than threshold temperature of 140 degrees F for

SCC). Stainless steel is susceptible to crevice corrosion given a sufficiently narrow crevice in the

presence of oxygen. Crevice corrosion most frequently occurs in joints, and connections, or points

of contact between metals and nonmetals, such as gasket surfaces, lap joints, and under bolt

heads where contaminants can concentrate. The stainless steel liner has all welded seams and

plug welds for anchorage, with all welds ground smooth. Therefore, the occurrence of crevice

corrosion in the tank liner is not expected due to its configuration.

In addition, the floor drain surge tank has a drain system installed between the liner and concrete

that would intercept leakage from behind the liner plate weld seams and drain the leakage to the

attached pump house room. There have been no documented corrective action requests related

to aging associated with the stainless steel liner plate drains.

The staff finds the applicant's explanation to be acceptable and agrees that the stainless steel

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liners in the floor drain surge tanks do not require aging management.

In LRA Table 3.5-2 (Reference Nos. 1, 2, 6, and 16), the applicant identified loss of

material/general corrosion as an aging effect/mechanism requiring management for the

following galvanized or coated carbon steel components in the station blackout building and

yard structures:

* bus duct covers

* bus duct supports

* dead end structures

* transmission towers

The applicant credited the Structures Monitoring Program as the AMP for these component

groups. In Appendix B.1.30, Structures Monitoring Program, the applicant stated that the

program will be enhanced to provide for inspections of structural steel in offsite power structural

components. The staff finds the applicant's AMR for these components to be acceptable and

agrees that the Structures Monitoring Program is an acceptable program to manage the

identified aging effect.

Table 2.4-6 of the LRA references LRA Table 3.3-2, entry 3.3.2.207, for the AMR of carbon

steel piles exposed to soil and ground water in the station blackout building (Dresden only).

Section 2.4.6 of the LRA provides no description of the steel piles. In SER Section 2.4.6.2, the

staff requested the applicant in part (c) of RAI 2.4.5 to describe the steel piles at Dresden and

define intended functions and explain why the 'Aging Management Ref" for the steel piles is

3.3.2.207, which is in LRA Section 3.3 for Auxiliary Systems. The applicant described the steel

piles and revised the AMR reference. Consistent with past staff determinations, the applicant

has concluded that no aging management is necessary for the steel piles. The staff accepts

this assessment.

Elastomers/Roofing: In LRA Table 3.5-2 (Reference Nos. 3, 4, 7, 11, 12, and 13), the

applicant identifies the following aging effects/mechanisms for elastomer materials that require

management in various component groups for Class 1 structures:

* hardening cracking/elastomer degradation in silicone rubber used in caulking/sealants,

door seals, and secondary containment boot seals

* change in material properties/loss of resiliency, loss of strength, loss of elasticity in

silicone rubber caulking/sealants and polyethylene seismic gap filler

* separation and water in-leakage/weathering in vapor barrier, coal tar pitch, rigid

insulation, felt, gravel, or single-ply hypalon pavers for roofing

The applicant credited the Structures Monitoring Program as the AMP for these component

groups. In Appendix B.1.30, "Structures Monitoring Program," the applicant states that the

program will be enhanced to provide for inspection parameter specificity for nonstructural joints,

roofing, grout pads, and isolation gaps. The staff finds the applicant's AMR for these

components to be acceptable and agrees that the Structures Monitoring Program is an

acceptable program to manage the identified aging effects.

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Aluminum New Fuel Storage Racks: In LRA Table 3.5-2 (Reference No. 3.5.2.10), the

applicant stated that there are no viable aging effects for the aluminum new fuel racks in the

indoor environment of the reactor building, and concluded that n6oAMP is required. The staff

agrees with the applicant that no aging management is required for the aluminum new fuel

racks.

Spent Fuel Storage Rack Materials: Table 2.4-2 of the LRA references LRA Table 3.3-1 for

the AMR of the spent fuel storage racks and the neutron absorbers in the reactor building:

* reduction of neutron-absorbing capacity and loss of material for boral and boraflex

neutron absorbing sheets in chemically treated oxygenated water (boral-LRA

Reference 3.3.1.9; boraflex-LRA Reference 3.3.1.12)

* crack initiation and growth of stainless steel spent fuel storage racks in chemically

treated oxygenated water (LRA Reference 3.3.1.1 1)

In LRA Table 3.3-1, Reference 3.3.1.12 identifies the Boraflex Monitoring AMP (LRA B.1.36) for

managing reduction of neutron-absorbing capacity in boraflex, used at Quad Cities. The

discussion column indicates that this AMP is consistent with the GALL Report. The staff finds

this acceptable.

In LRA Table 3.3-1, Reference 3.3.1.11 identifies the Water Chemistry AMP (LRA B.1.2) for

managing crack initiation and growth in stainless steel spent fuel storage racks. The discussion

column indicates that this AMP is consistent with the GALL Report, with exceptions as noted in

LRA B.1.2. The exceptions do not affect water chemistry monitoring of the spent fuel pool.

On the basis that the spent fuel storage racks are made of the same material as the spent fuel

pool liner and are in the same environment, the applicant's AMP for the spent fuel pool liner

(i.e., Water Chemistry AMP plus fuel pool water level monitoring) will also manage aging of the

spent fuel storage racks. Any reduction in the spent fuel pool water level that is attributed to

crack initiation and growth in the liner would be an indicator that crack initiation and growth may

also be occurring in the spent fuel storage racks. The staff finds this acceptable.

Fire and Flood Barrier Materials: Tables 2.4-2 through 2.4-7, 2.4-11, and 2.4-12 of the LRA

reference LRA Tables 3.3-1 and 3.3-2 for the AMR results for the following fire and flood barrier

items:

* loss of materiaVwear for steel fire doors (LRA References 3.3.2.4 and 3.3.1.18)

* reduced fire protection capability for cementitious fire proofing and ceramic fiber fire

wrap (LRA References 3.3.2.62 and 3.3.2.63) (based on applicant's response to an

RAI related to LRA Section 2.3)

* cracking of concrete block fire barriers (LRA Reference 3.3.2.129)

* increased hardness and shrinkage of sealant for fire barrier and flood barrier penetration

seals (LRA Reference 3.3.1.18)

* cracking and spalling and loss of material for concrete and reinforcement of fire barrier

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walls, ceilings, and floors (LRA Reference 3.3.1.28)

The applicant's exceptions to the GALL Fire Protection AMP are described in LRA Section

B.1.18. These exceptions primarily relate to the frequency of inspection of the various fire

protection component groups. The staff review of the applicant's Fire Protection AMP is

presented in SER Section 3.3.2.3.

The aging effects identified in the LRA for the Class 1 structures are consistent with industry operating experience for the materials and environments listed. The staff finds that all the

plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs with managing the aging effects described

above for Class 1 structures:

* Structures Monitoring Program

* Masonry Wall Program

* RG 1.127, "Inspection of Water-Control Structures Associated with Nuclear Power

Plants," Program

* Water Chemistry Program

* Fire Protection Program

* Boraflex Monitoring Program

The Structures Monitoring and Water Chemistry Programs are considered common AMPs. The

staff's evaluation of the common AMPs is in SER Section 3.0.3. The staff's evaluation of the

Masonry Wall Program and RG 1.127, Inspection of Water-Control Structures Associated with

Nuclear Power Plants, is in SER Section 3.5.2.3. The staff's evaluation of Fire Protection and

Boraflex Monitoring is in SER Section 3.3.2.3. The staff finds that the applicant has credited

the appropriate AMPs to manage the aging effects for the materials and environments

associated with the Class 1 structures.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the Class 1

structures will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.4.3 Station Chimney (LRA Section 2.4.13)

Summary of Technical Information in the Application. The applicant's description of the station

chimney (Dresden and Quad Cities) is in LRA Section 2.4.13. The component groups requiring AMR are identified in LRA Table 2.4-13. For each component group listed, LRA Table 2.4-13

specifies a reference to LRA Section 3 for the AMR results. The AMR results are provided in

LRA Tables 3.5-1 and 3.5-2. The applicant used the SRP-LR report format in LRA Table 3.5-1

to present its AMR for station chimney components addressed in the GALL Report. Further

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evaluation of aging management, hs recommended by GALL, is discussed in LRA Section

3.5.1.1. In LRA Table 3.5-2, the applicant identified the station chimney component groups that

are not addressed in GALL and provided information about material, environment, aging

; effect(s)/mechanism(s), and AMPs.

Utilizing the Dresden and Quad Cities Aging Management Review Aid (February 2003), the

staff identified the applicable materials for Station Chimney components as carbon steel,

reinforced concrete, concrete block, and silicone rubber. Utilizing the Review Aid the staff also

identified the applicable environments as exposure to aggressive environment and weather

exposed.

Aging Effects

The LRA identifies the following applicable aging effects for the station chimney components:

* loss of material

: * change in material properties

* cracking

Table 2.4-13 of the LRA references LRA Section 3.5 for the AMR results for all components.

Aging Management Programs

The LRA credits the following AMPs for managing the identified aging effects:

* Structures Monitoring Program

* Masonry Wall Program

A description of these AMPS is provided in LRA Appendix B. The applicant concludes that the

effects of aging will be adequately managed by these AMPs such that there is reasonable

assurance that the intended functions will be maintained during the period of extended

operation.

Staff Evaluation. This section provides the staff's evaluation of the applicant's AMR for the

station chimney, and of the applicability of the AMPs credited with managing the aging effects.

Table 3.5-1 of this SER provides a summary of the staff's evaluation of components, aging

effects/mechanisms, and AMPs listed in LRA Table 3.5-1 for the components that are

addressed in the GALL Report. SER Section 3.5.2.1 of this SER provides the staff's evaluation

of the aging management evaluations in the GALL Report that are relied on for license renewal,

which do not require further evaluation. Section 3.5.2.2 of this SER provides the'staff's

evaluation of the aging management evaluations in the GALL Report that are relied on for

license renewal, for which the GALL Report recommends further evaluation.

The staff's evaluations of the aging management evaluations for the station chimney that are

not addressed in the GALL Report are discussed below.

Aging Effects

Elastomers: In LRA Table 3.5-2 (Reference No. 3.5.2.4), the applicant identified change in

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material properties/loss of resiliency, loss of strength, loss of elasticity in silicone rubber

caulking/sealants as an aging effect/mechanism requiring management in the station chimney.

The applicant credited the Structures Monitoring Program as the AMP for this component

group. In Appendix B.1.30, Structures Monitoring Program, the applicant stated that the

program will be enhanced to provide for inspection parameter specificity for nonstructural joints,

roofing, grout pads, and isolation gaps. The staff finds the applicant's AMR for this component

to be acceptable and agrees that the Structures Monitoring Program is an acceptable program

to manage the identified aging effects.

Concrete Block: In LRA Table 3.5-2 (Reference No. 3.5.2.9), the applicant identified

cracking/restraint, shrinkage, creep, and aggressive environment in concrete block masonry

walls as aging effects/mechanisms requiring management in the station chimney. The

applicant credited the Masonry Wall Program as the AMP for this component group. The staff

finds the applicant's AMR for this component to be acceptable and agrees that the Masonry

Wall Program is an acceptable program to manage the identified aging effects.

The aging effects identified in the LRA for the station chimney are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs to manage the aging effects described above for

the station chimney:

* Structures Monitoring Program

* Masonry Wall Program

The Structures Monitoring Program is considered a common AMP. The staff's evaluation of the

common AMPs is in SER Section 3.0.3. The staff's evaluation of the Masonry Wall Program is

in SER Section 3.5.2.3.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the station

chimney will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.5.2.4.4 Cranes and Hoists

Summary of Technical Information in the ApDlication. The applicant described the cranes and

hoists (Dresden and Quad Cities) in LRA Section 2.4.14. Table 2.4-14 of the LRA lists the

component groups and specifies the location of the AMR results in LRA Section 3. For cranes

and hoists, the AMR results are provided in LRA Table 3.3-1, under Auxiliary Systems. The

applicant used the SRP-LR report format in LRA Table 3.3-1 to present its AMR for cranes and

hoists addressed in the GALL Report. Further evaluation of aging management, as

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recommended by GALL, is discussed in LRA Sections 3.3.1.1.6 and 4.7.1. The credited AMP,

including any enhancements or exceptions to the comparable GALL program, is described in

LRA Section B.1.15.

Utilizing the Dresden and Quad Cities Aging Management Review Aid, the staff identified the

applicable materials for cranes and hoists as structural steel A-36, A-7, A-285, and A-759, and

the applicable environment as air at 100 percent relative humidity and 49 0C (120 'F).

Aging Effects

The applicant identified the applicable aging effects for the cranes and hoists in LRA Table

3.3-1 (Reference Nos. 3.3.1.3 and 3.3.1.14) as cumulative fatigue damage and loss of material

due to general corrosion and wear. Cumulative fatigue is a TLAA, addressed in LRA Section

4.7.1.

Aging Management Programs

The applicant credits the Inspection of Overhead Heavy Load and Light Load (Related to

Refueling) Handing Systems (B.1.15) AMP for managing loss of material due to general

corrosion and wear. A description of this AMP is provided in LRA Appendix B, Section B.1.15.

The applicant concludes that loss of material due to general corrosion and wear will be

adequately managed by this AMP such that there is reasonable assurance that the intended

functions will be maintained during the period of extended operation.

Staff Evaluation. This section presents the staff's evaluation of the applicant's AMR for cranes

and hoists, and the applicability of the AMP credited with managing the aging effects.

Aging Effects

Table 3.3-1 (Reference No. 3.3.1.3) of the LRA states that further evaluation of cumulative

fatigue damage for cranes and hoists is provided in LRA Section 3.3.1.1.6. Section 3.3.1.1.6

of the LRA states that cumulative fatigue damage of load handling cranes is a TLAA, as defined

in 10 CFR 54.3, and is evaluated in accordance with 10 CFR 54.21(c)(1). Section 4.7.1 of the

LRA "Reactor Building Crane Load Cycles," documents the applicant's evaluation of this TLAA.

On the basis that the number of load cycles expected over a 60-year operating life is

significantly less than the initial design rating for full-load cycles, the applicant has concluded,

that this TLAA remains valid for the period of extended operation. The staff's detailed

evaluation of this TLAA is provided in SER Section 4.7.

Table 3.3-1 (Reference No. 3.3.1.14) of the LRA states that loss of material due to general

corrosion and wear of cranes, including bridges, trolleys, and rail systems, will be managed by

the AMP Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling

Systems, described in LRA Section B.1.15.

Based on information provided in LRA Section 2.4.14, the staff could not identify which "LRA

Aging Management Ref No.' is applicable to each of the crane/rail systems included in the

scope of LRA 2.4.14. Also, it was unclear to the staff why cranes and hoists have been split

into two groups, covered under different sections of LRA Section 2.0, and why all references to

the AMR results point to LRA Section 3.3-Auxiliary Systems. In its response to RAI 2.4-9, the

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applicant listed all cranes and hoists that are in the license renewal scope and also listed all

cranes and hoists that are not in the license renewal scope. The staff found the applicant's

response to RAI 2.4-9 to be acceptable, from the standpoint of clarifying the scope.

The applicant also clarified the AMR of cranes and hoists in its response to RAI 2.4-9. Cranes

and hoists related to refueling are included under auxiliary systems, while all other cranes and

hoists within the scope of license renewal are included under structures. In all cases, the AMP

Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems,

described in LRA Section B.1.15, is credited with managing loss of material due to general

corrosion and wear. The staff reviewed this AMP to ensure that all cranes and hoists are

included in its scope. The AMP description in LRA Section B.1.15 addresses only load handling

systems related to refueling. In a letter dated December 5, 2003, the applicant stated that the

program scope is not restricted to cranes and hoists related to refueling but includes all cranes

and hoists within the scope of license renewal. The staff finds the applicant's response

adequate.

The aging effects identified in the LRA for the cranes and hoists are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

plausible the aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the AMP Inspection of Overhead Heavy Load and Light Load

(Related to Refueling) Handling Systems (B.1.15) with managing loss of material due to general

corrosion and wear for cranes and hoists.

The staff's detailed evaluation of this AMP is provided in SER Section 3.3.2.3.

On the basis of its review, the staff finds that the AMPs credited in the LRA far the cranes and

hoists will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.5.2.4.5 Component Supports Commodity Group

Summarv of Technical Information in the Application. The applicant's description of the

component supports commodity group (Dresden and Quad Cities) is in LRA Section 2.4.15.

The component groups requiring AMR are identified in LRA Table 2.4-15. For each component

group listed, LRA Table 2.4-15 specifies a reference to LRA Section 3 for the AMR results. The

applicant used the SRP-LR report format in LRA Table 3.5-1 to present its AMR for the

component supports commodity group components addressed in the GALL Report. Further

evaluation of aging management, as recommended by the GALL Report, is discussed in LRA

Section 3.5.1.1. Aging management programs or evaluations that are different from those in

GALL are described in LRA Section 3.5.1.2. In LRA Table 3-5-2, the applicant identified the

component supports commodity group components that are not addressed in the GALL Report

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and provided information on material,* environment, aging effect(s)/mechanism(s), and

AMP(s).

Utilizing the Dresden and Quad Cities Aging Management Review Aid (February 2003), the

staff identified the applicable materials for the component supports commodity group as carbon

steel, low-alloy steel (yield strength 150 ksi), stainless steel, steel and nonsteel materials (e.g.,

lubrite plates), and nonmetallic materials (e.g., rubber). Utilizing the Review Aid, the staff

identified the applicable environments as inside containment; outside containment; submerged

(torus grade water); and 25-288 0C (77-550 'F) demineralized water.

Aging Effects

The LRA identifies the following applicable aging effects:

* loss of material

* cumulative fatigue damage

* cracking

* loss of mechanical function

* reduction or loss of isolation function

In most cases, LRA Table 2.4-15 references LRA Section 3.5 for the AMR results for all

components. For some structural support members, LRA Table 2.4-15 references LRA Section

3.2, LRA Table 3.2-2 (Reference Nos. 3.2.2.79, 3.2.2.80, and 3.2.2.81).

Aging Management Programs

The LRA credits the following AMPs for managing the identified aging effects:

* Structures Monitoring Program

* ASME Section Xl, Subsection IWF Program

* Bolting Integrity Program

* Water Chemistry Program

* One-Time Inspection

A description of these AMPs is provided in LRA Appendix B. The applicant concludes that the

effects of aging will be adequately managed by these AMPs such that there is reasonable

assurance that the intended functions will be maintained during the period of extended

operation.

Staff Evaluation. This section presents the staff's evaluation of the applicant's AMR for the

component supports commodity group and the applicability of the AMPs credited with managing

the aging effects. Table 3.5-1 of this SER provides a summary of the staff's evaluation of

components, aging effects/mechanisms, and AMPs listed in LRA Table 3.5-1 for the

components that are addressed in the GALL Report. Section 3.5.2.1 of this SER provides the

staff's evaluation of the aging management evaluations in the GALL Report that are relied on

for license renewal, which do not require further evaluation. Section 3.5.2.2 of this SER

provides the staff's evaluation of the aging management evaluations in the GALL Report that

are relied on for license renewal, for which the GALL Report recommends further evaluation.

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The staff's evaluations of the aging management evaluations for the component supports

commodity group that are different from those described in the GALL Report, or are not

addressed in GALL, are discussed below.

Aging Effects

Section 3.5.1.2.1 0 of the LRA discusses an exception to the GALL Report for XI.Ml 8, Bolting

Integrity, identified under Reference No. 3.5.1.32 of LRA Table 3.5-1. The applicant states that

Dresden and Quad Cities recirculation piping loop component supports inside the containment

have ASTM 193 Grade B7 high-strength low-alloy steel bolting', which will be managed by

ASME Section XI, Subsection IWF (B.1 .27). The applicable GALL item number is lll.B.1 .1.2-a,

which identifies XI.Ml 8, Bolting Integrity, as an acceptable AMP for high-strength low-alloy steel

bolts (yield strength greater than 150 ksi) used in NSSS component supports. In RAI 3.5-13,

the applicant was requested to provide the following information:

(a) It is stated in LRA Section 3.5.1.2.1 0 that "the specification for ASTM 193 Grade B7 lists

minimum yield strength of 105 ksi, with no upper yield strength installed.' Clarify what is

meant by the phrase "no upper yield strength installed.'

(b) Verify that the actual yield strengths of the Dresden and Quad Cities recirculation piping

loop component support bolting do not exceed 150 ks.

(c) Clarify whether other Class 1, 2, 3 and MC component supports use high-strength

low-alloy steel bolts. If so, describe the materials used and the corresponding AMP.

In its response to RAI 3.5-13, the applicant stated the following:

Exelon has reviewed LRA Section 3.5.1.2.10 and the following additional information is provided:

(a) Table 2, "Mechanical Requirements', foundin ASTM A193, Standard Specification for

Alloy-Steel and Stainless Steel Bolting Materials for High-Temperature Service, specifies a

minimum yield strength of 105 Ws. No upper limit is specified in the ASTM standard. The phrase

.no upper yield strength installed' means there is no upper yield strength mentioned in the ASTM

standard.

(b) ASTM Al93, Standard Specification for Al 93, Grade B7 material, specifies amaximum

Brinell Hardness number of 321 HB for recirculation piping loop component support bolting that is

less than 2-'k2inch diameter. Based on ASTM A370, Standard Specification, Section 1, volume

01.01, a maximum Brinell Hardness number of 321 HB (interpolated between 319 HB and 327 HB)

equates to a tensile strength of 153 ksi (interpolated between 152 ksi and 156 ksi). Therefore, the

maximum yield strengths of the recirculation piping loop component support bolting are rounded to

an approximate tensile strength of 150 ksi threshold value.

(c) Dresden UFSAR Section 3.9.3.1.1.3.3 and Quad Cities UFSAR Section 3.9.3.1.1.3 state that

there are high strength bolts used in a friction type connection at the reactor skirt base. The

material used for these high strength bolts is assumed to be ASTM Al 93, Grade B7 or equivalent.

ASME Section XI, Subsection IWF (B.1.27) aging management program inspects the bolting. There are no other documented uses of high strength bolting found on Class 1, 2, 3 and MC

Component supports at Dresden and Quad Cities Nuclear Power Stations.

The staff finds that the applicant's response related to ASTM Al 93, Grade B7 bolting material is

sufficient to establish that the upper limit on yield strength is less than 150 ksi; consequently;'

the additional inspections of XI.M.1 8 Bolting Integrity are not warranted for Al 93, Grade B7.

However, in part (c) of its response, the applicant has assumed that the bolt material used in "a

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friction type connection at the reactor skirt base' is ASTM A193, Grade B7 or equivalent. The

applicant was requested to confirm that assumption or commit to inspection in accordance with

NUREG-1801, Program XI.M.18 Bolting Integrity. In a letter dated December 5,2003, the

applicant stated that it would commit to inspection in accordance with NUREG-1 801,I Program

XI.M.1 8 Bolting Integrity since it could not confirm that the yield strength of the bolts would be

less than 150 ksi. This is part of Commitment #12 in Appendix A of this SER. The staff finds

the applicant's response acceptable and considers RAI 3.5-13 resolved.

Section 3.5.1.2.11 of the LRA discusses an exception to the GALL Report for the AMP XI.S3,

ASME Section Xl, Subsection IWF. This exception is identified under Reference No. 3.5.1.31

of LRA Table 3.5-1. The applicant proposes to manage aging of downcomer bracing by

inspections performed under the applicant's AMP ASME Section Xl, Subsection IWE (B.1.26).

The applicable GALL item number is Ill.B1.3.1-a, which identifies ASME Section Xl, Subsection

IWF as an acceptable AMP for support members. The staff requested in RAI 3.5-14 that the

applicant (1) describe any inspections and schedules that would be required under Subsection

IWF that will not be performed under the applicant's proposed use of Subsection IWE and (2)

provide the technical bases for any deviations from the requirements of Subsection IWF.

In its response to RAI 3.5-14, the applicant stated the following:

(1) There are no inspections required by Subsection IWF that will not be performed by the use of

Subsection IWE. Per the 1989 Edition and the 1992 Edition, with the1992 Addenda of ASME

Section Xi, Table IWE-2500-1, Item E1.11, the Class MC integral attachments are subject to a

General Visual Examination (as described In IWE-3510.1) prior to each Type A Test.

Additionally, per Item E1.12, these Integral attachments are subject to a VT-3 each inspection interval. Per the 1995 Edition, with the 1996 Addenda of ASME Section XI, Table

IWF-2500-1, supports are subject to a VT-3 each inspection interval.

(2) The bases for making this change is the comprehensive containment inservice inspection (CISI) which was recently mandated by the Nuclear Regulatory Commission final rulemaking

per an amendment to the Code of Federal Regulations (10 CFR 50.55a). This rulemaking incorporates, by reference, the requirements of the 1992 Edition with the 1992 Addenda of the

ASME Boiler and Pressure Vessel Code, Section Xl, Division 1, Subsections IWE and IWL

with specified modifications. The final rulemaking was published on August 8, 1996 and

specified an effective date of September 9, 1996 as well as an expedited implementation of

these requirements within five years of the effective date (September 9. 2001). In response,

the Dresden and Ouad Cities CISI program included these supports as part of the IWE

examination boundary.

The staff finds the applicant's basis for conducting inspection of downcomer bracing under the

IWE AMP (B.1.26) to be reasonable and acceptable. Thus, RAI 3.5-14 is resolved.-

In Table 3.5-2 of the LRA, Reference No. 3.5.2.5, "Clevis Pins,' identifies three different

component groups (torus columns, vent systems, and ESF lines), two materials (carbon steel

and stainless steel), and three environments (submerged in torus grade water, inside

containment and outside containment). For each of the three different component groups, at

both Dresden and Quad Cities, the applicant was requested in RAI 3.5-15 to (1) identify all

aging effects/mechanisms that were evaluated for each combination of material and

environment, including those not requiring aging management; and (2) submit the technical

basis for each aging management conclusion.

In its response to RAI 3.5-15, the applicant stated the following:

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For evaluation of carbon steel and stainless steel materials, 'inside or outside containment' is

treated as one environment. Thus, as evaluated, there are two materials and two environments

associated with each of the three different clevis pin component groups. These are

Carbon Steel - Submerged (torus grade water) inside or outside containment

Stainless Steel - Submerged (torus grade water) inside or outside containment.

The applicant provided further clarification by correcting entry 3.5.2.5 in LRA Table 3.5-2 to

show the correct combinations of materials, environments, and aging effects for the clevis pins.

In addition, the applicant corrected Table 2.4-15 to show the proper AMR references.

The staff finds that the applicant's response clarifies the AMR and the credited AMPs for the

clevis pins. The applicant has identified cracking due to SCC as an applicable aging

effect/aging mechanism for stainless steel clevis pins submerged in torus grade water and

credited the Water Chemistry Program for aging management. The staff position is that some

verification of the effectiveness of the Water Chemistry Program is necessary. In a letter dated

December 5, 2003, the applicant stated that it will include inspection for SCC as part of its

one-time inspection to validate the effectiveness of the Water Chemistry Program in managing

the aging of stainless steel components in the torus. This is part of Commitment #23 of

Appendix A of this SER. The staff finds the applicant's response acceptable and considers RAI

3.5-15 resolved.

In Table 3.5-2, Reference No. 3.5.2.14, "Support Members,' states that stainless steel pipe

support stanchions are used on the recirculation piping 28" lines at Dresden and Quad Cities.

The applicant credited ASME Section Xl, Subsection IWF (B.1.27) with managing the stainless

steel support members, inside or outside containment, for loss of material due to pitting and

crevice corrosion. In RAI 3.5-16, the applicant was requested to (1) describe the location of all

the stainless steel components and identify the specific environments to which they are

exposed; (2) identify all aging effects/mechanisms that were evaluated, including those not

requiring aging management, and provide the technical basis for each conclusion; and (3)

discuss the technical basis for the selection of the AMP used to manage the applicable aging

effects.

In response to the applicable part of RAI 3.5-16, the applicant stated the following:

(1) The stainless steel pipe support stanchions are located on the 'A' and 'B' Recirculation Pump

suction and discharge piping, inside the drywell portion of the containment at both Quad Cities

and Dresden. The lines are identified on boundary diagrams LR-QDC-35-2 and LR-ODC-77-2

at Quad Cities, and on LR-DRE-26-2 and LR-DRE-357-2 at Dresden. The line numbers are:

Quad Cities: 1-0201A-280-A, 1-0202A-28'-A, 1-0201B-28'-A, 1-0202B-28'-A, 2-0201A-28'-A,

2-0202A-28.-A, 2-0201 B-28'-A, 2-0202B-28'-A

Dresden: 2-0201A-28'-A, 2-0202A-28'-A, 2-0201B-28'-A, 2-0202B-28'-A, 3-0201A-28'-AM,

3-0202A-28'-AM, 3-0201 B-28'-AM, 3-0202B.28'-AM

The specific environment assigned to the stainless steel pipe supports is 'Inside

Containment.' The drywell is made inert with nitrogen to render the primary containment

atmosphere non-flammable by maintaining the oxygen content below 4% by volume during

normal operation. The drywell has an average temperature of 135 F during normal

operations. The relative humidity in the drywell ranges from 20% - 90%.

(2) All aging effects/mechanisms that were evaluated for the pipe support stanchions are

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A-:* ~~~Fr__ 

described below along with the technical basis used to determine whether aging management

was required.

Stainless Steel Pipe SuP6orA Stanchions

The aging effects degradation of stainless steel external surfaces in indoor/outdoor

atmospheric environments Is evaluated in EPRI 1003056, 'Non-Class 1 Mechanical

Implementation Guideline and Mechanical Tools" (EPRI Mechanical Tools) Appendix E, Table

4-1 and Figure 1.

Loss of material/crevice, pitting corrosion: This Is the only aging effect/mechanism identified

for stainless steel in EPRI 1003056.

(3) The stainless steel pipe supports on the A and "B' Recirculation Pump suction and

discharge lines Inside the drywell are ISI Class 1 component supports. The ASME Section Xl,

Subsection IWF ISI Aging Management program is credited with managing the aging effect of

loss of material due to corrosion for these stainless steel supports. This program provides for

the inspection of ASME Class 1, 2, and 3 supports and is also credited for managing the loss

of material due to corrosion for NUREG-1801 Section lll.B1 component supports.

Since the applicant's use of the IWF AMP to manage loss of material for the stainless steel pipe

support stanchions, used on the recirculation piping 28" lines at Dresden and Quad Cities, is

consistent with the GALL Report, the staff considers RAI 3.5-16 resolved.

In the LRA Table 3.2-2 (Reference Nos. 3.2.2.79, 3.2.2.80, and 3.2.2.81) states that Water

Chemistry (B.1.2) and One-Time Inspection (B.1.23) will be used to manage loss of

materialpitting and crevice corrosion in carbon and stainless steel support members

submerged in 25-288 OC (77-550 OF) demineralized water. The Water Chemistry Program will

also be used to manage cracking/stress-corrosion cracking in stainless steel support members

submerged in the same environment. In RAI 3.5-17, the staff requested the applicant to submit

the following information:

(a) Identify the specific supports covered by References 3.2.2.79, 3.2.2.80 and 3.2.2.81 and

the plant-specific operating experience.

(b) Explain why the ASME Section Xl, Subsection IWF Program is not credited for aging

management of these supports.

(c) Explain the number, type, and location of the supports that will be included in the

one-time inspection.

(d) Explain why the supports covered by Reference 3.2.2.80 are not included in the

one-time inspection.

In its response to RAI 3.5-17, the applicant stated the following:

Exelon has reviewed LRA Table 3.2-2, Aging Management References 3.2.2.79, 3.2.2.80, and

3.2.2.81, and following information Is provided.

(a) LRA Aging Management References 3.2.2.79, 3.2.2.80, and 3.2.2.81 discuss support

members submerged in a torus water environment. The submerged supports in the Low

Pressure Coolant Injection System (LPCI) at Dresden Station and the Residual Heat Removal

System (RHR) at Quad Cities Station are addressed by these aging management references.

All supports were evaluated for aging as a commodity group. No specific support numbers

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are cited by Aging Management References 3.2.2.79, 3.2.2.80, and 3.2.2.81. Generic

supports are grouped by system, material type, and environment combination. A review of

plant operating history did not reveal any loss of intended function for systems for which

Suppression PooVTorus Chemistry control exists.

The following are some plant specific operating experiences of Suppression Pool/Torus water

chemistry. These examples demonstrate the effectiveness of the Suppression Pool/Torus

water chemistry Aging Management Program (AMP).

* Dresden: Chemistry samples taken on the LPCI (shell) side of the 3A LPCI Heat

Exchanger on 1⁄2/100 and again on IW600 show that water conductivity, chloride

concentration, and sulfate concentration are considerably higher than normal torus water

chemistry conditions. The shell side chemistry concentrations are indicative of a service

water in-leakage.

* Dresden: Chemistry took the monthly Unit 2 torus water sample from the shell side of the

2B LPCI Heat Exchanger (8117/00) and found out-of-specification concentrations of

chlorides and sulfates as well as out-of-specification conductivity. On 8/19/00, the

existence of a leak in the 2B LPCI Heat Exchanger was confirmed.

* Quad Cities: Nuclear Oversight identified that the Station had been running with Unit 2

towus water at an elevated specific conductivity since October 1995. Readings had

fluctuated above and below the 'goal' value (less than or equal to 3 mS/cm) but less than

the limit (5 mS/cm).

* Quad Cities: Unit 2 torus. On 7/2196, a sample was found to be over the administrative

limit for conductivity of 5.0 mmho. The conductivity was 5.6 mmho as compared to 4.6

mmho from the last sample (6/26/96). The results of an investigation indicated there was

work in progress in the Unit 2 torus to replace an instwument air line hanger. The torus

hatch was removed on 6/29/96 in preparation for the work to commence and this may

have caused the water chemistry administrative limit to [be exceeded].

(b) 10 CFR 50.55a does not require inspecting ASME Section Xl, Subsection IWF supports that

are associated with ASME Section Xl, Subsection IWE. Supports in a submerged (towus

water) environment are associated with ASME Section Xl, Subsection IWE (components that

are part of the reactor coolant pressure boundary) and do not require inspection in

accordance with ASME Section Xl, Subsection IWF.

(c) A one-time inspection will be performed to verify the effectiveness of the torus water

chemistry. One time inspection of HPCI towus suction check valves is credited for the

one-time inspection of all submerged supports. The HPCI torus suction check valves and the

supports have a similar environment and material condition. The HPCI towus suction check

valves are carbon steel typically exposed to stagnant flow conditions but with occasional flow.

The one-time inspection utilizes the Preventive Maintenance (PM) program to inspect check

valves. The acceptance criteria for the HPCI check valves inspections are based on ASME

Section Xl, Examination Category B- 2 (Valve Body). Control of chemistry in accordance

with EPRI guidelines (TR-103515) does not preclude loss of material due to general, crevice,

or pitting corrosion at locations of stagnant flow conditions. This one-time inspection includes

measures to verify the effectiveness of the Suppression Pool/Tous Chemistry and confirm the

absence of loss of material in stagnant flow areas as required by NUREG 1801. Examinations

are to be conducted in an area where typically stagnant flow is present but occasionally there

is flow, which will cause replenishment of the oxygen supply. Therefore, the one-time

inspection of the Dresden and Quad Cities HPCI torus suction check valves is credited for

verifying the effectiveness of the Suppression Pool/Torus Chemistry and confirming the

absence of loss of material in stagnant flow areas.

(d) EPRI TR-1003056, 'Non-Class 1 Mechanical Implementation Guideline and Mechanical

Tools, Revision 3' states that cracking due to Stress Corrosion Cracking (SCC) is not likely in

a high purity environment below 2000F. The support members that are exposed to torus water

do not reach temperatures above 200'F and, therefore, cracking due to SCC is less likely to

occur in these support members. Control of torus water chemistry in accordance with EPRI

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guidelines (TR-1 03515) will provide high purity water and, therefore, provides assurance that

the potential for SCC is minimized. Because of this, a one-time inspection of components in

torus water environment for cracking due to SCC is not required to verify the effectiveness of

the Suppression Pool/Torus water chemistry for Aging Management Reference 3.2.2.80.

The staff has identified the need for additional information and has also identified a discrepancy

between the responses to RAI 3.5-15 and RAI 3.5-17. First, the applicant's response to RAI

3.5-15 stated the following:

The line item for Support Members in Table 2.4-15 incorrectly referenced 3.2.2.79, 3.22.80, and

3.2.2.81. These references should have been designated as aging management references for

Support References. Aging Management References 3.5.1.29,3.5.1.31, and 3.5.2.14 are correct.

New Aging Management References should have Included 3.5.2.17, 3.5.2.18, and 3.5.2.19, as

shown below in Table 3.5-2.

In the RAI 3.5-17 response, part (a), there is no indication of the correction described in the RAI

3.5-15 response. The applicant was requested to clarify this.

Second, part (b) of the response to RAI 3.5-17.is not acceptable. The supports in question are

not Class MC supports. The systems involved are most likely Class 2. In addition, the

reference to "(components that are part of the reactor coolant pressure boundary)" appears to

be misplaced. The applicant was requested to resubmit its justification for not crediting IWF.

Third, using only carbon steel HPCI torus suction check valves as the basis for the one-time

inspection does not address the potential aging effects for stainless steel support members.

The applicant was requested to describe how the one-time inspection will address aging effects

for stainless steel support members.

Fourth, as previously stated in the evaluation of the response t o RAI 3.5-15, the staff position' is

that some verification of the effectiveness of the Water Chemistry Program is necessary.

In a letter dated December 5, 2003, the applicant responded to the above questions. With

respect to the first question, the applicant corrected the previous references. With respect to

the second question, the applicant credited IWF for aging management References 3.5.1.31

and 3.5.2.14, which are applicable to structural members with a component intended function of

Ustructural support' and for References 3.5.1.31, 3.5.2.5 and 3.5.2.23, which are applicable to

clevis pins. With respect to the third question, the applicant believes that Torus Water

Chemistry controls will be (1) sufficient to prevent the aging effects of loss of material due to

general, crevice, and pitting corrosion in the carbon steel HPCI torus suction check valves and

(2) will also be sufficient to prevent aging effects in stainless steel support members and

components. Nevertheless, the applicant will provide a one-time inspection of selected

stainless steel clevis pins in the submerged environment to confirm the effectiveness of Torus

Water Chemistry controls in preventing the aging effect/mechanism of SCC. Where the

selected stainless steel clevis pins interface with uncoated carbon steel support members, the

interfacing support members will also be inspected for the aging effect/mechanism of loss of

materia/galvanic corrosion. This is part of Commitment #23 of Appendix A of this SER. With

respect to the fourth question, the applicant stated that it had responded in the preceding

question that it would provide a one-time inspection of selected stainless steel clevis pins in the

submerged environment to confirm the effectiveness'of Torus Water Chemistry controls: This is

also part of Commitment #23 of Appendix A of this SER. The staff finds the applicant 's

response acceptable and, therefore, considers RAI 3.5-17 resolved.

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The aging effects identified in the LRA for the components support commodity group are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible the aging effects were identified and that the aging effects listed

are appropriate for the combination of materials and environments specified.

Aging Management Programs

The applicant has credited the following AMPs with managing the aging effects described

above for the components support commodity group:

* Structures Monitoring Program

* ASME Section Xl, Subsection IWF Program

* Bolting Integrity Program

* Water Chemistry Program

* One-Time Inspection Program

The Structures Monitoring, Bolting Integrity, Water Chemistry, and One-Time Inspection

Programs are considered common AMPs. The staff's evaluation of the common AMPs is in

SER Section 3.0.3. The staff's evaluation of ASME Section Xl, Subsection IWF Program is in

SER Section 3.5.2.3.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the components

support commodity group will effectively manage or monitor the aging effects identified in the

LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.5.2.4.6 Insulation Commodity Group

Summary of Technical Information in the Application. The applicant's description of the

insulation commodity group (Dresden and Quad Cities) is in LRA Section 2.4.16. The

component groups requiring AMR are identified in LRA Table 2.4-16. For each component

group listed, LRA Table 2.4-16 specifies a reference to LRA Section 3 for the AMR results. The

applicant stated that all of the component groups are not addressed in the GALL Report and

provided the AMR results in LRA Tables 3.2-2, 3.3-2 and 3.4-2. These tables identify the

insulation commodity group components that are not addressed in the GALL Report and

provide information on material, environment, aging effect(s)/mechanism(s), and AMPs.

Utilizing the Dresden and Quad Cities Aging Management Review Aid, the staff identified the

applicable materials for insulation commodity group components as asbestos, fiberglass,

NUKON quilted fiberglass, stainless steel mirror insulation, closed-cell foam, calcium silicate,

stainless steel, aluminum, and aluminum jacketing. Utilizing the Review Aid, the staff also

identified the applicable environments as air, moisture, humidity less than 100 OC (212 OF), and

outdoor ambient conditions.

Aging Effects

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The LRA identifies the following applicable aging effects for the insulation commodity group

components:

* insulation degradation/loss of insulating characteristics

* insulation degradation/loss of jacket leak-tight integrity

LRA Table 2.4-16 references LRA Sections 3.2, 3.3, and 3.4 for the AMR results for all

components.

Aging Management Programs

The LRA credits the Structures Monitoring Program for managing the identified aging effects. A

description of this AMP is provided in LRA Appendix B. The applicant concludes that the

effects of aging will be adequately managed by this AMP such that there is reasonable

assurance that the intended functions will be maintained during the period of extended

operation.

Staff Evaluation. This section presents the staff's evaluation of the applicant's AMR for the

insulation commodity group and the applicability of the AMPs credited with managing the aging

effects. The staff's evaluations of the aging management evaluations for the insulation

commodity group that are not addressed in the GALL Report are discussed below.

Aging Effects

In the LRA Table 3.2-2 (Reference Nos. 3.2.2.44 and 3.2.2.45) and Table 3.4-2 (Reference No.

3.4.2.23) state that the Structures Monitoring Program is credited with managing two aging

effects/mechanisms-(1) insulation degradation/loss of insulating characteristics for asbestos

and fiberglass insulation, and (2) insulation degradation/loss of jacket leak-tight integrity for

aluminum insulation jacketing. In LRA Appendix B.1.30, Structures Monitoring Program, the

applicant states that tfhe program will be enhanced as follows:

Program procedures will reference specific insulation inspection criteria for existing cold weather

preparation and inspection procedures for outdoor insulation, and establish new inspections for

various indoor area piping and equipment insulation.

The staff finds the applicant's AMR for these components to be acceptable and agrees that the

Structures Monitoring Program is an acceptable program to manage the identified aging

effects.

In the LRA Table 3.2-2 (Reference Nos. 3.2.2.46, 3.2.2.47 and 3.2.2.48), Table 3.3-2

(Reference Nos. 3.3.2.122 and 3.3.2.123) and Table 3.4-2 (Reference No. 3.4.2.22) provide the

following technical justifications for concluding that there are no aging effects requiring

management for six specific insulation groups:

(1) The plant indoor environment is not conducive to promoting aging degradation of

NUKON quilted fiberglass insulation.

(2) Stainless steel mirror insulation materials are not subject to any viable aging mechanism

in the absence of aggressive chemical species.

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(3) Stainless steel insulation jacketing materials are not subject to any viable aging

mechanism in the absence of aggressive chemical species.

(4) Closed-cell foam insulation is susceptible to degradation when exposed to UV light. The

plant indoor environment is not conducive to promoting aging degradation of closed-cell

foam insulation.

(5) Aluminum is reactive but develops an oxide film that protects it from further corrosion.

No viable aging effects exist in the indoor environment for aluminum insulation jacketing.

(6) The plant outdoor environment is not conducive to promoting aging degradation of

jacketed calcium silicate insulation.

The staff finds these justifications to be reasonable and acceptable.

The aging effects identified in the LRA for the isolation commodity group are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible the aging effects were identified and that the aging effects listed are appropriate

for the combination of materials and environments specified.

Aging Management Programs

The applicant credited the Structures Monitoring Program with managing the aging effects

described above for the insulation commodity group components. The Structures Monitoring

Program is considered a common AMP. The staff's evaluation of the common AMPs is in SER

Section 3.0.3.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the insulation

commodity group will effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review, the staff finds the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the current licensing basis for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.6 Electrical and Instrumentation and Controls

This section addresses the aging management of electrical and instrumentation and controls

(I&C) components. The components have been divided into commodity groups as described in

the following LRA sections:

* Cables and Connections (2.5.1.1)

* Bus Duct (2.5.1.2)

* High Voltage transmission Conductors and insulators (2.5.1.3)

As discussed in Section 3.0.1 of this SER, the components of the electrical and instrumentation

and controls system group are included in two LRA Tables. LRA Table 3.6-1 consists of

electrical and l&C components that are evaluated in the GALL report. LRA Table 3.6-2 consists

of electrical and l&C components that are not evaluated in the GALL report.

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3.6.1 Summary of Technical Information in the Application

In LRA Section 3.6, the applicant described its AMRs for the ele6trical and l&C commodity

groups at Dresden and Quad Cities.

The results of the AMR for the electrical and l&C components or component groups are

presented in LRA Section 2.5. AMR was performed to assure that the component groups,

materials, environments and aging effects referenced in NUREG-1801 are applicable to

Dresden and Quad Cities and that the aging management program described in NUREG-1801

is applicable to Boiling Water Reactors (BWR) or to both Boiling Water Reactors and

Pressurized Water Reactors (BWR/PWR).

Not all electrical and l&C component types at Dresden and Quad Cities are listed in NUREG1801, Volume 2. However, the aging management reviews presented in NUREG-1 801, Volume

2 were applied to additional component types if the following criteria were satisfied:

* constructed of the similar material as components in the NUREG-1801 line item

* assigned the same component intended function as components in the NUREG-1 801

line item

* located in the same environment as components in the NUREG-1801 line item

* have exhibited the same aging effects identified in the NUREG-1 801 line item

Component types meeting these criteria have been included in the presentation of AMR results

in Table 3.6-1, "Aging management evaluated in NUREG-1 801 that are relied on for license

renewal for electrical and instrumentation and control components."

The third column of the table shows the component types included in each evaluation line.

"NUREG-1 801 Components" are those that correspond exactly with component types in

NUREG-1 801, Volume 2. "Evaluated with NUREG 1801 Components" shows the component

types that meet the criteria above and therefore share the same evaluation.

The applicant stated that Table 3.6-2, 'Aging management review results for the electrical and

instrumentation and control components that are not addressed in NUREG-1 801," presents the

AMR results for the remainder of the electrical and l&C components. These entries result from

AMR where the component type, material, environment or aging effect/mechanism differs from

NUREG-1801, Volume 2 line item entries. Table 3.6-2 includes a line reference number,

component group, material, environment, aging effect/mechanism, aging management program

and discussion.

3.6.2 Staff Evaluation

In Section 3.6 of the LRA, the applicant described its AMR for electrical and l&C component

groups at Dresden and Quad Cities. The staff reviewed LRA Section 3.6 to determine whether

the applicant has provided sufficient information to demonstrate that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

throughout the period of extended operation, in accordance with the requirements of 10 CFR

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54.21 (a)(3), for electrical and l&C system components that are determined to be within the

scope of license renewal and subject to an AMR.

The applicant referenced the GALL report in its AMR. The staff has previously evaluated the

adequacy of the aging management of electrical and l&C system components for license

renewal as documented in the GALL report. Thus, the staff did not repeat its review of the

matters described in the GALL report, except to ensure that the material presented in the LRA

was applicable, and to verify that the applicant had identified the appropriate programs as

described and evaluated in the GALL report. The staff evaluated those aging management

issues recommended for further evaluation in the GALL report. The staff also reviewed aging

management information submitted by the applicant that was different from that in the GALL

report or was not addressed in the GALL report. Finally, the staff reviewed the UFSAR

supplement to ensure that it provided an adequate description of the programs credited with

managing aging for the electrical and l&C system components.

Table 3.6-1 below provides a summary of the staff's evaluation of components, aging

effects/mechanisms, and AMPs listed in LRA Section 3.6 that are addressed in the GALL

report.

Table 3.6-1: Staff Evaluation Table for Dresden and Quad Cities Electrical Components

Evaluated in the GALL Report

Component Group Aging Effect/ AMP in GALL AMP in Staff Evaluation

Mechanism Report LRA

Electrical equipment subject to Degradation due to Environmental B.1.35 See SER Section 4.4

10 CFR 50.49 environmental various aging qualification of

qualification (EQ) requirements mechanisms electrical

components

Electrical cables and Embrittlement, cracking, Aging 8.1.33 Consistent with GALL

connections not subject to 10 melting, discoloration, management (See Section 3.6.2.3.1

CFR 50.49 EQ requirements swelling, or loss of program for below and audit report)

dielectric strength leading electrical

to reduced insulation cables and

resistance (IR); electrical connections

failure caused by not subject to

thermalthermoxidative 10 CFR 50.49

degradation of organics; EQ

radiolysis and photolysis requirements

(ultraviolet [UV] sensitive

materials only) of

organics; radiationinduced oxidation;

moisture intrusion

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i *~'J I_-:

Component Group Aging Effect/ AMP in GALL AMP in Staff Evaluation

Mechanism Report LRA

Electrical cables used In Enibriiement, cracking, Aging B.i.37 Consistent with GALL with

instrumentation circuits not melting, discoloration, management exception (See Section

subject to 10 CFR 50.49 EQ swelling, or loss of program for 3.6.2.32 below and audit

requirements that are sensitive dielectric strength leading electrical report)

to reduction in conductor to reduced IR; electrical . cables used in

insulation resistance (IR) failure caused by Instrumentation

thermal/thermoxidative circuits not

degradation of organics; subject to 10

radiation-induced CFR 50.49 EQ

oxidation; moisture requirements

intrusion

Inaccessible medium-voltage Formation of water trees, Aging B.1.38 Consistent with GALL

(2 kV to 15 kV) cables (e.g., localized damage leading management (See Section 3.6.2.3.3

installed in conduit or direct to electrical failure program for below)

buried) not subject to 10 CFR (breakdown of insulation); inaccessible

50.49 EQ requirements water trees caused by mediummoisture intrusion voltage cables

not subject to

10 CFR 50.49

EQ

requirements . .-

The staff's review of the electrical and l&C system groups for the Dresden and Quad Cities LRA

is contained within four sections of this SER. Section 3.6.2.1 is the staff review of components

in the electrical and l&C systems that are consistent with GALL, as stated in the LRA, and do

not require further evaluation. Section 3.6.2.2 is the staff review of components in the electrical

and l&C systems that are consistent with GALL, as stated in the LRA, and GALL recommends

further evaluation. Section 3.6.2.3 is the staff evaluation of aging management programs for

electrical and l&C components. Section 3.6.2.4 contains an evaluation of aging management

programs for plant specific components.

3.6.2.1 Aging Management Evaluations in the GALL Report that Are Relied on for License

Renewal, Which Do Not Require Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL does not recommend further evaluation, the staff sampled

components in these groups to determine whether the plant-specific components contained in

these GALL component groups were bounded by the GALL evaluation. The staff also sampled

component groups to determine whether the applicant had properly identified those component

groups in GALL that were not applicable to its plants. The staff also identified several areas

where additional information or clarification was needed.

On the basis of its review, the staff has verified the applicant's claim of consistency with the

GALL report. The staff finds that the applicant has demonstrated that the effects of aging will

be adequately managed so that the intended functions will be maintained consistent with the

CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.6.2.2 Aging Management Evaluation in the GALL Report That Are Relied on for License

Renewal, For Which GALL Recommends Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL recommends further evaluation, the staff reviewed the applicant's

evaluation to determine whether it adequately addressed the issues for which GALL

recommended further evaluation. In addition, the staff sampled components in these groups to

determine whether the plant-specific components contained in these GALL component groups

were bounded by the GALL evaluation.

The GALL Report indicates that further evaluation should be performed for the electrical

equipment subject to environmental qualification.

3.6.2.2.1 Environmental Equipment Subject to Environmental Qualification

Environmental qualification is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be

evaluated in accordance with 10 CFR 54.21 (c)(1). The staff reviewed the evaluation of this

TLAA separately in Section 4.4 of this SER, following the guidance in Section 4.4 of the SRPLR.

3.6.2.3 Aging Management Programs for Electrical and l&C Components

In SER Section 3.6.2.1, the staff determined that the applicant's AMRs and associated AMPs

will adequately manage component aging in electrical and l&C systems. The staff then

reviewed specific electrical and l&C system components to ensure that they were properly

evaluated in the applicant's AMR.

To perform its review, the staff reviewed the components listed in LRA Table 2.5-1 to determine

whether the applicant had properly identified the applicable AMRs and AMPs needed to

adequately manage the aging effects for the components. This portion of the staff review

involved identification of the aging effects for each component, ensuring that each aging effect

was evaluated using the appropriate AMR in Section 3, and that management of the aging

effect was captured in the appropriate AMP. The results of the staff's review are provided

below.

The staff also reviewed the UFSAR supplements for the AMPs credited with managing aging in

electrical and l&C system components to determine whether the program descriptions

adequately describe the programs.

The applicant credited the following AMPs to manage the aging effects associated with

electrical and l&C components:

* aging management program for electrical cables and connections not subject to 10 CFR

50.49 EQ requirements

* aging management program for electrical cables used in instrumentation circuits not subject

to 10 CFR 50.49 EQ requirements

* aging management program for inaccessible medium-voltage cables not subject to 10 CFR

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50.49 EQ requirements

The staff's evaluation of these AMPs is provided below.

3.6.2.3.1 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental

Qualification requirements

Summary of Technical Information in the Application. The AMP for electrical cables and

connections not subject to 10 CFR 50.49 environmental qualification requirements manages

cables and connections within the scope of license renewal that are subject to an adverse

environment. It also identifies and manages cables and connections subject to an adverse

localized environment. The aging management program for electrical cables and connections

not subject to 10 CFR 50.49 environmental qualification requirements is a new program.

An adverse localized environment is a condition in a limited plant area that is significantly more

severe than the specified service environment for a subject cable or connection. 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.

Cables and connections subject to an adverse environment are managed by inspection of a

sample of these components. Selected cables and connections from accessible areas, which

represent, with reasonable assurance, the cables and connections in adverse environments are

inspected. They are inspected for signs of accelerated age-related degradation. Additional

inspections, repair or replacement are initiated as appropriate.

Samples of cables and connections found to be located in adverse localized areas will be

inspected prior to the period of extended operation, with an inspection frequency of at least

once every 10 years. The scope of this program includes inspections of power, control and

instrumentation cables and connections located in adverse localized areas, including the cables

used in instrumentation circuits that are sensitive to reduction in conductor insulation

resistance.

NUREG-1801 Consistency

The aging management program for electrical cables and connections not subject to 10 CFR

50.49 environmental qualification requirements is a new program. The program is scheduled

for implementation prior to the period of extended operation. Program activities are consistent

with the ten elements of aging program XL.E1, 'Electrical Cables and Connections Not Subject

to 10 CFR 50.49 Environmental Qualification Requirements," specified in NUREG-1801.

Operating Experience

This program is new. Therefore, no programmatic operating experience is available. However,

existing activities provide for inspection of butyl rubber insulated, environmentally qualified

cables in heater bays to assess aging of cable insulation. These cables are in a localized

adverse environment. No adverse trends indicative of premature aging of cables have been

identified. Cable failures, when identified, are subject to the station corrective action program.

Operating experience does not indicate the presence of localized adverse environment or

premature aging of cable insulation.

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Conclusions.

The aging management program for electrical cables and connections not subject to 10 CFR

50.49 environmental qualification requirements provides reasonable assurance that aging

effects are adequately managed so that the intended functions of these types of cables and

connections are maintained during the period of extended operation.

Staff Evaluation. In Table 3.6-1, the applicant identifies embrittlement, cracking, melting,

discoloration, swelling, or loss of dielectric strength leading to reduced insulation resistance

(IR), electrical failure caused by thermal/thermoxidative degradation of organics, radiolysis and

photolysis (ultraviolet [UV] sensitive materials only) of organics, radiation-induced oxidation,

moisture intrusion are the aging effects of cables and connections due to heat or radiation. The

staff concurs with the aging effects identified by the applicant. These aging effects are

consistent with the aging effects identified by the staff in the GALL report.

The applicant stated that the scope of this program includes inspections of power, control and

instrumentation cables and connections located in adverse localized areas, including the cables

used in instrumentation circuits that are sensitive to reduction in conductor insulation

resistance. The staff finds that the aging management activity (LRA Table 3.6-1, Ref. No.

3.6.1.3) submitted by the applicant does not utilize the calibration approach for non-EQ

electrical cables used in circuits with sensitive, low level signals. Instead, these cables are

simply combined with all other non-EQ cables under the visual inspection activity. The staff

believes, however, that visual inspection alone would not necessarily detect reduced insulation

resistance (IR) levels in cable insulation before the intended function is lost. Exposure of

electrical cables to localized environments caused by heat, radiation, or moisture can result in

reduced IR. Reduced IR causes an increase in leakage of electrical 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 staff raised a question regarding the applicant's assumption that aging of these cables will

initially occur on the outer jacket resulting in sufficient damage that visual inspection will be

effective in detecting the degradation before IR losses lead to a loss of its intended function,

particularly if the cables are also subject to moisture. The staff requested the applicant to

provide a technical justification which will demonstrate that visual inspection will be effective in

detecting damage before current leakage can affect instrument loop accuracy, or propose an

alternate aging management activity (RAI 3.6-9). In its response dated October 3, 2003, the

applicant stated that it will develop a program that is consistent with the NRC staff's Interim

Staff Guidance (ISG) -15 issued on August 12, 2003, to address the staff's concern identified in

RAI 3.6-9. ISG-15 included a revision of GALL AMP XI.E2, 'Electrical cables not Subject to 10

CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits." The

applicant committed that it will develop a program that is consistent with NUREG 1801 AMP

XL.E2 to manage the aging of these cables. This program will be implemented prior to entering

the period of extended operation. This is Commitment #37 in Appendix A of this SER. The

staff finds that its concern is resolved since the applicant has committed to implement an AMP

for cables used in instrument circuits that are sensitive to reduction in conductor insulation

resistance consistent with ISG-1 5.

The applicant stated that the aging effects of fuse blocks will be managed by an AMP for

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' ,, . 4' .'

electrical cables and connections not subject to 10 CFR 50.49 EQ requirements. On March 4,

2003, the staff issued ISG-5 concerning identification and treatment of electrical fuse holders

for license renewal. The ISG-5 specified that the aging manag-menit review for fuse blocks

(metallic clamps) need to include the following aging stressors: fatigue, mechanical stress,

vibration, chemical contamination and corrosion. While the staff agrees that the proposed AMP

(B.1.33) will manage aging of insulation material for fuse holders, the AMP may not be effective

in addressing the above mentioned aging stressors associated with fuse blocks (metallic

clamps). The staff requested the applicant to provide a description of an aging management

program, in accordance with the requirements of 10 CFR 54.21 (a)(3), used to detect aging

effects associated with aging stressors as discussed in the ISG-5, or provide justification why

such a program'is not needed (RAI 3.6-1).

In its response dated October 3, 2003, the applicant stated that it will continue to include fuse

holders in an aging management program consistent with NUREG 1801 XL.E1. Additionally, it

will follow the guidance contained in ISG-5 dated March 4, 2003, and identify those fuse holders

that are not part of a larger assembly but support safety-related and non-safety-related

functions in which the failure of a fuse precludes a safety function from being accomplished.

Any fuses satisfying this criterion will be evaluated against the stressors listed in ISG-5 and an

aging management program will be developed if the aging evaluation determines that one is

necessary. The applicant stated that these fuses will be identified, the evaluation against the

stressors completed, and the actions identified in the aging management program completed, if

necessary, prior to entering the period of extended operation.

At the request of the staff, the applicant provided supplemental information on November 20,

2003. The applicant stated that a total of 708 fuse holders at Dresden and 724 fuse holders at

Quad Cities require evaluation against the stressors identified in ISG-5.' The 708 fuse holders

at Dresden are located in 17 different SCRAM Solenoid Fuse Panels which are located in the

reactor building (elevation 517 feet). The 724 fuse holders at Quad Cities are located in 25

different panels which are located in the reactor building (elevation 595 feet) and the turbine

building (elevation 639 feet). The aging evaluation results for each stressor are described

below.

Moisture

As stated in DOE Cable Aging Management Guideline (SAND 0944), Section 3.7.2.1.3, 3% of

all low-voltage metal connector failures were identified as being caused by moisture intrusion.

In each case, the source of moisture was precipitation. Based on the total number of reported

connector failures in the DOE Cable AMG, moisture'intrusion accounted for only 10 failures in'

all of the operating plants in the United States. The fuse holders at Dresden and Quad Cities

Stations that require an AMR are protected from external sources of moisture by two barriers.

For the first barrier, the panels in which the subject fuse holders are installed are located in

rooms inside the reactor and turbine buildings, which do not see high relative humidity

conditions. Based on plant walk downs, these panels are not located in areas which'experience

adverse localized temperature or humidity. These areas are protected from weather variations

and are not subject to any significant temperature variations. As a second barrier, the fuse

holders are located in closed enclosures. With regard to internal moisture (i.e., formation of

condensation), a walk down revealed no signs of moisture/humidity in the area or any signs of

moisture within the enclosures.

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Chemical Contamination

The fuse holders are protected, as described above, by their location and enclosure. There are

no sources of chemicals in the area or vicinity of the fuses, which was confirmed by the plant

walk down inspections.

Oxidation and Corrosion

Fuse clips are made of copper or copper alloy plated with a corrosion resistant coating material

to protect the base metal from oxidation and provide for low electrical resistance. The fuses

experience no appreciable change in operating environment and are not located near heavy

industrial or oceanic environments. Furthermore, the fuse holders evaluated are not near any

humid areas. Based upon recent inspections of the Bussmann fuse blocks performed in

September 2003, the surface condition of the fuse clips show no signs of corrosion and still

retain their metal surface. Additionally, there was no evidence or trace of moisture. For these

reasons, oxidation and corrosion are not applicable stressors.

Mechanical Stresses, Electrical Transients, Thermal Cycling, Fatigue

Mechanical stress due to forces associated with electrical faults and transients are mitigated by

the fast action of circuit protective devices at high currents. However, mechanical stress due to

electrical faults is not considered a credible aging mechanism since such faults are infrequent

and random in nature.

The Quad Cities fuse holders associated with alternate feeds to switchgear (used during fire

protection safe shutdown) are normally de-energized and do not experience frequent cycling.

As such, they do not experience enough heat to damage the fuse blocks and connections.

The Dresden and Quad Cities fuse holder SCRAM solenoids stay energized during normal

operation and also do not experience frequent cycling. The loading seen by these fuses are

well below 60%. A 60% loading is identified as a critical value in NUREG-1760 for fuses as

generating enough heat to damage the fuse blocks and connections. The SCRAM solenoids

draw about 15 watts and the fuses are rated for 3 amps. Therefore, these fuses are lightly

loaded. Inspection of a few samples did not reveal any age related degradation and the fuse

clips did not exhibit any signs of degradation.

Vibration is induced in fuse holders by the operation of external equipment, such as

compressors, fans, and pumps. Since there are no direct sources of vibration for the fuse

holder panels, and the panels are mounted separately on their own support structure on

concrete walls, vibration is not an applicable aging mechanism.

By design and their location, the fuse holders are not subject to aging effects associated with

thermal cycling. The SCRAM solenoid fuses are very lightly loaded and will experience very

insignificant temperature rise.

Wear/fatigue aging mechanism is caused due to repeated insertion and removal of fuses. The

fuses evaluated are not subject to frequent manipulations. When these circuits need to be

de-energized, power is removed at the safety-related power supplies. When manipulated, an

inspection is performed that would identify any abnormal indication such as loose or corroded

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fuse clips.

Fatigue may also be caused by frequent cycling of fuses when subject to significant loading,

which would cause the clips to expand and contract and to experience fatigue failure. However,

the subject fuses do not experience operational cycling during normal service due to the fact

that they are'lightly loaded, and therefore this is not a concern.

The applicant concluded that based on the aging evaluations of the stressors identified in

ISG-5, evaluations presented in NUREG-1760, and the operating service conditions of the

fuses in scope of this evaluation, no stressors are identified for these fuse blocks/clips that

would require aging management.

On the basis of its review, the staff finds that the applicant adequately addressed the stressors

identified in ISG-5 and agrees that no AMP is required.

GALL XL.E1 program requires visual inspection of cables and connections jacket anomalies,

such as embrittlement, discoloration, cracking, or surface contamination. The description of

B.1.33 and A.1.33 included inspection for signs of accelerated age related degradation. The

staff requested the applicant to describe what would qualify as signs of accelerated age related

degradation and explain how the requirements of GALL XL.E1 are met (RAI B.1.33-2). In its

response dated October 3, 2003, the applicant clarified that age related degradation includes

embrittlement, discoloration, cracking, and surface contamination. The applicant further stated

that the terms embrittlement, discoloration, cracking, and surface contamination are used in the

plant specific procedures that comprise the aging program described in B.1.33 to identify

accelerated age related degradation. The staff finds that its concern is resolved.

The applicant stated that cables and connections subject to adverse environment are managed

by inspection of sample of these components. The staff requested the applicant to provide the

technical basis for selecting sample location/size consistent with GALL Program XL.E1 attribute

number 3 on Paramet-ers Monitored/Inspected; (1) Indicate whether the sample will include

different type of cable insulations used in the plant; (2) Provide details about the samples of

connections and fuse holders (RAI B.1.33-3). In its response dated October 3, 2003, the

applicant stated that all accessible cables exposed to the localized adverse environments will

be inspected. This is part of Commitment #33 of Appendix A of this SER. No effort will be

made to segregate cables based on insulation material. All accessible fuse holders and

terminal blocks insulating material located within localized adverse environments will be

inspected. All accessible connections in the localized adverse environments will be inspected.

The staff finds that its concern is resolved.

The LRA indicated that selected cables and connections from accessible areas, which

represent, with reasonable assurance, the cables and connections in adverse environments are

inspected. However, GALL XL.E1 specifies that selected cables and connections from

accessible areas are inspected and [should] represent, with reasonable assurance, "all" cables

and connections in adverse environments. The staff requested the applicant to clarify this

difference (RAI B.1.33-4). In its response dated October 3, 2003, the applicant stated that for

the cable aging management referenced in LRA Section B.1.33, there is no difference between

NUREG-1801 requirements and the AMP commitments. Cable aging management referenced

in B.1.33 AMP applies to all accessible non-EQ in-scope cables and connections in adverse

environments. Based on its review, the staff finds that its concern is resolved.

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The staff also reviewed the UFSAR supplement to determine whether it provides an adequate

description of the program.

Conclusions. On the basis of its review and audit of the applicant's program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. Since the GALL program is acceptable to the

staff, the applicant has demonstrated that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also concludes that no AMP for fuse

holder is required. The staff also reviewed the UFSAR Supplement for this AMP and finds that

it provides an adequate summary description of the program, as required by 10 CFR 54.21 (d).

3.6.2.3.2 Electrical Cables used in Instrumentation Circuits not subject to 10 CFR 50.49 EQ

requirements that are sensitive to reduction in conductor Insulation Resistance

Summary of Technical Information in the Application. The applicant stated that sensitive

instrumentation circuit cable insulations were reviewed for their resilience against temperature,

radiation and moisture environments. All cable insulation materials were assessed to have 60-

year temperature and radiation thresholds greater than the bounding plant environments for

which cables and connections are installed. The specified aging effects are not expected and

therefore, no aging management is required. However, the cables of sensitive instrumentation

circuits not subject to 10 CFR 50.49 requirements will be managed for aging due to adverse

localized environments, as they are included in cables that are managed for aging per Item

3.6.1.2 of LRA Table 3.6-1 and aging management program for Electrical Cables and

Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (B.1.33).

Staff Evaluation. GALL Report contains an AMP specifically for cables with sensitive, low-level

signals. However, Dresden and Quad Cities apply the Non-EQ Insulated Cables and

Connections Aging Management Program to this area. The applicant claimed that the

inspection required by this program would be effective in identifying visual indications of

insulation deterioration caused by environmental conditions (e.g., embrittlement, cracking,

melting, discoloration, and swelling). This approach is considered by the applicant to be

consistent with GALL Report with one exception.

The aging management activity described in LRA Table 3.6-1, Ref. No. 3.6.1.3, does not utilize

the calibration approach for non-EQ electrical cables used in circuits with sensitive, low level

signals. Instead, these cables are simply combined with all other non-EQ cables under the

visual inspection activity. The staff believes, however, that visual inspection alone would not

necessarily detect reduced insulation resistance (IR) levels in cable insulation before the

intended function is lost. Exposure of electrical cables to localized environments caused by

heat, radiation, or moisture can result in reduced IR. Reduced IR causes an increase in

leakage currents between conductors and from individual conductors to ground. A reduction in

IR is a concern for circuits with sensitive, low-level signals such as radiation monitoring and

nuclear instrumentation since it may contribute to inaccuracies in the instrument loop.

The staff raised a question regarding the applicant's assumption that aging of these cables will

initially occur on the outer jacket resulting in sufficient damage that visual inspection will be

effective in detecting the degradation before IR losses lead to a loss of its intended function,

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I .7~ 0' 5

particularly if the cables are also subject to moisture. The staff requested the applicant to

provide a technical justification which will demonstrate that visual inspection will be effective in

detecting damage before current leakage can affect instrument loop accuracy, or propose an

alternate aging management activity (RAI 3.6-9). In its response dated October 3, 2003, the

applicant stated that it will develop a program that is consistent with the NRC staff's Interim

Staff Guidance (ISG) -15 issued on August 12, 2003, to address the staff's concern identified in

RAI 3.6-9. ISG-15 included a revision of GALL AMP XL.E2, UElectrical cables not Subject to 10

CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits." The

applicant committed that it will develop a program that is consistent with NUREG 1801 AMP

XL.E2 to manage the aging of these cables. This program will be implemented prior to entering

the period of extended operation. This is Commitment #37 in Appendix A of this SER. The

staff finds that its concern is resolved since the applicant has committed to implement an AMP

for cables used in instrument circuits that are sensitive to reduction in conductor insulation

resistance consistent with ISG-1 5.

Aging Effects

In Table 3.6-1, the applicant identified embrittlement, cracking, melting, discoloration, swelling,

or loss of dielectric strength leading to reduced insulation resistance (IR), electrical failure

caused by thermalthermoxidative degradation of organics, radiation-induced oxidation,

moisture intrusion as aging effects of cables and connections due to heat or radiation. The

staff concurs with the aging effects identified by the applicant. These aging effects are

consistent with the aging effects identified by the staff in the GALL report.

Aging Management Program

The applicant committed to develop a program that will be consistent with NUREG 1801 AMP

XL.E2 to manage the aging of electrical cables used in instrumentation circuits not subject to 10

CFR 50.49 EQ requirements that are sensitive to reduction in conductor insulation resistance.

This is Commitment #37 in Appendix A of this SER. The cables included within the scope of

this program are the cables used in the following Nuclear Instrumentation Systems (NIS) and

radiation monitoring systems: Source Range Monitors (SRM), Intermediate Range Monitors

(IRM), Local Power Range Monitors (LPRM), Drywell High Range Radiation Monitors, Main

Steam Line (MSL) Radiation Monitors, and Steam Jet Ejector (SJAE) Radiation Monitors.

By a letter dated December 22, 2003, the applicant provided the details of the program (ten

attributes). The evaluation of the applicant's AMP focused on program attributes. To

determine whether the applicant's AMP is adequate to manage the effect of aging so that the

intended function will be consistent with CLB for the period of extended operation, the staff

evaluated the following seven attributes: (1) scope of program, (2) preventive action, (3)

parameter monitored or inspected, (4) detection of aging effects, (5) monitoring and trending,

(6) acceptance criteria, and (7) operating experience. The staff's evaluation of the applicant's

corrective action, confirmation process, and administrative controls is provided separately in

Section 3.0.4 of the staff's safety evaluation.

[Scope of Program] This program applies to the cables used in sensitive instrumentation

circuits with low level signals of the NIS which includes SRM, IRM, LPRM and Radiation

Monitoring Systems which includes Drywell High Range Radiation Monitors, Main Steam Line

Radiation Monitors, and Steam Jet Air Ejector Radiation Monitors. For the LPRM, SRM, and

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IRM systems, the cables within the scope of this AMP are the cables between the detectors and

main control room panel. For the radiation detectors within the scope of this program, the

cables within the scope of this AMP are the cables between the detectors and the associated

meters. The staff considers the scope of the program to be acceptable.

[Preventive Actions] This is a surveillance program and no actions are taken as part of this

program to prevent or mitigate aging degradation. This is acceptable since the staff finds no

need for such actions.

[Parameters Monitored/lnspected] Nuclear Instrumentation Systems:

(1) LPRM- Calibration surveillance testing being credited for the LPRM system. The full core

LPRM calibration is performed per technical specification surveillance requirements. Per the

implementing procedure, the LPRM's are verified to be within calibration. The acceptability of

the LPRM cable/detectors/connectors is verified through this calibration. This calibration

adjusts for loss in sensitivity of the circuit. The staff finds that this action to be acceptable because the review of calibrations and surveillances will provide reasonable assurance that age related degradation of the cables will be detected prior to loss of cable intended function.

(2) SRM- For the SRM system, the cables between the preamplifier and detectors are subject to Current/Voltage (IN) testing. The IN test data is used to calculate the cable insulation

resistance. The IN testing results will be indicative of reduced insulation resistance. These

tests verify the insulation resistance of the cables inside the drywell, along with the operability of

the detectors and connectors. A surveillance test of the SRM monitors is performed to verify the functionality of the SRM (indicate counts per cycle within a certain range or have proper signal to noise ratio) during core alterations (refueling). This surveillance test verifies the

integrity of the SRM cable system. Cable and surveillance testing as recommended by ISG-1 5

is being credited for the SRM system.

(3) IRM - For the IRM system, the cables inside the drywell are subject to Current/Voltage (IN) testing. The IN test data is used to calculate the cable insulation resistance. The IN testing results will be indicative of reduced insulation resistance. These tests verify the insulation

resistance of the cables inside the drywell, along with the operability of the detectors and

connectors. A surveillance response test will be performed for the IRM monitors from the

preamplifier to the control room chassis by injecting simulated inputs into the preamplifier. This

surveillance test will verify the integrity of the IRM cables between the preamplifier and control

room chassis. Cable and surveillance testing as recommended by ISG-15 is being credited for

the IRM system.

The staff finds that above testing is acceptable because those testing will determine cable

insulation resistance (potential degradation).

Radiation Monitoring System

Drywell High Range Radiation Monitoring: In accordance with NUREG 1801, calibration

surveillance testing is being credited for the Drywell High Range Radiation Monitors. The

calibration required by technical specification surveillances will verify that the cables maintain

adequate insulation resistance integrity to perform their intended function. In this calibration, a

calibrated source is used to expose the detector to gamma radiation field, and verify that

acceptable readings are measured on the corresponding meter. As recommended by ISG-15,

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the applicant is committing to a once every 10 year review of the calibration results for cable

aging degradation. The first review will be performed prior to entering the period of extended

operation. This is Commitment #37 in Appendix A of this SER.

Main Steam Line Radiation Monitoring: In accordance with NUREG 1801, calibration

surveillance testing is being credited for the entire MSLRM system. The calibration utilizes a

source capable of producing photon energy in the range expected during normal and abnormal

conditions. This check is performed with the entire'system, including detectors, cables, and

control room chassis, intact. This demonstrates that no detector or connecting cable

degradation has occurred that could inhibit the system from performing its intended function.

As recommended by ISG-1 5, the applicant is committing to a once every 10 year review of the

calibration results for cable aging degradation. The first review will be performed prior to

entering the period of extended operation.

Steam Jet Air Ejector Radiation Monitoring: In accordance with NUREG 1801, calibration

surveillance testing is credited for the entire SJAERM system. The calibration utilizes a source

capable of producing photon energy in the range expected during normal and abnormal

conditions. This check is performed with the entire system, including detectors, cables, and

control room chassis, intact. This demonstrates that no detector or connecting cable

degradation has occurred that could inhibit the system from performing its intended function.

As recommended by ISG-1 5, the applicant is committing to a once every 10 year review of the

calibration results for cable aging degradation. The first review will be performed prior to

entering the period of extended operation.

The staff finds that this action to be acceptable because the review of calibrations and

surveillances will provide reasonable assurance that age related degradation of the cables will

be detected prior to loss of cable intended function.

[Detection of Aging Effects:] The LPRM, Drywell High Range Radiation Monitors, Main Steam

Line Radiation Monitors, and the Steam Jet Air Ejector Radiation Monitors are calibrated per the

frequency specified in the technical specification. The normal calibration frequency specified in

the technical specification provides reasonable assurance that severe aging degradation will be

detected prior to loss of the cable intended function. A review of calibration results will be

completed before the period of extended operation and every 10 years thereafter. This review

may detect severe aging degradation prior to the loss of cable intended function. The staff

finds that 10 year testing frequency is consistent with ISG-1 5.

The SRM and IRM cable systems inside the drywell are tested for insulation resistances. This

test is a direct indication of condition of the insulation and will detect severe aging degradation

prior to the loss of cable intended function. These cable systems are being tested every 24

months. The staff finds that 24 months testing frequency is acceptable.

The SRM surveillance test is performed every 24 months and will provides reasonable

assurance that severe aging degradation will be detected prior to loss of the cable intended

function. A review of the surveillance results will be completed before the end of the current

term and every 10 years thereafter. This review may detect severe aging degradation prior to

the loss of cable intended function.

The IRM surveillance test will be performed before the period of extended operation and every

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24 months thereafter. The surveillance test will provides reasonable assurance that severe

aging degradation will be detected prior to loss of the cable intended function. A review of the

surveillance results will be completed before the period of extended operation and every 10

years thereafter. This review may detect severe aging degradation prior to the loss of cable

intended function.

The staff finds that 10 year frequency of the review of surveillance test for SRM and IRM is

acceptable because it is consistent with ISG -15.

[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 of NUREG 1801, calibration results will be trended once every 10 year, as

recommended by ISG-15. The staff finds this to be acceptable.

[Acceptance Criteria] The LPRM, Drywell High Range Radiation Monitors, Main Steam Line

Radiation Monitors, and the Steam Jet Air Ejector Radiation Monitors calibration results are to

be within the acceptance criteria, as set out in the technical specifications surveillance

calibration procedures. The staff finds this to be acceptable because surveillance or calibration

activity ensures that cable intended function used in instrumentation circuits are maintained

under all CLB design conditions during the period of extended operation.

The SRM and IRM cable systems test results and surveillance results are to be within the

acceptance criteria, as set out in the testing and surveillance procedures. The staff finds this to

be acceptable because testing and surveillance activity ensures that cable intended function

used in instrumentation circuits are maintained under all CLB design conditions during the

period of extended operation.

[Operating Experience] This is a new aging management program and therefore there is no

programmatic operating experience. However, plant experience shows that when an

equipment cannot be brought into calibration or when cable system tests indicate unacceptable

results, further reviews will identify if the problem is attributable to the instrument, connector or

cabling. The staff finds that the applicant has adequately addressed operating experience.

The staff also reviewed the UFSAR supplement to determine whether it provides an adequate

description of the program.

Conclusions. On the basis of its review and audit of the applicant's program, the staff finds that

those portions of the program for which the applicant claims consistency with the GALL

program are consistent with the GALL program. In addition, the staff has reviewed the

exceptions to the GALL program and finds that the applicant has demonstrated that the effects

of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB during the period of extended operation as required by 10 CFR

54.21 (a)(3). The staff also reviewed the UFSAR supplement for this AMP and finds that it

provides an adequate summary description of the program as required by 10 CFR 54.21 (d).

3.6.2.3.3 Inaccessible Medium Voltage Cable Not Subject to 10 CFR 50.49 EQ Requirements

Summary of Technical Information in the Application. The applicant stated that five mediumvoltage power cables at Dresden are exposed to significant moisture and significant voltage

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(subject to system voltage more than 25 perecnt of the time). Prior to the extended period of

operation, these five medium-voltage power cables will be replaced with cables that are

resistant to insulation degradation due to water treeing, and therefore, no aging management is

required. The applicant stated that only Dresden has medium-voltage cables in the scope of

license renewal that are routed in underground ducts.

Staff Evaluation. The applicant stated that no AMP is required for inaccessible medium-voltage

(2kV to 15kV) cables (e.g., installed in conduit or direct buried) not subject to 10 CFR 50.49 EQ

requirements.

The applicant determined that insulation degradation due to water treeing is not applicable to

Quad Cities and, therefore, no AMP is required.

In Section 3.6.1.2.2, LRA indicates that five medium-voltage power cables at Dresden are

exposed to significant moisture and significant voltage. The staff requested the applicant to

identify these cables. The staff wanted to clarify whether the cable connecting the Station

Blackout (SBO) diesel generator is included in this group. The staff requested the applicant to

provide a discussion regarding the use of the SBO diesel generator including possible use of

the SBO diesel generator to generate power during peak demands. Also, the staff requested

the applicant to provide information regarding the replacement cables. (The staff has accepted

submarine cables and lead sheathed cables for components not requiring a GALL XI.E3

program.) In addition, the staff requested the applicant to explain why this issue doesn't apply

to Quad Cities. Additionally, the staff requested the applicant to provide a description of an

aging management program (with ten attributes) to remove water from the cable manholes or

provide a justification why such a program is not needed (RAI 3.6-3). In its response dated

October 3, 2003, the applicant stated that the medium voltage cables that are exposed to

significant moisture and significant voltage at Dresden Station are scheduled to be replaced

prior to the extended period of operation (By letter dated November 20,2003, this commitment

was withdrawn in favor of a new program, B.1.38, see below). These are the power feed

cables to the five (5) Dresden Station Service Water Pump motors. The motors are non-safetyrelated, but perform a function that demonstrates compliance with the NRC's regulation for Fire

Protection (10 CFR 50.48). The service water pumps run continuously and are located in the

crib house.

The Quad Cities Service water pumps are not credited in the station's fire protection program or

required for other license renewal intended functions; therefore, their power feeds do not

perform any license renewal intended functions.

The medium voltage cables connecting the SBO Diesel Generator (SBO DG) are not part of

this group. The SBO DG bus feeder cables to the ESF buses are routed underground at

Dresden and are routed overhead at Quad Cities. The SBO DG output cables are exempt from

the NUREG 1801 Xl. E3 program based on their duty cycles (not energized normally or less

than 25% of the time). The power feeds from the SBO DG bus to the ESF buses are energized

only during an SBO event or surveillances.

The SBO system is a non-safety-related, independent source of additional on-site emergency

ac power. The SBO DG is designed to be started remotely or locally in the emergency mode

under conditions of total or partial loss of offsite power. The SBO DGs are not used to

generate power during peak demands.

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Section 3.6.1.2.2 of LRA states that prior to the extended period of operation the five

medium-voltage power cables will be replaced with cables that are resistant to insulation

degradation due to water treeing and therefore do not require aging management per NUREG

1801 Xl. E3 program. The plant modification process will be used to identify suitable

replacement cables that are resistant to insulation degradation due to water treeing.

A program to remove water from the cable manholes is not required. At Dresden, the only

medium voltage cables that perform an intended function in support of 10 CFR 54.4 and are

energized more than 25 percent of the time will be replaced with cables that are resistant to

insulation degradation due to water treeing. At Quad Cities there are no medium voltage cables

installed in underground duct banks that perform intended functions that demonstrate

compliance with 10 CFR 54.4.

The staff finds that the applicant did not identify the type of the replacement cables at Dresden.

On November 20, 2003, the applicant stated that it has reevaluated its position with regards to

the replacement of the five medium-voltage cables at Dresden. A review of the industry

experience contained within EPRI TR 103834-P1-2, Effects of Moisture on the Life of Power

Plant Cables and SAND96-0344, Aging Management Guideline for Commercial Nuclear Power

Plants has determined that butyl rubber insulated medium-voltage cable has not experienced

failure due to water treeing. Based on the lack of adverse industry experience and 30 plus

years of continuous operating experience, the applicant believes that these cables will perform

their intended functions for the period of extended operation. As such, the applicant does not

intend on replacing the cables as stated in Section 3.6.1.2.2 of the Dresden and Quad Cities

License Renewal Application. Rather, the applicant will manage these cables in accordance

with NUREG-1801 XL.E3 aging management program. The applicant provided a new LRA

section B.1.38 and A.1.38 that describes this new aging management program for Inaccessible

Medium-Voltage Cables not Subject to 10 CFR 50.49 Environmental Qualification

Requirements. This is part of Commitment #38 of Appendix A in this SER.

The applicant has reviewed all of the in-scope inaccessible medium-voltage cables that are

installed in underground duct runs and as stated in the response to RAI 3.6.3 there are only five

inaccessible in-scope medium voltage cables at Dresden that are exposed to significant

moisture and that are energized more than twenty-five percent of the time. The diesel

generator cooling water supply pump motors are 480 V ac, not 4160 V ac. For this reason, they

are not considered medium-voltage cables. Additionally, the electrical loads referenced in Table

8.3-2 of the Quad Cities UFSAR represent the major diesel generator loading for both

automatic and manual operation on loss of offsite power (LOOP). The loads listed in Table

8.3-2 are not required to achieve safe shutdown of a reactor in the event of a LOOP. LRA

Section 2.3.3.16, Service Water system shows that for Quad Cities, the Service Water system

is only in-scope, as specified in 10 CFR 54.4(a)(2), to preclude adverse effects on safetyrelated SSC's and for structural support. The Quad Cities Service Water system does not

perform any intended function within the scope of License Renewal as specified in 10 CFR

54.4(a) (1) or (3). Therefore, the medium-voltage cable feeds to the Quad Cities service water

pumps are not within the scope of License Renewal. On the basis of its review, the staff finds

its concern for Quad Cities is resolved.

Aging Effects

The applicant identified the formation of water trees, localized damage leading to electrical

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failure (breakdown of insulation); and water trees caused by moisture intrusion as the aging

effects for inaccessible medium-voltage cables not subject to 10 CFR 50.49 requirements. The

staff concurs with the aging effecis identified by the applicant. These aging effects are

consistent with the aging effects identified by the staff in the GALL report.

Aging Management Program

Dresden will implement an AMP for inaccessible medium-voltage cables not subject to 10 CFR

50.49 EQ requirements. The scope of the program is limited to five butyl rubber insulated

inaccessible medium-voltage cables routed in underground duct banks that are at times

exposed to significant moisture and are energized more than25 percent of the time.

On November 20, 2003, the applicant provided the details of the program (10 attributes). The

evaluation of the applicant's AMP focused on program attributes. To determine whether the

applicant's AMP is adequate to manage the effect of aging so that the intended function will be

consistent with CLB for the period of extended operation, the staff evaluated the following

seven attributes: (1) scope of program, (2) preventive action, (3) parameter monitored or

inspected, (4) detection of aging effects, (5) monitoring and trending, (6) acceptance criteria,

and (7) operating experience. The staff's evaluation of the applicant's corrective action,

confirmation process, and administrative controls is provided separately in Section 3.0.4 of the

staff's safety evaluation.

[Scope of Program] This program applies to five inaccessible medium-voltage cables that feed

the Dresden service water pumps. These cables are routed in underground duct banks that are

at times exposed to significant moisture and are energized more than 25 percent of the time.

At Dresden, adverse conditions are expected to be prevalent inside the duct bank that runs to

the crib house. This duct bank is a continuous run without manholes. The ducts are sloped

toward the crib house and during wet seasons, water collected in the ducts drains into the crib

house. The staff considers the scope of the program acceptable.

[Preventive Actions] At Dresden, the duct bank is a continuous run without manholes. The

ducts are sloped toward the crib house and during wet seasons water collected in the ducts

drains into the crib house. The ducts will be inspected annually to verify that the crib house end

of the ducts are not plugged with debris and that water can drain from the ducts. This is

acceptable since the staff finds that these cables will be tested once every 10 years.

[Parameters Monitored or Inspected] Testing will be performed to provide an indication of the

condition of the conductor insulation. The specific type of test 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 TR1 03834-Pl -2, or other testing that is state -of-the-art at the time the test is performed. The staff

finds this acceptable because it provides means for monitoring the applicable aging effects on

the cable insulation.

[Detection of Aging Effects] The five Dresden inaccessible medium-voltage cables exposed to

significant moisture and significant voltage will be tested at least once every 10 years. The first

tests for license renewal will be completed prior to the period of extended operation. The staff

finds a 10-year testing frequency is an adequate period to preclude failure of these cables since

aging degradation is a slow process and the ducts will be inspected annually to verify that the

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crib house end of the ducts are not plugged with debris and that water can drain from the ducts.

[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. Test results that

are trendable may be trended to provide additional information on the rate of degradation. The

staff finds this to be acceptable.

[Acceptance Criteria] The acceptance criteria for each test will be defined by the specific type

of test performed on the five butyl rubber insulated inaccessible medium-voltage cables. The

staff finds this to be acceptable because the acceptance criteria is dependable on the test

selected.

[Operating Experience] This is a new program and no plant experience exists to verify the

effectiveness of this program. However, the five cables are butyl rubber insulated 4 kV cables

which are less susceptible to water treeing than the cross-linked polyethylene or HMWPE

insulation materials. A review of plant and industry experience determined that there has been

no failure due to water treeing of butyl rubber cable installed in underground ducts. The staff

finds that the applicant has adequately addressed operating experience.

The staff also reviewed the UFSAR supplement to determine whether it provides an adequate

description of the program. On the basis of its review, the staff finds that the AMPs credited in

the LRA for the inaccessible medium-voltage circuits will effectively manage or monitor the

aging effects identified in the LRA.

Conclusion. The staff concludes that the applicant has adequately identified the aging effects

and the AMP will be credited for managing the aging effects of cables used in inaccessible

medium-voltage circuits at Dresden and that these cables will perform their intended function in

accordance with the CLB during the period of extended operation as required by 10 CFR

54.21 (a)(3). The staff also concludes that no AMP is required for Quad Cities. The staff also

reviewed the UFSAR supplement for this aging management program and finds that it provides

an adequate summary description of the program as required by 10 CFR 54.21 (d).

3.6.2.4 Aging Management of Plant-Specific Components

The applicant credited one AMP to manage the aging effects associated with electrical and l&C

components. The following sections provide the results of the staff's evaluation of the

adequacy of aging management for plant specific electrical and instrumentation and control

components.

3.6.2.4.1 Bus Duct

Summary of Technical Information in the Application. The applicant stated that bus ducts utilize

a pre-assembled raceway (enclosure) design with conductors supported by electrical insulators.

The bus ducts within the scope of license renewal are the bus ducts used for safety-related

systems and those associated with 4160 V power feeds between the reserve auxiliary

transformer (RAT) and switchgear. The function of the bus ducts is to electrically connect

power supplies and load centers to deliver voltage and current. The function of the bus duct

insulators is to support and insulate the bus bar conductors. Bus ducts were not evaluated in

the GALL Report. The applicant identified embrittlement, cracking, melting, discoloration,

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swelling, or loss of dielectric strength leading to reduced insulation resistance (IR); electrical

failure as the aging effects for the insulators in the bus ducts. The applicant further stated that

those aging effects will be managed by a aging management program B.2.2, "Periodic

Inspection of Non-Segregated Electrical Bus Ducts."

This program inspects the non-segregated bus ducts that connect the reserve auxiliary

transformers to the 41 60V ESF buses. They are normally energized, and therefore, the bus

duct insulation material will experience temperature rise due to energization, which may cause

age-related degradation during the extended period of operation. These bus ducts are in scope

of license renewal but are not subject to 10 CFR 50.49 environmental qualification. These

non-EQ, non-segregated bus ducts will therefore be inspected periodically during the period of

extended operation. This inspection program considers the technical information and guidance

provided in IEEE Standard P1205, "IEEE Guide for Assessing, Monitoring and Mitigating Aging

Effects on Class 1 E Equipment Used in Nuclear Power Generating Stations," SAND 96-0344,

"Aging Management Guidelines for Commercial Nuclear Power Plants - Electrical Cable and

Terminations," and EPRI-109619, Guideline for the Management of Adverse Localized

Equipment Environments."

The non-segregated bus duct internal components and materials are visually inspected under

station inspection procedures for signs of aging degradation that indicate possible loss of

insulating function. Repair or rework is initiated as required to maintain the operating functions

of the bus ducts.

The inspection program for the non-EQ, non-segregated electrical bus ducts that connect the

reserve auxiliary transformers to the 41 60V ESF buses will provide reasonable assurance that

the intended function of the non-EQ, non-segregated bus ducts will be maintained consistent

with the CLB for the period of extended operation.

This is a new program and will be implemented prior to the period of extended operation. The

applicant provided tenrelements of the program in Appendix B, Section B.2.2.

Staff Evaluation. In the LRA Section 2.5.2, the applicant determined whether bus ducts meet'

the screening criteria of 10 CFR 54.21 (a)(1 )(i) and evaluated these components against 10

CFR 54.21 (a)(1 )(ii).

The applicant stated that the bus ducts utilize pre-assembled raceway (enclosure) design with

internal conductors installed on electrically insulated supports. Bus ducts are constructed of

various metals, polyester glass, PVC, and silicon caulk. Bus ducts at Dresden and Quad Cities

includes the bus ducts used for safety-related systems and those associated with the 4160 V

power feeds between the reserve auxiliary transformers and switchgear. Bus ducts electrically

connect specified sections of an electrical circuit to deliver voltage or current to various

equipment and components throughout the plant.

Aging Effects

The applicant identified embrittlement, cracking, melting, discoloration, swelling or loss of

dielectric strength leading to reduced insulation resistance, electrical failure as the aging

effects/mechanism for the bus ducts.

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The aging effects identified in the LRA for the bus ducts are consistent with industry operating

experience for the materials and environments listed. The staff finds that all the plausible aging

effects were identified and that the aging effects listed are appropriate for the combination of

materials and environments specified.

Aging Management Programs

Dresden and Quad Cities have elected to implement an AMP to identify and manage potential

aging degradation. This is a non-GALL program and will provide reasonable assurance that the

bus ducts will continue to perform their intended function consistent with the CLB through the

period of extended operation. LRA Table 3.6-2 indicates that polyester glass insulator

associated with electrical bus ducts will be periodically inspected per AMP B.2.2. It is not clear

whether all the components (i.e., bus bar, enclosure, insulators, etc.) are covered under this

AMP. Industry operating experience, as documented in Information Notices (IN 2000-14, IN

1998-36, and IN 1989-64) and Licensee Event Reports (LERs: 26698002, 41095010, and

27596017), indicate several problems (i.e., loosening of splice plate bolts, degradation of Noryl

insulation, insulation failure along with the presence of moisture or debris provided undesired

phase to phase or phase to ground electrical tracking paths which resulted in catastrophic

failure of the bus) associated with bus ducts. Additionally, most connections to non-segregated

bus ducts are made by bolted connections.

The non-segregated bus ducts may be exposed to appreciable ohmic or ambient heating during,

operation and may experience loosening related to the repeated cycling of connected loads or

of the ambient temperature environment (Refer to SAND 96-0344, page 4-38). The staff

understands that the proposed AMP B.2.2 program will manage the aging degradation of

insulation material. The staff requested the applicant to provide a discussion on how the other

problems identified by the above INs and LERs and SAND 96-0344 will be managed by the

AMP B.2.2 ( RAI 3.6-4). In response to the Staff's RAI 3.6-4, the applicant on October 3, 2003,

stated that the procedures that implement AMP B.2.2 visually inspect non-segregated bus duct

internal components and materials. These include: insulation material, bus duct support pieces,

gaskets, insulating boots, taped connections, and bus bar sleeves. This is part of Commitment

#40 of Appendix A of this SER. Failure of connection tapes and bus bar sleeves would not

prevent the bus duct from performing it's intended function. However, these components are

included with the scope of AMP B.2.2. The visual inspections check for evidence of water and

dirt accumulation, presence of foreign material, and cracking / chipping of insulation. The

description of AMP B.2.2 should have included this detail in the AMP description and in the

evaluation Parameters Monitored/inspected, and Detection of Aging Effects.

LRA Section B.2.2, Evaluation and Technical Basis Element (3) - "Parameters Monitored/

Inspected," should have read as follows: "Accessible normally energized non-segregated bus

duct internal components are visually inspected for insulator and bus bar insulation material

surface anomalies, such as embrittlement, discoloration, cracking, chipping, or surface

contamination. Internal components such as insulation material, bus duct support pieces,

gaskets, insulating boots, taped connections, and bus bar sleeves are inspected. The visual

inspections also check for evidence of water and dirt accumulation and presence of foreign

material."

The applicant stated that the failures identified in the referenced Information Notices and LERs

caused by introduction of contaminants and moisture into the bus duct housing are addressed

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in AMP B.2.2. However, several of the IN's and LERs address inadequate design or

inadequate maintenance as causal factors. These are not valid aging effects and are not

addressed by AMP B.2.2.

The information notices or LERs identified do not suggest any age related failures. On the

contrary, the failures noticed for installed lives are much shorter than a 40-year plant life.

As noted in LER 26698002, failure was caused by the presence of condensation. AMP B.2.2

inspects for evidence of water and dirt accumulation.

LER 41095010 event suggests the reason to be the use of wrong penetration sleeve material.

This failure mode is not a valid aging effect and is not addressed by AMP B.2.2.

LER 27596017 identifies PVC off gassing as the casual factor. AMP B.2.2 visually inspects

insulation for degradation.

IN 89-64 suggests that failure was caused by water and debris. AMP B.2.2 inspects for

evidence of water and dirt accumulation.

IN 98-36 identifies failure due to poor maintenance. This failure mode is not a valid aging effect

and is not addressed by AMP B.2.2.

IN 2000-14 identifies failures of two bus ducts, which started when a PVC insulator over a

splice joint overheated in turn causing heat induced failure on fiberglass insulation. AMP B.2.2

visually inspects insulation for degradation.

The non-segregated bus ducts at Dresden and Quad Cities subject to AMP B.2.2 do not

experience bolt loosening caused by the repeated cycling of connected loads from appreciable

ohmic or ambient heating during operation. The non-segregated phase bus ducts subject to

AMP B.2.2 are the bus ducts that connect the Reserve Auxiliary Transformer to the 4 KV

busses. They are normally energized and do not experience appreciable cyclical temperature

swings as discussed in SAND 96-0344. Therefore, the issue of heating and cooling that would

cause the bolting connections to loosen does not apply. Additionally, operating experience at

both sites has indicated no such failures.

In summary, AMP B.2.2 provides reasonable assurance that the applicable aging effects are

adequately managed. On the basis of its review, the staff finds that the visual inspection of bus

ducts, bus bars, and internal supports will provide an indication of aging effects.

The staff noted however that the proposed program will not verify the bolted connections for

proper torque. In its supplemental information dated December 12, 2003, the applicant stated

that bronze and stainless steel bolting material are used for the bus bar bolted connections on

the normally energized non-segregated bus duct. Bronze and stainless steel bolts are ideal for

use with copper bus because both materials have nearly the same coefficients of thermal

expansion as the copper bus bar. This prevents thermal stress from causing plastic

deformation of the bolts, which is the primary cause of loose connections. EPRI TR104213

(Joint Maintenance and Application Guide) Tables 7-4 and 7-6 show no thermal stress for

bronze or stainless steel bolts used with copper bus.

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EPRI TR1 04213 Section 8.2 states the bolts should be inspected for evidence of overheating,

signs of burning or discoloration, and indications of loose bolts. The bolts should not be

retorqued unless the joint requires service or the bolts are clearly loose.

Applicant's response to RAI 3.6-4 states that accessible normally energized non-segregated

bus duct internal components are visually inspected for insulator and bus bar insulation material

surface anomalies, such as embrittlement, discoloration, cracking, chipping, or surface

contamination. Internal components such as insulation material, bus duct support pieces,

gaskets, insulating boots, taped connections, and bus bar sleeves are inspected. This

inspection will verify that there is no discoloration, cracking, chipping or surface contamination

of the bus bar insulation material at the bolted connections. The absence of discoloration,

cracking, chipping or surface contamination provides positive indication that the bolted

connections are not loose and therefore, the intended function of the bus duct will be

maintained during the period of extended operation.

Applicant stated in LRA Section B.2.2 that it has not experienced any bus bar insulation failures

that would indicate that bolted connections have a creditable aging mechanism. Additionally,

there is no industry experience that indicates loosening of properly designed and installed bus

bar bolted connections is an industry problem for bus duct that is not overloaded. The

reference to SAND 96-0344 page 4-38 used in RAI 3.6-4 does not apply to bus bar bolting. A

review of the empirical data presented in SAND 96-0344 Section 3 shows only nine failures of

medium voltage cable splices. None of the failures were due to thermal cycling; most were due

to mechanical stress and failure of the insulation material.

In summary, there is no plant or industry operating experience that shows that there is a

credible aging mechanism pertaining to the bus bar bolts; therefore, no aging management

other than visual inspection is required. On the basis of its review, the staff's concern is

satisfactorily resolved.

The evaluation of the applicant's AMP focused on program elements. To determine whether

the applicant's aging management program is adequate to manage the effect of aging so that

the intended function will continue to be performed consistent with CLB for the period of

extended operation, the staff evaluated the following seven elements:(1) scope of program, (2)

preventive action, (3) parameter monitored or inspected, (4) detection of aging effects, (5)

monitoring and trending, (6) acceptance criteria, and (7) operating experience. The staff's

evaluation of the applicant's corrective action, confirmation process, and administrative controls

is provided separately in Section 3.0.4 of the staff's safety evaluation.

[Program Scope] This inspection program applies to the normally-energized non-segregated

bus ducts within the scope of license renewal, not subject to the environmental qualification

requirements of 10 CFR 50.49, which can be affected by elevated temperatures prior to the end

of the extended period of operation. The staff was concerned about excluding bus ducts that

are not normally energized from the scope of the program (RAI B.2.2-1). In response to RAI

B.2.2-1, the applicant by a letter dated October 3, 2003, stated that there are non-segregated

bus ducts within the scope of license renewal that are not normally energized. These are bus

ducts connecting the diesel generator to the ESF busses and connecting safety-related buses.

They are included in Section 2.5.1 of the license renewal application. These are not normally

energized and are energized only for technical specification surveillance or emergency

activities. They are only energized for very short durations during normal plant operation and

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are located inside (Reactor/Turbine/Diesel Generator/HPCI) buildings where the environment is

free from moisture, wind, and extreme ambient temperature 'differences. Therefore, thermal

aging is not a concern for the bus duct insulators or sleeves. Thi6re are no other aging

mechanisms applicable for these bus ducts. Periodic surveillance testing performed per

technical specification verifies functionality-of the bus'ducts. Dresden and Quad Cities

operating experience including experience from the non-segregated bus duct (Reserve Auxiliary

Transformer to 4 KV Busses) inspections currently performed at Dresden and Quad Cities also

confirm that no aging mechanisms apply for these bus ducts that would affect their intended

function. On the basis of its review, the staff finds that thermal cycling for bolted connections is

a concern for these bus ducts. The staff notes that EPRI TR1 04213 recommends inspection of

bolted joints for evidence of overheating, signs of burning or discoloration, and indication of

loose bolts (Section 8.2) regardless of bolt material.

LER 26698002 states that component failure was caused by the presence of condensation.

For the bus ducts not normally energized, condensation could occur since the area is 'not" air

conditioned. Additionally, dust, debris and moisture can be introduced inside the bus duct

during maintenance work around the vicinity with relaxed housekeeping practices.

By a letter dated December 22, 2003, the applicant stated that the non-energized nonsegregated bus duct bus bars are tubular aluminum with bolted joint connectors that are

torqued to 65 ft. lbs. Each joint connector is filled around the bolts/nuts with Duxseal and then

taped to provide a smooth surface. The available drawings do not indicate the bolting material.

The applicant believes based on discussion with the vendor that the bolts are zinc plated high

strength steel or stainless steel. The vendor manual states that under normal operating

conditions, no internal maintenance is required on the bus ducts. Additionally, EPRI TR1 04213

Section 8.2 states the bolts should be inspected for evidence of overheating, signs of burning or

discoloration, and indications of loose bolts. The bolts 'should not be retorqued unless the joint

requires service or the bolts are clearly loose.

The applicant stated that there are no credible aging effects concerning bus duct bolted

connections that require management. However, the applicant will include these bus ducts in

the B.2.2 (Periodic Inspection of Non-EQ, Non-Segregated Electrical Bus Ducts) inspection

program to inspect 10% of the bus bar insulation splice material at the bolted connections for

surface anomalies, such as embrittlement, discoloration, cracking, chipping, or surface

contamination. This is part of Commitment #40 of Appendix A of this SER. The absence of

insulation material surface anomalies, such as embrittlement, discoloration, cracking, chipping,

and discoloration provides positive indication that the bolted connections are not loose and

therefore, the intended function of the bus duct will be maintained during the period of extended

operation. This inspection will verify that there are no insulation material surface anomalies,

such as embrittlement, discoloration, cracking, chipping, and discoloration of the bus bar

insulation splice material at the bolted connections. The inspection will also include a,

verification for the presence of dirt and moisture in the bus duct. This is part of Commitment

#40 of Appendix A of this SER. The visual inspection will include as much of the insulation as

can be seen in both directions beyond the location of the bolted material. The initial baseline

inspections will be completed prior to the beginning of the period of extended operation.

Follow-up inspections will be performed on a frequency not to exceed once every ten years. If

degradation is found that could adversely effect the intended function of the bus bar,

inspections will be expanded appropriately to determine the extent of condition. On the basis of

its review, the staff finds that its concern is resolved.

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[Preventive Actions] This is an inspection program only. This program does not prevent or

mitigate aging degradation. This is acceptable since the staff finds no need for such actions.

[Parameters Monitored/Inspected] Accessible normally-energized nonsegregated bus duct

internal components are visually inspected for insulation material surface anomalies, such as

embrittlement, discoloration, cracking, chipping, or surface contamination. As a result of the

staff's RAI 3.6-4, on October 3, 2003, the applicant provided a revision of this element as

follows: "Accessible normally energized non-segregated bus duct internal components are

visually inspected for insulator and bus bar insulation material surface anomalies, such as

embrittlement, discoloration, cracking, chipping, or surface contamination. Internal components

such as insulation material, bus duct support pieces, gaskets, insulating boots, taped

connections, and bus bar sleeves are inspected. The visual inspections also check for

evidence of water and dirt accumulation and presence of foreign material." This is part of

Commitment #40 of Appendix A of this SER. The staff finds this to be acceptable since this

inspection will verify that there is no discoloration, cracking, chipping or surface contamination

of the bus bar insulation material at the bolted connections. The absence of discoloration,

cracking, chipping or surface contamination provides positive indication that the bolted

connections are not loose and therefore, the intended function of the bus duct will be

maintained during the period of extended operation.

[Detection of Aging Effects] Non-segregated bus ducts are inspected at least once every 10

years for material surface anomalies which are precursors to any onset of insulation failure due

to temperature or radiation degradation. Experience has shown that aging degradation is a

slow process. This frequency is therefore adequate to preclude age-related failures of the

conductor insulation. As a result of RAI B.2.2-2, the applicant stated that the program will be

implemented prior to the period of extended operation. The staff finds that the 10-year

inspection frequency is an adequate period to preclude failure of bus ducts because industry

experience has shown that the aging degradation is a slow process.

[Monitoring and Trending] Trending is not included in this activity because the parameters

inspected are difficult to quantify. The 10-year inspection frequency will however provide at

least 2 data points within 20 years, which will permit some characterization of the rate of

degradation. The staff finds this to be acceptable because the two data points will provide

some characterization of the rate of degradation.

[Acceptance Criteria] The accessible non-segregated bus ducts are to be free from

unacceptable visual indications. Unacceptable visual indications are duct insulation material

surface anomalies which suggest that bus duct insulation degradation exists, which if left

unmanaged, could lead to a loss of the intended function, as determined by an engineering

evaluation. The staff finds that the acceptance criteria to be acceptable because an

unacceptable visual indication will indicate bus duct insulation degradation and loose bolts.

[Operating Experience] No age-related bus duct insulation failures that would indicate aging to

be a concern at Dresden or Quad Cities have been identified. However, industry experience

indicates that high temperatures may cause degradation of electrical insulation materials.

Some visual surface indications of high-temperature degradation in bus duct electrical

insulation, such as color changes or surface cracking, have been observed in the industry. The

staff finds that the applicant has adequately addressed operating experience.

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X I FL , _F ,

The staff also reviewed the UFSAR supplement to determine whether it provides an adequate

description of the program.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the bus duct will

effectively manage or monitor the aging effects identified in the LRA.

Conclusions. On the basis of its review of the applicant's program, the staff finds that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the UFSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

3.6.2.4.2 High Voltage Electrical Switchyard Bus

Summary of Technical Information in the Application. Switchyard bus electrically connect

specified sections of an electrical circuit to deliver voltage or current to various equipment and

components throughout the plant. The switchyard bus is used in swtchyards to connect two or

more elements of an electrical power circuit such as active disconnect switches and passive

transmission conductors. The material used for the switchyard bus is aluminum and iron. The

staff notes that this component is missing from LRA Table 3.6-2.

Staff Evaluation. In the LRA Table 3.6-2, the staff did not find aging management review

results for switchyard bus. The staff finds that change in material properties leading to

increased resistance and heating due to oxidation, and cracking due to vibration are known to

be potential aging effects/mechanism for the high voltage electrical switchyard bus. The staff

requested the applicant to provide a description of aging management program, in accordance

with the requirements of 10 CFR 54:21 (a)(3), used to detect/manage above mentioned aging

effects or provide a justification why such a program is not needed (RAI 3.6-7). In its response

dated October 3, 2003, the applicant stated that the switchyard bus consists of aluminum tube,

copper bar, aluminum conductors, and the necessary connections. Conductor connections are

generally of the compression bolted category. The switchyard bus is located in an outside

environment subject to ambient temperatures that normally range from -6 OF to 93 OF

(referenced in section 9.4 of the Dresden & Quad Cities UFSAR). Copper and aluminum

materials do not experience any appreciable aging effects in this environment. Additionally,

connections are adequately designed and treated with corrosion inhibitors such as "No-oxide."

For this reason, the switchyard bus is not susceptible to corrosion due to oxidation.

There are no credible sources of vibration in the switchyard bus at Dresden and Quad Cities

stations that could result in fatigue or cracking. As such, this aging mechanism does not apply.

The staff finds that the applicant adequately addressed why these aging effects are not

applicable aging effects at Dresden and Quad Cities.

Conclusions. On the basis of the staff's review of the information presented in the RAI 3.6-7

response, the staff concludes that switchyard bus has no aging effects that require

management and will perform its intended function for the period of extended operation.

3-489.
3.6.2.4.3 High Voltage Transmission Conductors

Summary of Technical Information in the ApDlication. The high voltage transmission

conductors within the scope of license renewal rule are those associated with the power feed

from the switchyard to RATs. The function of the high voltage transmission conductors is to

supply power to the plant systems through the RATs. Materials used for the high-voltage

transmission conductors are aluminum conductor steel reinforced (ACSR).

Aging Effects

The applicant identified loss of material/corrosion as the aging effects/mechanism for the

transmission conductors.

Aging Management Program

The applicant stated that the plant outdoor environment is not subject to heavy industry air

pollution or saline environment. Aluminum is reactive, but develops an aluminum oxide film that

protects it from further corrosion. Therefore, no aging management program is proposed.

Staff Evaluation. In LRA Table 3.6-2, Ref. No. 3.6.2.1, aging effect/mechanism for high voltage

transmission conductors is identified as loss of materialcorrosion. However, no aging

management program for high voltage transmission conductors and connections is provided.

The LRA states that "the plant outdoor environment is not subject to heavy industry air pollution

or saline environment. Aluminum is reactive but develops an aluminum oxide film that protects

it from further corrosion." The staff finds that loss of conductor strength and vibration is a

known potential aging effects/mechanism for transmission line conductors. The most prevalent

mechanism contributing to loss of conductor strength of an aluminum conductor steel reinforced

(ACSR) transmission conductor is corrosion which includes corrosion of steel core and

aluminum strand pitting. For ACSR conductors, degradation begins as a loss of zinc from the

galvanized steel core wires. Corrosion rate depend largely on air quality which includes

suspended particles chemistry, SO2 concentration in air, precipitation, fog chemistry, and

meteorological conditions. Transmission conductor vibration (caused by wind loading) or sway

could cause loss of material (wear) and fatigue.

The staff requested the applicant to provide a description of aging management program, in

accordance with the requirements of 10 CFR 54.21 (a)(3), used to detect/manage the aging

effects discussed above or provide justification why such a program is not needed (RAI 3.6-8).

In response to RAI 3.6-8, the applicant by letter dated October 3, 2003, stated that EPRI

1003057, License Renewal Electrical Handbook, discusses the aging of high voltage

transmission conductors and concludes that the potential aging mechanism of corrosion does

not produce any significant effects that would be of a concern for their intended function.

Regarding high voltage transmission conductor strength, tests performed by Ontario

Hydroelectric showed a 30% loss of composite conductor strength of an 80-year-old ACSR

conductor due to corrosion. Using the example of a 4/0 ACSR conductor, EPRI 1003057

shows the ultimate strength and the National Electrical Safety Code (NESC) heavy load tension

requirements of 4/0 ACSR are 8350 lbs. and 2761 lbs. respectively. The margin between the

NESC Heavy Load and the ultimate strength is 5589 lb.; i.e., there is a 67% of ultimate strength

margin. The Ontario Hydroelectric study showed a 30% loss of composite conductor strength

in an 80-year-old conductor. In the case of the 4/0 ACSR transmission conductors, a 30% loss

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of ultimate strength would mean that there would still be a 37% ultimate strength margin

between what is required by the NESC and the actual conductor strength.

There is a set percentage of composite conductor strength established at which a transmission

conductor is replaced. The NESC requires that tension on installed conductors be limited to a

maximum of 60% of the ultimate conductor strength. The NESC also sets the maximum

tension a conductor must be designed to withstand under various load requirements, which

includes consideration of ice, wind and temperature. The applicant's design and installation

practice limits the tension in the conductors such that it will not exceed a maximum of 50% of its

rated tensile strength. Therefore, for a typical transmission conductor, there is ample design

margin to offset the loss of strength due to corrosion and maintain the transmission conductor

intended function through the extended period of operation. With respect to corrosion of steel

core caused by loss of zinc coating or aluminum strand pitting corrosion, this is a very slow

acting aging effect that is even slower for rural areas with generally less suspended particles

and SO2 concentrations in the air than urban or industrial areas. The transmission conductors

at Dresden and Quad Cities do not see air particulates or contaminants as seen in urban or

heavy industrial areas. Therefore, corrosion is not a credible aging mechanism for the intended

function of Dresden and Quad Cities transmission conductors.

EPRI 1003057 also discusses the aging of high voltage transmission conductors and concludes

that the potential aging mechanism of vibration does not produce any significant effects that

would be of a concern for their intended function. Regarding wind loading induced vibration,

wind loading is considered in the design and installation. Aging effect of loss of material and

fatigue that could be caused by transmission conductor vibration or sway are not applicable in

that they would not cause a loss of intended function for the extended period of operation.

Experience has shown that the transmission conductors do not normally swing significantly.

When they do swing due to a substantial wind, they do not continue to swing for very long once

the wind has subsided. Wind loading that can cause a transmission line to sway is considered

in the design and installation. Therefore, wind loading induced vibration and fatigue are not

credible aging mechanisms, and will not cause a loss of intended function of the conductors at

Dresden and Quad Cities.

The applicant concluded that the aging mechanism identified in the RAI are not significant for

Dresden and Quad Cities transmission conductors in that they would not cause a loss of

intended function for the period of extended operation.

The staff finds that the applicant adequately addressed why these aging effects (loss of

conductor strength and vibration) are not applicable at Dresden and Quad Cities transmission

conductors.

Conclusions. On the basis of the staff's review of the information presented in the RAI 3.6-8

response, the staff concludes that transmission conductors have no aging effects that require

management and will perform their intended function for the period of extended operation.

3.6.2.4.4 High Voltage Insulators

Summary of Technical Information in the Application. High-voltage insulators within the scope

of license renewal rule are those associated with the power feeds from the switchyard to

reserve auxiliary transformers. The function of high voltage insulators is to support and insulate

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the high voltage transmission conductors. Materials used for the high-voltage insulators are

porcelain.

Aging Effects

The applicant identified no aging effects/mechanisms for the high-voltage insulators.

Aging Management Program

The applicant stated that the plant outdoor environment is not subject to heavy industrial air

pollution or saline environment. Plant indoor and outdoor environments are not conductive to

promoting aging degradation of porcelain components. Therefore, no aging management

program is proposed.

Staff Evaluation. In the LRA Table 3.6-2, the aging effect/mechanism for porcelain insulator is

indicated as unone." The LRA states that "the plant outdoor environment is not subject to heavy

industrial air pollution or saline environment. Plant indoor and outdoor environment are not

conducive to promoting aging degradation of porcelain components." The staff finds that

surface contamination, cracking, and loss of material due to wear are the aging

effect/mechanism. Various airborne materials such as dust, salt, and industrial effluents can

contaminate insulator surfaces. A large buildup of contamination enables the conductor voltage

to track along the surface more easily and can lead to insulator flashover.

Surface contamination can be a problem in areas where there are greater concentrations of

airborne particles such as near facilities that discharge shoot or near the sea cost where salt

spray is prevalent. Porcelain is essentially a hardened, opaque glass. As with any glass,

porcelain will crack or break when subjected to enough force. Cracks have also known to occur

with insulators when the cement that binds the part together expands enough to crack the

porcelain. This phenomenon is known as cement growth. Mechanical wear is an aging effects

for strain and suspension insulators in that they are subject to movement. Movement of the

insulators can be caused by wind blowing the supported transmission conductor, causing it to

swing from side to side. If this swing is frequent enough, it could cause wear in the metal

contact points of the insulator string and between an insulator and supporting hardware. The

staff requested the applicant to provide a discussion why these aging effects/mechanism are

not of concern for Dresden and Quad Cities (RAI 3.6-6). In response to RAI 3.6-6, the

applicant by letter dated October 3, 2003, stated that the concerns identified in the RAI were

evaluated and discussed as follows:

Surface Contamination

Regarding the potential for contamination of insulators, the buildup of surface contamination is

gradual. In most areas, this contamination is washed away by rain or snow; the glazed

insulator surface aids this contamination removal. A large buildup of contamination enables the

conductor voltage to track along the surface more easily and can lead to insulator flashover.

Surface contamination can be a problem in areas where there are greater concentrations of

airborne particles such as near facilities that discharge soot or near a seacoast where salt spray

is prevalent. Dresden and Quad Cities are located in areas where airborne particle

concentrations are comparatively low, since they are not located in heavy industrialized areas.

Any insignificant contamination would be washed away by the rainfall or snow, which is

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PI .L . ,- I -[ ,i. it'

seasonal in nature, and cumulative build up is not expected. There is no salt spray that can

affect the insulators as Dresden and Quad Cities are not located near a seacoast. Therefore,

surface contamination is not a credible event for the insulators at Dresden and Quad Cities.

Cracking/ Cracking of Cement Due to Cement Growth

Regarding HV porcelain insulator cracking, porcelain is essentially a hardened, opaque glass.

As with any glass, if subjected to enough force it will crack or break. The most common cause

for cracking or breaking of an insulator is being struck by an object (e.g., a rock or bullet).

Cracking and breaking caused by physical damage is not an aging effect and is not subject to

an AMR. Cracks have been known to occur with insulators when the cement that binds the

parts together expands enough to crack the porcelain. This phenomenon, known as cement

growth, occurs mainly because of improper manufacturing processes or materials, which make

the cement more susceptible to moisture penetration, and the specific design and application of

the insulator. Therefore, cracking due to cement growth is not an applicable aging effect for the

HV switchyard insulators in the service conditions they are exposed to at Dresden and Quad

Cities. Along with improper manufacturing, cracking would also be caused by severe

temperature extremes or variation. The temperature extreme will be seasonal in nature and

does not produce a cumulative effect for 60 years. Any temperature related failures would be

manifested in a few years. The insulators are properly selected and specified for the expected

conditions. This is a design consideration. In summary, the concern of cracking is either event

driven or a design issue and is not an aging concem.

Loss of Material Due to Wear/ Mechanical Wear Due to Wind Blowing the Transmission

Conductors

Regarding mechanical wear, this applies to suspension insulators in that they are subject to

movement. Movement of the insulators can be caused by wind blowing the supported

transmission conductor, causing it to swing from side to side. If this swinging is frequent

enough, it could cause wear in the metal contact points of the insulator string and between an

insulator and the supporting hardware. Although this mechanism is possible, experience has

shown that the transmission conductors do not normally swing significantly. When they do

swing due to a substantial wind, they do not continue to swing for very long once the wind has

subsided. Wind loading that can cause a transmission line and insulators to sway is considered

in the design and installation. Therefore, the loss of material due to wear is not considered a

credible aging effect and will not cause a loss of intended function of the insulators at Dresden

and Quad Cities. Therefore, loss of material due to wear is not an applicable aging effect for

insulators.

The staff finds that the applicant adequately addressed why these aging effects (surface

contamination, cracking, and loss of material due to wear) are not applicable at Dresden and

Quad Cities.

Conclusions On the basis of the staff's review of the information presented by the applicant,

the staff concludes that high-voltage insulators have no aging effects that require management

and will perform their intended function for the period of extended operation.

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3.6.2.4.5 Non-EQ Electrical Penetration Assemblies

Summary of Technical Information in the Application. The applicant did not provide an AMR of

the electrical penetration assemblies.

Staff Evaluation. The staff requested the applicant to clarify whether there are any electrical

penetrations that are not covered under EQ program (RAI 3.6-2). In response to the staff's RAI

3.6-2, the applicant on October 3, 2003, stated that at Dresden Station, all electrical

penetrations are covered under the Environmental Qualification (EQ) program. At Quad Cities

Station, all but three electrical related penetrations (1 -Xl 02B, 2-X1 OOA, and 2-X1 05A) are part

of the station EQ program. These three penetrations serve circuits (such as drywell booster

fans and main steam line vibration monitoring instrumentation) that do not perform any

electrical intended function.

As stated in Section 2.5.1.4 of the License Renewal Application, the intended function

(electrical continuity) is managed by the EQ program. The mechanical and structural related

intended functions of all electrical penetrations, including the three Quad Cities penetrations not

included within the station EQ program, are addressed in Table 2.4-1 under Component Group

"Containment Penetrations (Electrical)" and the associated aging management is discussed in

Table 3.5-1, Aging Management Reference 3.5.1.3 of the application. The staff requested the

applicant to provide details about these circuits (i.e., energized during shutdown only and power

supply is disconnected during plant operation, etc.). The staff also requested the applicant to

discuss why the aging of the insulation do not have any effect on the penetration damage curve

so that penetration seal integrity is maintained as part of containment pressure boundary.

In its supplemental information dated December 5, 2003, the applicant stated that the drywell

booster fans are continuously energized during plant operations. The circuit for these fans is

protected by redundant 100 amp in-scope circuit breakers. The cables from the MCC to the

penetrations and from the penetrations to the fans are in-scope and managed by aging

management program B.1.33, "Electrical Cables and Connections Not Subject to 10 CFR 50.49

Environmental Qualification Requirements." The conax penetration feed-through-modules are

#2 AWG solid copper conductors insulated with polyimide film. The circuits are designed such

that the 100 amp breakers are coordinated to clear all fault currents before the short circuit

capacity of the #2 AWG feed-through-modules is exceeded thus preventing damage to the

penetration seal integrity. There are no credible aging effects that reduce the short circuit

capability of solid copper conductors. Short circuit capacity is based on the circular mills of the

copper conductor.

The vibration Instrumentation circuits are low voltage, milliamp circuits protected by fuses.

Fault currents are in the milliamp range and not severe enough to cause damage to the # 18

AWG feed-through-modules. The cables for these instrumentation circuits are in-scope and

managed by aging management program B.1.33, "Electrical Cables and Connections Not

Subject to 10 CFR 50.49 Environmental Qualification Requirements."

The design of the Conax penetration module is a stainless steel tube that is sealed at both ends

with polysulfone. Solid copper polymide film insulated conductors passes though the stainless

steel tube and are molded into the polysulfone seal at both ends to provide a leak proof seal. A

visual inspection of the exposed polymide film insulation will not provide any indication of the

leak tightness of the penetration because the insulation cannot be visually inspected once it

3-494
passes into the polysulfone seal. The aging management programs that are used to manage

the aging of the pressure boundary function are Containment ISI (B.1.26) and Containment leak

rate test (B.1.28).

Identical Conax EQ penetrations are installed at the Dresden station. The Dresden Conax EQ

penetrations are qualified for 60 years of normal and one-year accident/post accident conditions

in accordance with IEEE 323-1983 requirements and NUREG-0588, Category I. The Quad

Cities Conax penetrations are bounded by the environmental qualification reports approved for

Dresden.

The applicant concluded that license renewal intended function of the Quad Cities Non-EQ

penetrations will be maintained during the period of extended operation by using AMPs

Containment IS (B.1.26) and Containment Leak Rate Test (B.1.28).

On the basis of its review, the staff finds that three non-Class 1 E penetrations at Quad Cities

will not require an AMR.

Conclusions. On the basis of its review, the staff concludes that no AMR is required for

Dresden since all penetrations are covered under EQ program. The staff also concludes that

no AMR is required for Quad Cities Non-EQ penetrations and that the component intended

function for Quad Cities will be maintained consistent with the CLB for the extended operation

as required by 10 CFR 54.21 (a)(3).

3.7 Conclusion for Aging Management

On the basis of its review of AMR results and AMPs, the staff concludes that actions have been

identified and have been or will be taken to manage the effects of aging during the period of

extended operation on the functionality of SCs subject to an AMR such that there is reasonable

assurance with the CLB, as required by 10 CFR 54.21 (a)(3).

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4. TIME-LIMITED AGING ANALYSES

4.1 Identification of Time-Limited Aging Analyses

This section addresses the identification of time-limited aging analyses (TLAAs). The applicant

discusses the TLAAs in Sections 4.2 through 4.7 of the license renewal application (LRA). The

staff's review of the TLAAs can be found in Sections 4.2 through 4.7 of this safety evaluation

report (SER).

The TLAAs are plant-specific safety analyses that are based on an explicitly assumed 40-year

plant life. Pursuant to Title 10, Section 54.21 (c)(1), of the Code of Federal Regulations (10

CFR 54.21 (c)(1)), the applicant for license renewal must provide a list of TLAAs, as defined in

10 CFR 54.3.

In addition, pursuant to 10 CFR 54.21 (c)(2), an applicant must provide a list of plant-specific

exemptions granted under 10 CFR 50.12 that are based on TLAAs. For any such exemptions,

the applicant must provide an evaluation that justifies the continuation of the exemptions for the

period of extended operation.

4.1.1 Summary of Technical Information in the Application

A list of potential generic TLAAs was assembled using the scope and methods for identifying

TLAAs consistent with NUREG-1 800, Nuclear Energy Institute (NEI) 95-10, the Statements of

Consideration for 10 CFR Part 54, and prior license renewal applications. The current licensing

basis (CLB) for the Dresden/Quad Cities Nuclear Power Station (D/QCNPS), including the

updated final safety analysis report (UFSAR) and design-basis documents, was searched to

identify plant-specific and unit-specific TLAAs. The resulting list of potential TLAAs was

screened against the six 10 CFR 54.3(a) criteria and divided into the following general TLAA

categories:

* neutron embrittlement of the reactor vessel and internals

* metal fatigue of the reactor vessel, internals, and primary coolant boundary piping and

components

* environmental qualification of electrical equipment

* loss of prestress concrete containment tendons

* fatigue of the primary containment, attached piping, and components

* other plant-specific TLAAs

Information about the TLAAs in a category is described as to applicability, summary description,

analysis, and disposition in accordance with 10 CFR 54.21 (c)(1).

The applicant searched docketed correspondence, the operating licenses, and the UFSARs to

identify any exemptions in effect, pursuant to 10 CFR 50.12. The applicant stated that the

4-1
identified exemptions were evaluated to determine if they involved TLAAs as defined in 10 CFR

54.3. No exemptions based on a TLAA as defined in 10 CFR 54.3 were identified.

4.1.2 Staff Evaluation

In LRA Section 4.1, the applicant identified the TLAAs applicable to Dresden and Quad Cities

and discussed exemptions based on TLAAs. The staff reviewed the information to determine

whether the applicant provided adequate information to meet the requirements of 10 CFR

54.21 (c)(1) and 10 CFR 54.21 (c)(2).

As indicated by the applicant, TLAAs are defined in 10 CFR 54.3 as analyses that meet the

following six criteria:

(1) involve systems, structures, and components within the scope of license renewal, as

delineated in Section 54.4(a)

(2) consider the effects of aging

(3) involve time-limited assumptions defined by the current operating term (for example, 40

years)

(4) were determined to be relevant by the licensee in making a safety determination

(5) involve conclusions or provide the basis for conclusions related to the capability of the

system, structure, and component to perform its intended functions, as delineated in

Section 54.4(b)

(6) are contained or incorporated by reference in the CLB

The applicant listed the TLAAs applicable to Dresden and Quad Cities, both jointly and

individually, in Table 4.1-1 of the LRA. The staff reviewed the categorization of the TLAAs for

conformance with Tables 4.1-2 and 4.1-3 in NUREG-1800 and potential TLAAs that were

identified from the review of other license renewal applications.

4.1.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable list

of TLAAs as required by 10 CFR 54.21 (c)(1), and has confirmed that no 10 CFR 50.12

exemptions have been granted on the basis of a TLAA, as required by 10 CFR 54.21 (c)(2).

4.2 Reactor Vessel and Internals Neutron Embrittlement

During plant service, neutron irradiation reduces the fracture toughness of ferritic steel in the

reactor vessel beltline region of light-water nuclear power reactors. Areas of review to ensure

that the reactor vessel has adequate fracture toughness to prevent brittle failure during normal

and off-normal operating conditions are (1) upper-shelf energy (USE), (2) adjusted reference

temperature (ART), (3) a low-pressure coolant injection (LPCI) reflood thermal shock analysis,

(4) heatup and cooldown (pressure-temperature limit) curves, and (5) Boiling Water Reactor

4-2
(BWR) Vessel and Internals Project (VIP) VIP-05 analysis for elimination of circumferential weld

inspection, and (6) analysis of the axial welds. The adequacy of the analyses for these six

areas is reviewed for the period of extended operation.

The ART is defined as the sum of the initial (unirradiated) reference temperature (initial RTNDT),

the mean value of the adjustment in reference temperature caused by irradiation (delta RTNDT),

and a margin (m) term. The delta RTNDT is the product of a chemistry factor (CF) and a fluence

factor. The chemistry factor is dependent upon the amount of copper and nickel in the material

and may be determined from tables in Regulatory Guide (RG) 1.99, Revision 2, or from

surveillance data. The fluence factor is dependent upon the neutron fluence. The margin term

is dependent upon whether the initial RTN T is a plant-specific or a generic value and whether

the CF was determined using the tables in RG 1.99, Revision 2, or surveillance data. The

margin term is used to account for uncertainties in the values of the initial RTNDT, the copper

and nickel contents, the fluence, and the calculation methods. Revision 2 of RG 1.99

describes the methodology to be used in-calculating the margin term. The mean RTNDT is the

sum of the initial RTNDT and the delta RTNDT, without the margin term.

The ART values are used in the analysis for the adjusted reference temperature for the reactor

vessel material because of neutron embrittlement, the pressure-temperature limits, and the

reflood thermal shock. The mean RTNDT values are used in the analysis of the circumferential

weld examination relief and the axial weld failure probability.

4.2.1 Summary of Technical Information in the Application

The applicant described its evaluation of this TLAA in LRA Section 4.2, uNeutron Embrittlement

of the Reactor Vessel and Intemals." In order to demonstrate that neutron embrittlement does

not significantly impact BWR reactor pressure vessel (RPV) and vessel internals integrity during

the license renewal term, the applicant included discussion of the following topics related to

neutron embrittlement in LRA Section 4.2:

* reactor vessel materials upper-shelf energy reduction due to neutron embrittlement (LRA

Section 4.2.1)

e adjusted reference temperature for reactor vessel materials due to neutron embrittlement

(LRA Section 4.2.2)

* reflood thermal shock analysis of the reactor vessel (LRA Section 4.2.3)

* reflood thermal shock analysis of the reactor vessel core shroud and repair hardware (LRA

Section 4.2.4)

* reactor vessel thermal limit analyses-operating pressure-temperature limits (LRA Section

4.2.5)

* reactor vessel circumferential weld examination relief (LRA Section 4.2.6)

* reactor vessel axial weld failure probability (LRA Section 4.2.7)

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I

4.2.1.1 Reactor Vessel Materials Upper-Shelf Energy Reduction Due to Neutron Embrittlement

Appendix G of 10 CFR Part 50 requires that the predicted end-of-life Charpy USE for reactor

vessel materials be at least 50 ft-lb, unless an approved analysis supports a lower value. The

applicant determined the 54 effective full-power year (EFPY) fluence for the Dresden and Quad

Cities reactor vessels using the methodology of NEDC-32983P, uGeneral Electric Methodology

for Reactor Pressure Vessel Fast Neutron Flux Evaluation," which was approved by the U.S.

Nuclear Regulatory Commission (NRC) in a letter dated September 14, 2001, from Mr. S.A.

Richards (NRC) to Mr. J.F. Klapproth (General Electric (GE)). The applicant performed one

bounding fluence calculation for D/QCNPS and determined peak fluence at the vessel inner

surface and at the 1/4 vessel thickness location (1/4T) for evaluating USE. Initial unirradiated

test data are not available for the D/QCNPS reactor vessels to demonstrate a minimum 50 ft-lb

USE using the standard methods. Therefore, the applicant evaluated the 54-EFPY USE by an

equivalent margin analysis methodology approved by the NRC in NEDO-32205-A. The

applicant used calculated 54-EFPY fluence and D/QCNPS surveillance capsule results for

evaluating the 54-EFPY USE. The results are presented in LRA Tables 4.2.1-1 through 4.2.1-

8. The results show that the percent reductions in USE for limiting beltline plates and welds for

all four D/QCNPS units are less than the BWRVIP-74 equivalent margin analysis acceptance

criteria. The applicant stated that a report summarizing the results of the equivalent margin

analysis will be submitted for NRC approval by December 31, 2003. The applicant further

stated that the 54-EFPY USE values will be managed in conjunction with the surveillance

capsule results from the BWRVIP integrated surveillance program.

4.2.1.2 Adjusted Reference Temperature for Reactor Vessel Materials Due to Neutron

Embrittlement

Neutron irradiation causes an increase in the ART of the RPV beltline materials. Tables 4.2.2-1

and 4.2.2-2 of the LRA provide the 54-EFPY peak fluence, shift in initial nil-ductility transition

reference temperature (delta RTNDT), and ART, respectively, for Dresden and Quad Cities units.

In these tables, the applicant provided the delta RTNDT and ART values only for one limiting

material. The applicant stated that because of the refinement in the approved methodology

used to calculate the 54-EFPY fluence, the material with the limiting ART is the axial weld, with

the exception of Dresden Unit 3 where the axial weld and girth weld ART values are identical.

The applicant further stated that the use of American Society of Mechanical Engineers (ASME)

Code Case N-588 for Dresden Unit 3 causes the axial weld to become the limiting material.

Therefore, data for a single limiting material were presented in LRA Tables 4.2.2-1 and 4.2.2-2.

4.2.1.3 Reflood Thermal Shock Analysis of the Reactor Vessel

In LRA, Section 4.2.3, the applicant stated the following:

The Dresden and Quad Cities UFSARs describe an end-of-life thermal shock analysis performed

on the reactor vessels for a design basis LOCA followed by a low-pressure coolant injection. The

effects of embrittlement assumed by this thermal shock analysis will change with an increase in

operating period. This analysis satisfies the criteria of 10 CFR 54.3(a). As such, this analysis is a

TLAA.

Thermal shock analysis of the RPV considers a design-basis loss-of-coolant accident (LOCA)

followed by an LPCI accounting for the effects of neutron embrittlement at the end-of-life (54

4-4
EFPYs). The original analysis has been superseded by an analysis for BWR-6 vessels that is

applicable to the D/QCNPS BWR-3 reactor vessels. The revised analysis assumes end-of-life

material toughness, which in turn depends on end-of-life ART. The critical location for fracture

mechanics analysis is at the 1/4T location. For this event, the peak stress intensity occurs at

approximate 300 seconds after the LOCA. At that time, the temperature at 1/4T is

approximately 204 0C (400 0F), which is much higher than the 54-EFPY ART of 40 OC (104 OF)

for the limiting material of the D/QCNPS vessels. Therefore, the applicant indicated that the

revised analysis is valid for the period of extended operation.

4.2.1.4 Reflood Thermal Shock Analysis of the Reactor Vessel Core Shroud and Repair

Hardware

In LRA, Section 4.2.4, the applicant stated the following:

Radiation embrittlement may affect the ability of reactor vessel internals, particularly the core

shroud and repair hardware, to withstand a low-pressure coolant injection (LPCI) thermal shock

transient. Core shroud repair hardware was installed on the Dresden and Quad Cities core

shrouds after 20 years of operation when cracks were found on the shroud. The analysis of core

shroud strain due to reflood thermal shock is a TLAA because it is part of the current license basis,

supports a safety determination, and is based on the calculated lifetime neutron fluence.

The thermal shock analysis of D/QCNPS reactor vessel core shrouds considers the

embrittlement effects of 54-EFPY fluence at the inside surface opposite to the midpoint of the

fuel'centerline where the core shroud receives the maximum irradiation. The applicant

calculated 54-EFPY fluence for that location on the reactor vessel core 'shroud using the

methodology of NEDC-32983P, which was approved by the NRC. The calculated 54-EFPY

fluence at that location was 5.85 x 1020 n/cm2. The applicant stated that the calculated thermal

strain amplitude at the most irradiated location is 0.3 percent. The applicant further stated that

according to the GE document Y1002A602, Revision 3, "304 Stainless Steel, Irradiated,"

October 16, 1985, the allowable value of the thermal strain for irradiation levels in excess of 1

x 1021 n/cm2 and for this faulted event is at least 20 percent, which bounds the 0.3 percent

thermal strain amplitude in Dresden and Quad Cities. Therefore, the applicant indicated that

the peak thermal shock strain location is acceptable considering the embrittlement effects of a

60-year (54-EFPY) operating period.

4.2.1.5 Reactor Vessel Thermal Limit Analyses-Operating Pressure-Temperature Limits

The applicant used the ART of the limiting beltline material to determine the beltline pressuretemperature (P-T) limits to account for irradiation effect. The applicant stated that it will revise

P-T limits for the four D/QCNPS units and submit them to the NRC for approval before the

start of the extended period of operation using an approved fluence methodology. The

applicant further stated that it will use ASME Code Cases N-640 and N-588 (Dresden Unit 3

only) for revising the P-T limits. The applicant will manage the P-T limits using approved

fluence calculations when there are changes in the power of core'design in conjunction with

surveillance capsule results from the BWRVIP integrated surveillance program.

4-5
4.2.1.6 Reactor Vessel Circumferential Weld Examination Relief

The analysis in BWRVIP-05, "BWR Reactor Pressure Vessel Shell Weld Inspection

Recommendations," showed that the failure rate of the reactor vessel shell axial weld is orders

of magnitude greater than 40-year end-of-life circumferential weld failure rate. This analysis

has been used to justify relief from inspection of the circumferential welds. The circumferential

weld examination relief analysis meets the requirements of 10 CFR 54.3(a) and is, therefore, a

TLAA. The applicant presented the following data in LRA Table 4.2.6-1 for the circumferential

welds of the Dresden vessels-mean values for copper and nickel contents for each vessel,

mean 54-EFPY neutron fluence (E>1 MeV), delta RTNDT, and mean 54-EFPY RTNDT. In LRA

Table 4.2.6-1, the applicant also presented the 64-EFPY data for circumferential welds of a

Babcock and Wilcox (B&W) vessel from Table 2.6-5 of the final safety evaluation report

(FSER) for BWRVIP-05. In a letter dated April 17, 2003, from Mr. P.R. Simpson, Exelon

Nuclear, to the NRC, the applicant sent corrections to LRA Table 4.2.6-1. The corrected

values of delta RTNDT and mean 54-EFPY RTNDT are 44 OF and 54 0F for Dresden Unit 2, and

58 OF and 53 OF for Dresden Unit 3. The comparison of the corrected Dresden data with the

BWRVIP-05 FSER data indicates that the Dresden 54-EFPY mean RTNDT values are bounded

by the 64-EFPY RTNDT value of 129 OF for a B&W vessel. The applicant therefore indicated

that the conditional failure probability of Dresden RPV circumferential welds is bounded by the

corresponding NRC analysis results presented in the SER for BWRVIP-05. As indicated in

LRA Section 4.2.6, this TLAA applies only to the two Dresden units because Dresden received

relief from the reactor vessel circumferential weld examination for the remainder of the 40-year

licensed operating period at the time the LRA was prepared. However, the applicant submitted

a similar relief request for Quad Cities on May 16, 2003, which is currently being reviewed by

the staff. The applicant was required to submit an update to LRA Section 4.2.6 to include the

Quad Cities vessel circumferential weld examination relief analysis in accordance with 10 CFR

54.3(a) upon the staff's approval of the May 16, 2003, relief request. This was identified as

Confirmatory Item 4.2.1.6. In response to Confirmatory Item 4.2.1.6, in a letter dated March 5,

2004, the applicant submitted a revision to the UFSAR supplement for the reactor vessel

circumferential weld examination relief TLAA. The revised supplement refers to the

documents related to RPV circumferential weld relief request extension for the license renewal

term. The staff reviewed this supplement and found that it provides an adequate summary

description regarding the evaluation of this TLAA. Therefore, Confirmatory Item 4.2.1.6 is

closed.

4.2.1.7 Reactor Vessel Axial Weld Failure Probability

As discussed in the preceding paragraph, Dresden has followed the BWRVIP-05 results and

received relief from the circumferential weld inspections for the remaining 40-year licensed

operating period. Quad Cities never submitted for this relief. Therefore, the analysis for the

reactor vessel axial weld failure probability is a TLAA only for the two Dresden units. For the

extended operating period, the applicant presented the limiting axial weld 54-EFPY properties

for Dresden Units 2 and 3 in LRA Table 4.2.7-1. In a letter, dated April 17, 2003, from Mr. P.R.

Simpson, Exelon Nuclear, to the NRC, the applicant sent corrections to LRA Table 4.2.7-1.

The corrected values of delta RTNDT and mean 54-EFPY RTNDT are 44 OF and 67 OF for both

Dresden Units 2 and 3. The corrected data are compared with the corresponding data for a

B&W vessel from Table 2.6-5 in the NRC SER for BWRVIP-05 and the data for the Clinton

plant from the supplement for the SER. The applicant stated that the Dresden limiting axial

weld chemistry, chemistry factor, and the mean 54-EFPY RTNDT values are within the limits of

4-6
the values assumed in the analysis performed by the NRC staff in the March 7, 2000,

BWRVIP-05 SER Supplement and the 64-EFPY limits and values presented in Table 2.6-5 of

the SER.

The determination of the failure frequency of the limiting axial weld assumes that essentially

100 percent (i.e., 90 percent) of the vessel axial welds are inspected. However, because of

various obstructions within the Dresden reactor vessels, the actual inspection can include less

than 90 percent of axial welds. The applicant performed an analysis for the current 40-year

operating period to assess the effect on the probability of fracture of the vessel axial welds

because of the actual inspection performed. The analysis indicated that the conditional

probabilities of failure because of a low-temperature over-pressurization event are very small,

3.89 x 108 and 5.07 x 108 on a per year basis for Dresden Units 2 and 3, respectively. The

analysis results show that the calculated unit-specific axial weld conditional failure probabilities

at 54 EFPYs are less than the failure probabilities calculated by the NRC staff for a B&Wfabricated vessel, presented in Table 2.6-5 of the BWRVIP-05 SER at 64 EFPYs, and the

limiting Clinton values found in Table 3 of the SER Supplement. The applicant, therefore,

indicated that the probability of failure of an axial weld at Dresden will provide adequate margin

above the probability of failure of a circumferential weld, in support of relief from inspection of

circumferential welds, for the extended operating period.

4.2.2 Staff Evaluation

4.2.2.1 Reactor Vessel Materials Upper-Shelf Energy Reduction Due to Neutron

Embrittlement

Section IV.A.la of Appendix G of 10 CFR Part 50 requires, in part, that the RPV beltline

materials have Charpy USE values in the transverse direction for base metal and along the

weld for weld material of no less than 50 ft-lb (68J) throughout a facility's license period, unless

it is demonstrated in a manner approved by the Director, Office of Nuclear Reactor Regulation,

that lower values of Charpy USE will ensure margins of safety against fracture equivalent to

those required by Appendix G of Section Xl of the ASME Code.

By letter dated April 30,1993, the Boiling Water Reactor Owners Group (BWROG) submitted

a topical report entitled "10 CFR Part 50 Appendix G Equivalent Margins Analysis for Low

Upper Shelf Energy in BWR-2 Through BWR-6 Vessels," to demonstrate that BWR RPVs

could meet margins of safety against fracture equivalent to those required by Appendix G to

the ASME Code, Section Xl, for Charpy USE values less than 50 ft-lb. In a letter dated

December 8, 1993, the staff concluded that the topical report demonstrated that the evaluated

materials (including BWR/3-6 plates, Non-Linde SAW welds, and electroslag welds (ESW))

have the margins of safety against fracture equivalent to Appendix G of ASME Code Section

Xl, in accordance with Appendix G of 10 CFR Part 50. In that report, the BWROG derived

through statistical analysis the unirradiated USE values for materials that originally did not

have documented unirradiated Charpy USE values. Using these statistically derived Charpy

USE values, the BWROG predicted the end-of-license (40 years of operation) USE values in

accordance with RG 1.99, Revision 2. According to this RG, the decrease in USE is

dependent upon the amount of copper in the material and the neutron fluence at the 1/4T

depth predicted for the material. The BWROG analysis determined through an equivalent

4-7
margins analysis (EMA) methodology that the minimum allowable Charpy USE value in the

transverse direction for base metal and along the weld for weld material was 35 ft-lb.

General Electric updated the projected USE values for BWR RPV materials out to 54 EFPY in

Electric Power Research Institute (EPRI) report TR-1 13596, UBWR Vessel and Internals

Project BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines," BWRVIP74, September 1999. The staff's review and approval of EPRI TR-1 13596 is documented in a

letter from Mr. C.I. Grimes to Mr. C. Terry dated October 18, 2001. The analysis in EPRI TR113596 determined the reduction in the unirradiated Charpy USE resulting from neutron

irradiation using the methodology in RG 1.99, Revision 2. Using this methodology, and a

correction factor of 65 percent for conversion of the longitudinal properties to transverse

properties, the lowest Charpy USE value for all BWR/3-6 plates was projected to be 45 ft-lb.

The correction factor for specimen orientation in plates is based on NRC Branch Technical

Position MTEB 5-2. Using the RG methodology, the lowest Charpy USE value for BWR nonLinde 80 submerged arc welds was projected to be 43 ft-lb. According to EPRI TR-1 13596,

the percent reductions in Charpy USE for the limiting BWR/3-6 beltline plates and BWR nonLinde 80 submerged arc welds are 23.5 percent and 39 percent, respectively.

Since the analysis in EPRI TR-1 13596 is a generic analysis, the applicant submitted plantspecific information in LRA Tables 4.2.1-1 through 4.2.1-4 for Dresden Units 2 and 3, and in

LRA Tables 4.2.1-5 through 4.2.1-8 for Quad Cities Units 1 and 2, to demonstrate that the

beltline materials of the D/QCNPS RPVs meet the criteria in the EPRI report at the end of the

license renewal period. The tables include the information as specified in Tables B-4 and B-5

of EPRI TR-113596. In request for additional information (RAI) 4.2.1 (a), the staff noted the

applicant's statement that it has performed one bounding 54-EFPY fluence calculation for

Dresden and one for Quad Cities and then determined the corresponding 54-EFPY 1/4T

fluence. Therefore, it was expected that the applicant used the same 54-EFPY 1/4T fluence

for limiting beltline plate and weld material at both Dresden units. However, the data

presented in Tables 4.2.1-1 through 4.2.1-4 indicate that the applicant used two different

values for the limiting beltline materials for Dresden-a fluence value of 3.9 x 1017 n/cm2 for

the limiting plate and weld at Unit 2 and for the limiting plate at Unit 3, and a value of 2.9 x 1017

n/cm2 for the limiting weld at Unit 3. A similar apparent discrepancy was present in LRA

Tables 4.2.1-5 through 4.2.1-8 for Quad Cities. In addition to this discrepancy, there appeared

to be another discrepancy between the peak fluence data for Quad Cities in LRA Sections

4.2.1 and 4.2.2. Tables 4.2.1-5 through 4.2.1-7 of the LRA for Quad Cities list 2.9 x 1017 n/cm2

as the 54-EFPY 1/4T fluence, whereas LRA Table 4.2.2-2 for Quad Cities lists 3.9 x 1017 n/cm2

as the 54-EFPY 1/4T fluence. A similar discrepancy existed between LRA Sections 4.2.1 and

4.2.2 for the 1/4T fluence data for Dresden. In RAI 4.2.1 (a), the staff requested the applicant

to explain these apparent discrepancies in the peak fluence data and provide revised tables as

appropriate.

In response to RAI 4.2.1 (a) in a letter dated October 3, 2003, the applicant explained that the

statement about the bounding 54-EFPY fluence calculation in LRA Section 4.2.1 meant that

one neutron transport (flux) calculation was prepared that bounds both Dresden and Quad

Cities. However, based upon the different operating bases for the four units with regard to the

time period of operation at two different power levels, one before the extended power uprate

(EPU) and one after EPU, a unit-specific fluence was calculated for each of the four units.

From these calculations, it can be seen that, using the bounding flux with the plant-specific

pre-EPU and EPU periods of operation, the peak RPV fluence at 54 EFPY is the same (5.7 x

4-8
1017 n/cm2 at the RPV inside surface and 3.9 x 1017 n/cm2 at the i/4T) for all four units, when

rounding is applied. The staff has reviewed these values and found them acceptable.

The peak EPU fluence on the vessel is located at approximately 82 inches above the bottom of

active fuel and is applied to the l6wer-intermediate shell and axial welds. Additionally, axial flux

distribution factors are applied to different elevations (by shell) in the bettline region. For the

lower shell, the peak fluence is adjusted by the axial flux distribution factor based on an

elevation approximately 42 inches above the bottom of active fuel, which represents the lower

to lower-intermediate girth weld. The axial flux distribution factor for this location is 0.71. The

applicant stated that it applied this factor for calculating the peak pre-EPU fluence for the lower

to lower-intermediate shell girth weld and all lower shell materials. In a followup question to

RAI 4.2.1 (a), the staff requested the applicant to describe how the pre-EPU axial flux profile

compares with the EPU axial flux profile. The staff also requested that the applicant submit

information about how the axial flux distribution factor was used in calculating the peak-EPU

fluence for the lower to lower-intermediate shell girth weld and all lower shell materials. This

was identified as Confirmatory Item 4.2.1 (a).

In a letter dated April 9, 2004, the applicant referred to Figure 2 in a letter from Exelon to

NRC, "Additional Information Regarding Request for License Amendment for PressureTemperature Limits," dated July 31, 2003. This figure shows the pre-EPU and EPU axial flux

distribution at the inside surface of the reactor pressure vessel. The pre-EPU and EPU axial

flux distribution profiles are different, since the pre-EPU flux peaks at an elevation higher than

the mid-plane, whereas the EPU flux peaks at the mid-plane. The applicant stated that for

determining the peak 54-EFPY surface fluences at the lower shell plate material, lower shell

welds and the lower to lower-intermediate shell girth weld, the axial flux distribution factor of

0.71 is applied for pre-EPU and 0.74 is applied for EPU conditions. The staff has

independently verified the axial flux distribution factors using the data presented in the figure

mentioned above and also verified the peak surface fluences for the lower shell and

associated welds as calculated by the applicant. The staff finds the response acceptable

because the applicant has used appropriate axial flux distribution factors for calculating the

peak 54-EFPY surface fluence for the lower to lower-intermediate shell girth weld and all lower

shell materials when determining the limiting materials. Therefore, Confirmatory Item 4.2.1 (a)

is closed.

In response to RAI 4.2.1 (a), the applicant also provided the following explanation for the

apparent discrepancies in the 54-EFPY fluence data for calculating the limiting beltline

materials USE values presented in LRA Tables 4.2.1-1 through 4.2.1-8. In calculating the

USE percent decrease for the limiting beltline material (plate or weld) of each unit, a

combination of the applied fluence and the percentage of copper of each material is

considered. Both the limiting plate and limiting weld materials for Dresden Unit 2 are in the

lower-intermediate shell, thereby using the same fluence. The limiting plate material for

Dresden Unit 3 also occurs in the lower-intermediate shell, thereby using the same fluence as

that used for the Dresden 2 materials. However, the Dresden 3 limiting weld material with

respect to the limiting USE percent decrease occurs in 'the lower to lower-intermediate girth

weld because of the higher copper content, which offsets the higher fluence and lower copper

content of the weld materials in the other shells. The Dresden Unit 3 lower to lowerintermediate girth weld sees a different (and lower) fluence than the lower-intermediate shell

materials.

4-9
For Quad Cities Unit 1, the limiting plate and limiting weld materials with respect to 54-EFPY

USE values occur in the lower shell, where the fluence is lower. In Quad Cities Unit 2, the

limiting plate material is in the unit's lower shell, while the limiting weld material occurs in the

lower-intermediate shell where the fluence is higher. The staff has independently verified the

percentage of copper contents given in LRA Tables 4.2.1-1 to 4.2.1-8 for the limiting beltline

USE materials with the corresponding data in the NRC Reactor Vessel Integrity Database

(RVID). The staff accepts this explanation for the differences in the 54-EFPY fluence data for

limiting beltline materials USE values because these values are determined by the different

combinations of copper content and applied fluence for different beltline materials at

D/QCNPS.

In further responding to RAI 4.2.1 (a), the applicant provided the following explanation for the

differences between the peak fluence data presented in LRA Sections 4.2.1 and 4.2.2 for

Dresden and Quad Cities. The values presented in LRA Tables 4.2.2-1 and 4.2.2-2 represent

the peak RPV fluence, both at the surface and at the 1/4T locations. As noted above, an axial

flux distribution factor is applied to the lower shell, thereby reducing the fluence (both surface

and 1/4T) for the associated materials. The values for delta RTNOT and ART provided in these

tables represent the limiting materials based upon the fluence values presented. The staff

finds the applicant's explanation for the differences in fluence values acceptable because the

fluences presented in Section 4.2.1 are for the limiting beltline material USE values, whereas

those presented in Section 4.2.2 are for the limiting beltline material delta RTNDT and ART

values.

The data for copper content in the limiting beltline plate and limiting beltline weld material

presented in LRA Section 4.2.1 appear to be different from the data presented in Appendix F

to the Dresden UFSAR. For example, LRA Table 4.2.1-2 lists 0.24 percent copper for the

Dresden Unit 2 limiting beltline weld material, whereas Table 22 in Appendix F lists a maximum

copper content of 0.21 percent for Dresden Unit 2. In RAI 4.2.1 (b), the staff requested the

applicant to resolve this apparent discrepancy. This was identified as Confirmatory Item 4.2.1.

In response to RAI 4.2.1 (b), in a letter dated October 3, 2003, the applicant provided the

following explanation:

For the beltline region, Table 21 (Shell Course 57-Lower Shell) and Table 22 (Shell Course

58-Lower-Intermediate Shell) of the Dresden FSAR gives values actual chemical analysis of

these materials. Tables 21 and 22 contain the chemical analysis for electroslag welds contained in

the original FSAR. Since the original publication of the FSAR, the accepted best estimate

chemistry for Electroslag Weld (ESW) materials used in B&W vessels accepted by the NRC staff

is 0.24% Cu and 0.37% Ni. These values are reported in BAW-2258, 'Evaluation of RTNDT, USE

and Chemical Composition of Core Region Electroslag Welds for Dresden Units 2 and 3,"

Framatome Technologies, January 1996, and were previously accepted by the NRC in its review

of pressure temperature (P-T) limit curve report GE-NE-Bl3-02057-04R1a. Exelon submitted

reactor vessel chemistry values to the NRC in July 1998 in response to Generic Letter 92-01,

Supplement 1. The information provided in that response is included in NRC database RVID.

The staff accepts the applicant's response because, as mentioned above, the staff has verified

the percentage of copper content given in LRA Tables 4.2.1-1 to 4.2.1-8 for the limiting beltline

USE materials with the corresponding data in RVID. Therefore, Confirmatory Item 4.2.1 is

closed.

4-10
In RAI 4.2.1 (c), the staff requested the applicant to provide all fluence data for all welds and

plates in the beltline and specify which one is bounding with respect to the RPV USE

evaluation. In response to RAI 4.2.1 (c), in a letter dated October 3, 2003, the applicant

provided 54-EFPY surface fluences and 54 EFPY 1/4T fluences for all the beltline material but

identified materials that are bounding with respect to the RPV material ART values at 54-

EFPY. The applicant also needed to identify the USE for all beltline materials at 54-EFPYs

and to identify the limiting materials for each unit. This was identified as Open Item 4.2.1 (c).

Information was provided by the applicant in a letter dated April 9, 2004. The staff has

reviewed this information and confirmed the limiting beltline materials for each unit. The staff

also confirmed the USE for all four units and has reviewed the analysis for the material with

the lowest Charpy USE, as described below.

The applicant's April 9, 2004, letter indicated that all beltline materials, except for the ESWs in

Quad Cities Unit 2, will have predicted Charpy USE greater than 35 ft-lb, the minimum

allowable USE based on the generic BWR equivalent margins analysis documented in

BWROG topical report entitled, " 10 CFR Part 50 Appendix G Equivalent Margin Analysis for

Low Upper Shelf Energy in BWR/2 Through BWR-6 Vessels." Therefore, all beltline materials,

except for the ESW in Quad Cities Unit 2, meet the margins of safety against fracture

equivalent to those required by Appendix G of Section Xl of the ASME Code.

The applicant reevaluated the USE value for Quad Cities Unit 2 ESW using all electroslag weld

material surveillance test results from Quad Cities Unit 2, and performed a plant-specific EMA

for the Quad Cities Unit 2 ESW. General Electric report GE-NE-0000-0027-0575-01, Revision

0, 'The Upper Shelf Energy Evaluation for RPV Electroslag Welds at Quad Cities Unit 2,"-

issued March 5, 2004, and included in the applicant's April 9, 2004 letter, contains this

analysis. Using the limiting surveillance capsule 18 data and the methodology in RG 1.99,

Revision 2, the predicted Charpy USE for the ESWs welds is 34.2 ft-lb, which is below the

minimum established in the generic BWROG topical report. The applicant's plant-specific

EMA was performed using methods and criteria contained in RG 1.161, 'Evaluation of Reactor

Pressure Vessels with-Charpy Upper-Shelf Energy less than 50 Ft-Lb." and Appendix K of

ASME Code, Section Xl. Appendix K and RG 1.161 provide acceptance criteria and

evaluation procedures for determining acceptability for operation of a reactor vessel when the

vessel metal temperature is in the upper shelf range. The methodology is based on the

principles of elastic-plastic fracture mechanics. Flaws will be postulated in the reactor vessel

at locations of predicted low upper shelf Charpy impact energy, and the applied J-integral for

these flaws will be calculated and compared with the J-integral fracture resistance of the

material to determine acceptability. The applicant's analysis showed that the applied J-integral

of the postulated flaws and the J-integral material fracture resistance with a minimum USE of

32.4 ft-lb satisfies the criteria of Appendix K of the ASME Code, Section Xl and RG 1.161.

The analysis methods in Appendix K of the ASME Code initially followed the methodology in

RG 1.161. The analysis methods in Appendix K of the ASME Code, Section Xl were changed

in the 1995 Addenda to the 1995 Edition. The analysis method in the 1995 Addenda to the

1995 Edition of the ASME Code changed the method of calculating the contribution to the

applied J-integral because of a radial thermal gradient. -This change was incorporated into the

ASME Code to more accurately represent the contribution to the applied J-integral due to a

radial thermal gradient. The applicant's analysis was performed using the earlier analysis

method, i.e., the methods contained in RG 1.161. The staff confirmed the EMA using the

analysis methods in both Appendix K to the ASME Code, Section Xl, 1995 Addenda to the

4-11
1995 Edition, and the earlier analysis method in RG 1.161. This analysis included the effects

of the extended power uprate condition. Since the limiting end of extended life USE for Quad

Cities Unit 2 ESW exceeds the minimum value of 32.4 ft-lb demonstrated in the applicant's

plant-specific EMA, the staff concludes that all beltline materials, including the ESW in Quad

Cities Unit 2 RPV meet the margins of safety against fracture equivalent to those required by

Appendix G of Section Xl of the ASME Code. Therefore Open Item 4.2.1(c) is closed.

4.2.2.2 Adjusted Reference Temperature for Reactor Vessel Materials Due to Neutron

Embrittlement

The applicant calculated the 54-EFPY fluences for the Dresden and Quad Cities reactor

vessels using the methodology of NEDC-32983P. Because this methodology is approved by

the NRC, the calculated 54-EFPY fluences are acceptable. The applicant provided the results

for one bounding calculation and determined the peak surface fluence of 5.7 x 1017 n/cm2 and

peak 1/4T fluence of 3.9 x 1017 n/cm2 for all four D/QCNPS vessels. Using the calculated peak

1/4T fluence, the applicant determined the 54-EFPY delta RTNDT and ART values for all the

beltline materials according to RG 1.99, Revision 2. From all the 54-EFPY ART values, the

applicant identified the limiting ART value and listed it in LRA Tables 4.2.2-1 and 4.2.2-2 as the

54-EFPY ART for both Dresden and Quad Cities. These limiting ART values are for axial

welds. In RAI 4.2.2(a), the staff requested the applicant to explain how it determined that the

weld in which it calculated the neutron fluence bounds all the other welds in Dresden/Quad

Cities. In response to RAI 4.2.2(a), the applicant provided the same explanation for

determining peak fluence that it had provided in response to RAI 4.2.1 (a). The staff finds the

applicant's response acceptable because it has checked the applicant's calculations for peak

fluence and found them accurate.

In further responding to RAI 4.2.2(a), the applicant presented data for 54 EFPY 1/4T peak

fluence and 54 EFPY ART for all beltline welds in Dresden and Quad Cities. The ESW in the

lower-intermediate shell is a bounding weld material, one with the highest 54 EFPY ART, for

each of the four Dresden and Quad Cities units. The staff has independently verified the

identification of the bounding beltline material and its 54 EFPY ART at the 1/4 T location. The

staff accepts the applicant's response because the staff has verified it using the peak fluence

data provided by the applicant and the percentage of copper and nickel contents, initial RTNDT,

and margin data provided in the RVID. The applicant noted that the ART for the Dresden Unit

3 ESW material is 0.4 OF less than that for the girth weld (lower to lower-intermediate weld)

material. However, using ASME Code Case N-588, which allows a different application of K,

for girth weld materials, the limiting material for Dresden Unit 3 is the ESW material, which is

explained in more detail in the response to RAI 4.2.2 (c).

In RAI 4.2.2(b), the staff requested the applicant to submit the 54-EFPY delta RTNDT and ART

values along with initial RTNDT for all the beltline materials of the four D/QCNPS reactor

vessels. In response to RAI 4.2.2(b), in a letter dated October 3, 2003, the applicant provided

the requested information in a table form for each of the four Dresden and Quad Cities units.

The staff finds the response acceptable because the information submitted by the applicant

(percentage of copper and nickel, initial RTNDT, and margin term) is consistent with the data

presented in the RVID and confirms the limiting materials.

The applicant stated that because of the refinement in the approved methodology used to

calculate the 54-EFPY fluence, the material with the limiting ART is the axial weld, with the

4-12 I
exception of Dresden Unit 3, where'the axial weld and girth weld ART values are identical.

The applicant invoked ASME Code Case N-588 for Dresden Unit 3 which causes the axial

weld to become the limiting material. In RAI 4.2.2(c), the staff requested the applicant to

identify the refinement mentioned here and explain how this makes the axial weld a material

having the limiting ART. The staff also requested the applicant to explain how the use of

ASME Code Case N-588 makes the axial weld the limiting material for Dresden Unit 3.

In response to RAI 4.2.2(c), in a letter dated October 3, 2003, the applicant stated that as can

be seen in the ART tables submitted in response to RAI 4.2.2(b), the ART for the Dresden Unit

3 girth weld material is 104.16 0F and the ART for the axial ESW material is 103.80F. The

detailed explanation and calculated basis for the use of the ESW material as the limiting

material is provided in GE-NE-0000-0002-9600-Ola, Revision 0, and is explained in the GE

Report. Because the calculated value of KIm is reduced for a girth weld because of the

implementation of ASME Code Case N-588 (circumferentially oriented defect for a

circumferential weld), the axial weld bounds the P-T curve beltline region requirements. The

applicant also submitted the stress intensity calculations for both axial and girth welds at 54

EFPYs to demonstrate that by using ASME Code Case N-588 the axial weld has the most

limiting temperature for the P-T curves in the beltline region. The results of the axial and girth

weld calculations show that for a pressure of 1105 psig at 54 EFPYs, the allowable

temperature (T) value for the axial weld (146.5 OF) bounds the value for the girth weld (51 OF).

The staff finds the response acceptable because the applicant has invoked ASME Code Case

N-588, which has been approved by the staff as documented in the safety evaluations dated

February 4,'2000 (ML003680441) for Quad Cities and August 25, 2000, (ML003745769) for

Dresden.

4.2.2.3 Reflood Therrnal Shock Analysis of the Reactor Vessel

The applicant stated that the original D/QCNPS reflood thermal shock analysis has been

superseded by an analysis for BWR-6 vessels that is applicable to the D/QCNPS BWR-3

reactor vessels. In RAI 4.2.3(a), the staff requested the applicant to explain why the BWR-6

analysis is applicable to the BWR-3 reactor vessel at D/QCNPS. In response to RAI 4.2.3(a),

in a letter dated October 3, 2003, the applicant stated that the BWR-6 evaluation determined

the maximum stress intensity in the vessel wall as a function of vessel wall thickness and time

after a design- basis LOCA. As shown in Figure G2214-1 of Appendix G to the ASME Code,

Section Xl, 1998 Edition through 2000 Addenda,' the stress intensity is a function of vessel wall

thickness. The original analysis used a recirculation line break, while the BWR-6 analysis was

based on a main steam line break event, which is considered to bound the recirculation line

break. In addition, the analysis used a vessel thickness similar to Dresden and Quad Cities

vessels. Therefore, the BWR-6 analysis is applicable to the Dresden and Quad Cities reactor

vessels. The staff finds the applicant's explanation for applicability of an analysis for BWR-6

vessels to the D/QCNPS reactor vessels to be acceptable because the analysis for BWR-6

vessels bounds the recirculation line break event and it uses a vessel wall thickness similar to

BWR-3 vessels.

The revised analysis assumes end-of-life material toughness, which in tum depends on endof-life ART. The critical location for fracture mechanics analysis is at the 1/4T location. For

the reflood thermal shock analysis of the reactor vessel, the peak stress intensity occurs at

approximate 300 seconds after the LOCA. At that time, the temperature at 1/4T is

approximately 204 °C (400 °F), which is much higher than the 54-EFPY ART 40 °C (104 OF)

4-13
for the limiting material of the D/QCNPS vessels. Therefore, the staff concurs with the

applicant that the revised thermal shock analysis of the D/QCNPS vessels is valid for the

period of extended operation.

4.2.2.4 Reflood Thermal Shock Analysis of the Reactor Vessel Core Shroud and Repair

Hardware

In the thermal shock analysis of D/QCNPS reactor vessel core shrouds, the applicant

considered the location on the inside surface of the core shroud opposite to the midpoint of the

fuel centerline as a location most susceptible to damage during an LPCI thermal shock

transient because it receives the maximum irradiation. The 54-EFPY fluence at this location is

5.85 x 1020 n/cm2 (greater than 1 MeV). This fluence is calculated using the methodology of

NEDC-32983P, which was approved by the NRC. In RAI 4.2.3(b), the staff requested the

applicant to confirm whether the effect of extended power uprates, which is incorporated at

D/QCNPS, is accounted for in the calculation of the 54-EFPY fluence.

In response to RAI 4.2.3(b), in a letter dated October 3, 2003, the applicant confirmed that the

fluence used to determine the 54-EFPY shroud fluence was calculated using extended power

uprate conditions. The staff finds the response acceptable because the calculations for the

54-EFPY shroud fluence take into account the effect of extended power uprates that are

implemented at D/QCNPS.

The applicant calculated the maximum thermal shock stress and the corresponding thermal

strain at the location on the inside surface of the shroud receiving the maximum irradiation.

The staff questioned the validity of this analysis. The reflood thermal shock would produce

high tensile stresses on the outside surface of the core shroud, and these stresses would

penetrate only to a small depth into the shroud wall. Thus, it appears that the outside surface

of the core shroud could be the location most susceptible to damage during an LPCI thermal

shock transient. In RAI 4.2.4-a, the staff requested the applicant to respond to the following

three items:

(1) Provide an evaluation of strain at the outside surface of the core shroud, exposed to 54-

EFPY fluence, during an LPCI thermal shock transient.

(2) What is the impact of strain rate associated with the LPCI thermal shock transient on the

measured and calculated strains in the core shroud?

(3) The applicant compared the calculated strain range with the measured values of percent

reduction in area for annealed Type 304 stainless steel irradiated to 1 x 1021 n/cm2 (E>1

MeV) and indicated that the analysis results represent a considerable margin of safety.

Provide the bases for concluding that the calculated strains at both the inside and outside

surfaces of the shroud should be compared with the measured value of percent uniform

strain for annealed Type 304 stainless steel irradiated to 1 x 1021 n/cm2 (greater than 1

MeV).

In response to RAI 4.2.4-a(1), in a letter dated October 3, 2003, the applicant submitted the

calculation of the thermal shock strain for the LPCI transient described in the original analysis.

That analysis is based on a linear elastic thermal stress analysis and assumes that a lowpressure coolant of 49 IC (120 0F) is injected on a shroud at a temperature of 282 OC (540 OF).

4-14
The calculated thermal shock strain is 0.55 percent at the outside surface. However, the

effects of the thermal shock transient are very localized, and the majority of the material is at

the higher temperature where the ductility is sufficient to accommodate the thermal shock

strain and prevent brittle fracture. The staff finds the response acceptable because the

localized therrmanl shock strain at the outside surface of the core shroud would be

accommodated by the surrounding material at the higher temperature, thus preventing brittle

fracture. This is further discussed in the next paragraph.

In respronse'to RAI 4.2.4-a(2), in a letter dated October 3, 2003, the applicant stated that the

thermal strains in the core shroud are calculated based on a linear elastic thermal stress

analysis, which is a bounding calculation. The heat transfer coefficient is assumed to be -

infinite (making the calculation independent of strain rate), and therefore the outside surface of

the shroud is considered to be at the fluid temperature 49 'C (120 'F). The applicant also

stated that at the fluence levels experienced by the shroud, the material will continue to exhibit

ductile behavior. As discussed above, the effect of the thermal shock transient is very

localized, and the majority of the material is at the higher temperature where the ductility is

sufficient to prevent brittle fracture. Even assuming the strain rate has a significant effect, the

increased strain rate is still not sufficient to result in brittle fracture. The effect of strain rate

during the LPCI thermal shock event can be accounted for by assuming that the material yield

strength is increased (an effect also produced by increased fluence). At fluence levels up to 1

X1021 n/cm2 (which would represent the increased yield strength),-Type 304 stainless steel

exhibits sufficient ductility to preclude brittle fracture. The staff accepts the applicant's

assertion that Type 304 stainless has sufficient ductility at fluence levels up to 1 X1 021 n/cm2

because it is consistent with the data presented in a report by Mr. J.N. Kass, 'Effect of Neutron

Irradiation at 288 0C (5500F) on Reactor Component Materials for BWR-6," NEDO-20243,-

74NED2, 1974. Kass reports that at a temperature of 288 0C and neutron fluence of 1x102'

n/cm2 (>1 MeV), Type 304 stainless steel experiences a 32 percent reduction in area. The staff

accepts the applicant's response because the core shroud will have sufficient ductility during

the LPCI transient during the extended period of operation to preclude brittle failure.

In response to RAI 4.2.4-a(3), in a letter dated October 3, 2003, the applicant stated that the

strain associated with the reflood thermal shock event is very localized and is constrained by

the surrounding bulk material. As such, it is similar to the triaxial stress condition present in

the neck region (where the area reduction is taking place) during a tensile test. The percent

reduction in area is a measure of this triaxial stress state and, as such, is the most appropriate

property for evaluating the effect of thermal shock on the shroud. Therefore, a comparison

with uniform elongation is not appropriate in this case. At lower values of temperature or

neutron fluence, the percent reduction in area is generally higher. The staff accepts the

applicant's reasoning that the strain associated with the reflood thermal shock event is very

localized and, therefore, reduction in area is the most appropriate property for evaluating the

effect of thermal shock on the shroud.

4.2.2.5 Reactor Vessel Thermal LimitAnalyses-Operating Pressure-Temperature Limits

The applicant plans to calculate vessel P-T limit curves for 60 years (54 EFPYs) using an

approved fluence methodology for D/QCNPS and submit them to the NRC for approval before

the start of the extended period of operation. The applicant will place the approved P-T limit

curves in the D/QCNPS technical specifications. The applicant plans to use ASME Code

Cases N-640 and N-588 (Dresden Unit 3 only) which have been approved by the staff as

4-15
I

documented in safety evaluations dated February 4, 2000 (ML003680441) for Quad Cities and

August 25, 2000 (ML003745769) for Dresden. ASME Code Case N-640 allows the use of

reference fracture toughness K10, as found in Appendix A to ASME Code Section Xl, in lieu of

reference fracture toughness Kia, as found in Figure G-2210-1 in Appendix G to ASME Code,

Section Xl for the development of P-T limit curves. Reference fracture toughness Kic is based

on the lower bound of static crack-initiation critical (reference) values of K, measured as a

function of temperature. As found in Appendix G, Kia is based on the lower bound of static,

dynamic, and crack arrest critical values of K, measured as a function of temperature. As

mentioned above, the use of ASME Code Case N-588 for Dresden Unit 3 causes axial weld of

the reactor vessel to become the limiting material. The applicant stated that it will manage the

P-T limits using approved fluence calculations when there are changes in the power of core

design in conjunction with surveillance capsule results from the BWRVIP integrated

surveillance program. The staff finds the applicant's plan to manage the P-T limits acceptable

because the change in P-T curves will be implemented by the license amendment process

(i.e., modifications of technical specifications) and will meet the requirements of 10 CFR 50.60

and Appendix G of 10 CFR Part 50.

4.2.2.6 Reactor Vessel Circumferential Weld Examination Relief

Section 4.2.6 and Appendix A.3.1.6 to the LRA discuss inspection of the D/QCNPS RPV

circumferential welds. These sections of the LRA indicate that the applicant will use an

approved technical alternative in lieu of ultrasonic testing (UT) of RPV circumferential shell

welds. The technical alternative is discussed in the staff's final SER of the BWRVIP-05 report,

which is enclosed in a July 28, 1998, letter to Mr. C. Terry, the BWRVIP Chairman. In this

letter, the staff concluded that since the failure frequency for circumferential welds in BWR

plants is significantly below the criterion specified in RG 1.154, uFormat and Content of PlantSpecific Pressurized Thermal Shock Safety Analysis Reports for Pressurized Water Reactors,"

and below the core damage frequency (CDF) of any BWR plant, the continued inspection

would result in a negligible decrease in an already acceptably low value, and, therefore,

elimination of the inservice inspection (ISI) for RPV circumferential welds is justified. The

staff's letter indicated that BWR applicants may request relief from inservice inspection

requirements of 10 CFR 50.55a(g) for volumetric examination of circumferential RPV welds by

demonstrating that (1) at the expiration of the license, the circumferential welds satisfy the

limiting conditional failure probability for circumferential welds in the evaluation, and (2) the

applicants have implemented operator training and established procedures that limit the

frequency of cold over-pressure events to the frequency specified in the report. The letter

indicated that the requirements for inspection of circumferential RPV welds during an

additional 20-year license renewal period would be reassessed, on a plant-specific basis, as

part of any BWR LRA. Therefore, the applicant must request relief from inspection of

circumferential welds during the license renewal period per 10 CFR 50.55a.

Section A.4.5 of the BWRVIP-74 report indicates that the staff's SER of the BWRVIP-05 report

conservatively evaluated the BWR RPVs to 64 EFPYs, which is 10 EFPYs greater than what is

realistically expected for the end of the license renewal period. The NRC staff used the mean

RTNDT value for materials to evaluate failure probability of BWR circumferential welds at 32 and

64 EFPYs in the staff SER dated July 28, 1998. The mean RTNDT value is defined as the sum

of the initial (unirradiated) reference temperature (initial RTNDT) and the mean value of the

adjustment in reference temperature caused by irradiation (delta RTNDT); it does not include a

4-16
margin (m). The neutron fluence used in this evaluation was the neutron fluence at the cladweld (inner) interface.

Since the staff analysis discussed in the BWRVIP-74 report is a generic analysis, the applicant

submitted plant-specific information to demonstrate that the Dresden beltline materials meet

the criteria specified in the report. To demonstrate that the Dresden vessels have not become

embrittled beyond the basis for the technical alternative, the applicant, in LRA Table 4.2.6-1,

supplied a comparison of 54-EFPY material data of the limiting Dresden circumferential welds

with that of the 64-EFPY reference case in Appendix E to the staff's SER of the BWRVIP-05

report. The Dresden material data include the amounts of copper and nickel, chemistry factor,

neutron fluence, delta RTNDT, initial RTNDT, and mean RTNDT of the limiting circumferential weld

at the end of the renewal period. The staff has verified the data for the amounts of copper and

nickel contents and the initial RTNDT values for Dresden Unit 2 and 3 beltline materials by

comparing them with the corresponding data in the RVID. The 54-EFPY mean RTNDT values

for Dresden Units 2 and 3 are 54 0F and 53 'F, respectively. The staff has checked the

applicant's calculations for the 54-EFPY mean RTNDT values for the Dresden circumferential

welds using the data presented in LRA Table 4.2.6-1 and found them to be accurate. These

54-EFPY mean RTNDT values for Dresden Units 2 and 3 are bounded by the 64-EFPY mean

RTNDT value of 129.40F used by the NRC for determining the conditional failure probability of a

circumferential girth weld. The 64-EFPY mean RTNDT value from the staff SER dated July 28,

1998, is for a B&W weld because B&W welded the girth welds in the Dresden vessels. Since

the Dresden 54-EFPY mean RTNDT values are less than the 64-EFPY value from the staff SER

dated July 28, 1998, the staff concludes that the Dresden RPV conditional failure probabilities

are bounded by the NRC analysis.

The applicant stated that the procedures and training used to limit cold over-pressure events

will be the same as those approved by the NRC when Dresden requested to use the BWRVIP05 technical alternative for the current term, but it did not explicitly cite a document that

supports this statement. In RAI 4.2.6, the staff requested the applicant to provide specific

reference(s) in the LRA and the UFSAR Supplement that include the applicant's request to use

the BWRVIP-05 technical alternative for the current license term and the NRC approval of that

request. In response to RAI 4.2.6, in a letter dated October 3, 2003, the applicant stated that

the procedure and training requirements identified in the Dresden request to use the BWRVIP05, technical alternative were identified in "Dresden Letter JMHLTR 99-0078 from J. M. Heffley

(Commonwealth Edison (ComEd)) to NRC, 'Relief Request for Alternative Weld Examination

of Circumferential Reactor Pressure Vessel Shell Welds,'" dated July 26, 1999, attached to

Dresden ISI Relief Request No. CR-18. The NRC approval of this relief request and

associated procedure and training requirements was provided in the document, "Safety

Evaluation by the Office of Nuclear Reactor Regulation Related to Alternative to Inspection of

Reactor Pressure Vessel Circumferential Welds, Dresden Power Station, Units 2 and 3,"

attached to the NRC letter from Mr. A.J. Mendiola to Mr/ O.D. Kingsley (ComEd), Dresden,

"Authorization for Proposed Alternative Reactor Pressure Vessel Circumferential Weld

Examinations," (Task Action Commitment Nos. MA6228 and MA6229), dated February 25,

2000. The applicant further stated that LRA Section 4.2.6 and associated UFSAR Supplement

Section A.3.1.6, Reactor Vessel Circumferential Weld Examination Relief, should have

referenced the request letter identified above. By letter dated March 5, 2004, the applicant

provided revisions to the UFSAR Supplements A.3.1.6 for Dresden and Quad Cities which

clarified that the application for relief was extended to the period of extended operation. The

staff finds the response acceptable because the applicant identified the requested references.

4-17
-

With respect to Quad Cities, the applicant submitted its request for relief from the

circumferential welds examination requirements for the remainder of the 40-year licensed

operating period by letter dated May 16, 2003. This relief was approved by the NRC staff by

SER dated April 29, 2004. However, the applicant did not provide an evaluation of the basis

for extending this relief through the end of the period of extended operation, as was done for

Dresden. The applicant submitted an extension of the relief request for all four units through

the period of extended operation. The staff will review the basis for extending this relief

through the end of the period of extended operation for all four units as the staff completes its

review of the applicant's February 23, 2004 submittal.

The staff finds that the applicant's evaluation for this TLAA is acceptable because the Dresden

54-EFPY conditional failure probabilities for the RPV circumferential welds are bounded by the

NRC analysis in the staff SER dated July 28, 1998, and Dresden will be using procedures and

training to limit cold over-pressure events during the period of extended operation. This

analysis satisfies the evaluation requirements of the staff SER dated July 28, 1998. The

applicant has provided this request for relief for the extended period of operation by letter

dated February 23, 2004 for Dresden and Quad Cities and will be reviewed by the staff in

accordance with 10 CFR 50.55a. The staff finds the UFSAR Supplement (LRA Appendix

A.3.1.6) for Dresden and Quad Cities acceptable because it includes the necessary

information regarding the evaluation of this TLAA.

4.2.2.7 Reactor Vessel Axial Weld Failure Probability

In its July 28, 1998, letter to Mr. C. Terry, the BWRVIP Chairman, the staff identified a concern

about the failure frequency of axially oriented welds in BWR RPVs. In response to this

concem, the BWRVIP supplied evaluations of axial weld failure frequency in letters dated

December 15, 1998, and November 12, 1999. The staff's SER on these analyses is enclosed

in a March 7, 2000, letter to Mr. C. Terry. The SER indicates that the RPV failure frequency

because of failure of the limiting axial welds in the BWR fleet at the end of 40 years of

operation is below 5 x 10i6per reactor year, given the assumptions about flaw density,

distribution, and location described in this SER. Because the results apply only for the initial

40-year license period of BWR plants, applicants for license renewal must submit plantspecific information applicable to 60 years of operation.

The BWRVIP identified the Clinton and Pilgrim reactor vessels as the reactor vessels with the

highest mean RTNDT in the BWR fleet. The mean RTNDT values were determined using the

neutron fluence at the clad/weld interface and did not include a margin term. The staff

confirmed this conclusion about the highest mean RTNDT in the SER enclosed in the March 7,

2000, letter by comparing the information in the BWRVIP analysis and the information in the

RVID for all BWR RPV axial welds. The results of the staff and BWRVIP calculations are

presented in Table 4.2-1. The staff calculations used the basic input information for Pilgrim,

with three different assumptions for the initial RTNDT. The calculations of the actual Pilgrim

condition used the docketed initial RTNDT of -44 "C (-47 'F) and a mean RTNDT of 20 "C (68 0F).

A second calculation, listed as "Mod 1" in Table 4.2-1, uses an initial RTNDT of -18 IC (0 0F) and

a mean RTNDT of 47 0C (116 OF) consistent with the BWRVIP calculations. A third calculation,

with an initial RTNDT of -19 0C (-2 OF) and a mean RTNDT of 46 'C (114 IF), was chosen to

identify the mean value of RTNDT required to provide a result which closely matches the RPV

failure frequency of 5 x 1 0-6per reactor year. The vessel failure frequency is the product of

conditional failure probability, or P(F/E), and the low-temperature over pressurization (LTOP)

4-18
event frequency. The LTOP frequency is the frequency of the transient occurring, determined

as 10-3 per reactor year in the evaluation. Since Pilgrim was not identified within the RVID as

one of the limiting plants, the SER states that the axial welds for the Clinton reactor vessel are

the limiting welds for the BWR fleet, and vessel failure probability determined for Clinton

should bound those for the BWR fleet.

Table 4.2-1. Comparison of Results from Staff and BWRVIP Calculations

Initial Mean

RTNDT RTNDT

Plant (OF)' (T) Vessel Failure Freq.

._. _Staff BWRVIP

Clinton -30 91 2.73E-6 1.52E-6

Pilgrim -48 68 2.24E-7

Mod 1 0 116 5.51 E-6 1.55E-6

Mod2 * -2 114 5.02E-6

* = 0.56 x (VF -32)

A variant of Pilgrim input data, with initial RTNDT = 0F

A variant of Pilgrim input data, with initial RTDT = -20F

Since the BWRVIP analysis was generic, the applicant submitted plant-specific information in

LRA Section 4.2.7 to demonstrate that the Dresden beltline materials meet the criteria

specified in the March 7, 2000, SER. The Dresden vessels were fabricated by B&W, and its

axial welds are ESW. To demonstrate that the Dresden vessels have not become embrittled

beyond the basis for the staff and BWRVIP analyses, the applicant submitted the following

information in LRA Table 4.2.7-1:

* a comparison of the amounts of copper and nickel, chemistry factor, neutron fluence, delta

RTNDT, initial RTNDT, and mean RTNDT of the limiting axial welds at the end of the renewal

period to the reference cases in the BWRVIP and staff analyses

* estimates of the conditional failure probability of the Dresden RPVs at the end of the

license renewal term based on the comparison of the mean RTNDT for the limiting axial

welds and the reference cases

Table 4.2.7-1 of the LRA includes data for two reference cases, 64-EFPY data for a limiting

B&W vessel (from Table 2.6-5 in the March 7, 2000, SER) and Clinton data from Table 4.2-1.

The data in LRA Table 4.2.7-1 show that the mean RTNDT values for Dresden Units 2 and 3 are

equal to 19 OC (67 OF), and these values are smaller than the corresponding values for Clinton

and the limiting B&W vessel. The staff verified the data for chemical composition and initial

RTNDT for all the axial welds in the two Dresden vessels by comparing them with the

corresponding data in RVID maintained by the NRC and confirmed the identification of the

most limiting axial weld as presented in LRA Table' 4.2.7-1. The staff checked the applicant's

calculations for mean RTNDTvalues following Equation 2 of RG 1.99, Revision 2, and found

them to be accurate.

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The vessel failure frequency calculated by the SER for BWRVIP-05 and its supplement

assumes that essentially 100 percent of the axial welds can be inspected. According to 10

CFR 50.55.a(g)(6)(ii)(A)(2), "essentially 100 percent" as used in Table IWB-2500-1 means

more than 90 percent of the examination volume of each weld, where the reduction in

coverage results from interference by another component, or part geometry. However, the

actual inspection at Dresden can include less than 90 percent of the axial welds. Therefore,

the applicant performed an analysis to calculate the conditional probability of vessel failure,

taking into account the actual limited inspection of axial welds at Dresden. The results show

that the conditional probability of vessel failure at 54 EFPYs because of an LTOP event is very

small, 3.89 x 104 and 5.07 x 10- for Dresden Units 2 and 3, respectively. These values of the

conditional probability of failure of Dresden axial welds are smaller than the corresponding

values calculated by the NRC staff in the SER at 64 EFPYs and the limiting Clinton values

found in Table 4.2-1 of this SER. In RAI 4.2-7, the staff requested the applicant to confirm

whether the analysis was performed as part of relief from 100 percent axial and/or elimination

of circumferential inspection. The staff also requested the applicant to discuss the impact of

54 EFPYs of operation on the probability of vessel failure. In response to RAI 4.2-7, in a letter

dated October 3, 2003, the applicant stated that this analysis was performed to demonstrate

that the reliability of the Dresden RPVs remained extremely high considering actual inspection

coverage. The actual inspection coverage could not meet the "essentially 100 percent"

coverage because of inspection limitations caused by obstructions with internal components

and attachments. The analysis did not include the circumferential welds since they had been

previously eliminated from the inspection plan in accordance with BWRVIP-05. The applicant

also stated that the failure probabilities quoted in the question were determined using the

predicted fluence at the end of 60 years of operation (54 EFPYs). The staff finds the response

acceptable because the failure probabilities listed in LRA Table 4.2.7-1 were calculated taking

into account the actual inspection coverage and the predicted 54-EFPY fluence.

This axial weld failure probability analysis is required to be performed as a license renewal

action item in accordance with the staff FSER of EPRI report TR-1 13596 (BWRVIP-74) and

compliance with the license renewal rule (10 CFR Part 54) enclosed in an October 18, 2001,

letter from Mr. C.l. Grimes to Mr. C. Terry. This action item, as stated in the staff's March 7,

2000, letter to Mr. C. Terry, requires the license renewal applicant to monitor axial beltline weld

embrittlement. One acceptable method is to determine that the mean RTNDT of the limiting

axial beltline weld at the end of the extended period of operation is less than the values

specified in Table 1 of this FSER. Therefore this evaluation applies to Dresden Units 2 and 3,

as well as to Quad Cities Units 1 and 2. In addition, Dresden and Quad Cities have the same

mean RTNDT, because the initial RTNDT, chemical composition, and 54-EFPY surface fluence

are the same for the limiting beltline axial welds at Quad Cities and Dresden. Therefore, for

Quad Cities and Dresden plants, the mean RTNDT for the limiting beltline axial welds at 54-

EFPYs is equal to 19 0C (67 OF). A comparison of the mean RTNOTvalue of 33 OC (91 OF) for

the Clinton axial weld from Table 4.2-1 of this SER with the Dresden and Quad Cities value of

19 OC (67 OF) shows that the NRC analysis of the Clinton axial welds bounds the Dresden and

Quad Cities welds. The applicant should confirm that Quad Cities Units 1 and 2 have a mean

value of 19 "C (67 OF) and address this TLAA of the axial welds for Quad Cities in the UFSAR

Supplement. This was identified as Confirmatory Item 4.2.2. In response to Confirmatory Item

4.2.2, in a letter dated March 25, 2004, the applicant compared the limiting axial weld 54-EFPY

properties for Quad Cities 1 and 2 against the corresponding limiting values calculated by the

NRC in the SER for BWRVIP-05 at 64 EFPY and the limiting Clinton values taken from Table

2.6-5 in the March 7, 2000, supplement to the SER. The applicant confirmed that the limiting

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axial welds at Quad Cities Units 1 and 2 have a mean 54 EFPY RTNDT of 190C (67rF), which is

less than the value of 331C (910F) for Clinton. The comparison also shows that the conditional

vessel failure probabilities for Quad Cities Units 1 and 2 are equal to 2.08 x 1 0' and 5.27 x

10'7, respectively. These failure probabilities are less than the corresponding value for Clinton

listed in Table 4.2-1 of this SER. The staff finds the applicant's evaluation for this TLAA

acceptable because the conditional probability of failure of Quad Cities Unit 1 and 2 limiting

axial welds at 54 EFPY is smaller than the corresponding values calculated by the NRC staff in

the SER for BWRVIP-05 at 64 EFPY and the limiting Clinton values found in the March 7,

2000, supplement to the SER.

In a letter dated March 5, 2004, the applicant submitted a revision to the UFSAR supplement

for the reactor vessel axial weld failure probability. The staff reviewed this supplement and

found that it provides an adequate summary description regarding the evaluation of this TLAA.

Therefore, Confirmatory Item 4.2.2 is closed.

The staff finds that the applicant's evaluation for this TLAA is acceptable because the

conditional probability of failure of Dresden and Quad Cities axial welds at 54 EFPYs is

smaller than the corresponding values calculated by the NRC staff in the SER at 64 EFPYs

and the limiting Clinton values found in the March 7, 2000, SER. The staff finds the UFSAR

Supplement (LRA Appendix A.3.1.7) to be acceptable because it includes the necessary

information regarding the evaluation of this TLAA.

4.2.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21 (c)(1)(i) that the analyses remain valid for the period

of extended operation, which includes the extended power uprate conditions, for the reflood

thermal shock analysis of the reactor vessel and the reflood thermal shock analysis of the

reactor vessel core shroud and repair hardware TLAAs. The staff also concludes that the

UFSAR Supplement contains an appropriate summary description of the reflood thermal shock

analysis of the reactor vessel and the reflood thermal shock analysis of the reactor vessel core

shroud and repair hardware TLAA evaluations for the period of extended operation, as

required by 10 CFR 54.21(d).

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21 (c)(1)(ii), that the analyses have been projected to

the end of the period of extended operation, which includes the extended power uprate

conditions, for the reactor vessel materials' USE reduction due to neutron embrittlement,

adjusted reference temperature for reactor vessel materials due to neutron embrittlement,

reactor vessel thermal limit analyses, reactor vessel circumferential weld examination relief,

and the reactor vessel axial weld failure probability TLAAs. The staff also concludes that the

UFSAR Supplement contains an appropriate summary description of the reactor vessel

material' USE reduction because of neutron embrittlement, adjusted reference temperature for

reactor vessel materials because of neutron embrittlement, reactor vessel thermal limit

analyses, reactor vessel circumferential weld examination relief, and the reactor vessel axial

weld failure probability TLAA evaluations for the period of extended operation, as required by

10 CFR 54.21 (d).

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Therefore, the staff has reasonable assurance that the safety margins established and

maintained during the current operating term will be maintained during the period of extended

operation, as required by 10 CFR 54.21 (c)(1).

4.3 Metal Fatigue

A metal component subjected to cyclic loading at loads less than the static design load may

fail because of fatigue. Metal fatigue of components may have been evaluated based on an

assumed number of transients or cycles for the current operating term. The validity of such

metal fatigue analysis is reviewed for the period of extended operation. NUREG-1801

identifies fatigue aging-related effects that require evaluation as possible TLAAs pursuant to

10 CFR 54.21(c). Each of these is summarized in NUREG-1800 and presented in Section 4 of

the LRA.

4.3.1 Summary of Technical Information in the Application

The applicant discussed the design requirements for components of the reactor coolant

system (RCS) at Dresden and Quad Cities. The reactor vessel, reactor vessel internals, and

the reactor coolant pressure boundary (RCPB) piping and components were designed and

fabricated in accordance with the requirements for Class 1 components stated in ASME Boiler

and Pressure Vessel Code, Section 1II, 1965 Edition and 1965 Summer Addenda. Other

safety-related piping and fittings were designed and fabricated in accordance with the

requirements of United States of America Standard (USAS) B31.1, "Power Piping Code,"

ASME Code, Section 1II, Classes 2 and 3, or ASME Code, Section Vill, Classes B and C. The

fatigue analyses of both the reactor coolant loop and attached piping were performed in

accordance with the requirements for ASME Code, Section 1II, Class 1 components.

4.3.1.1 Reactor Vessel Fatigue Analyses

In Section 4.3.1 of the LRA, "Reactor Vessel Fatigue Analyses," the applicant stated that the

original pressure vessel stress report included ASME Code Section III fatigue analyses of the

reactor vessel components based on a set of design-basis duty cycles, which are listed in

Table 3.9-1 of the Dresden and Quad Cities UFSARs. The analyzed components consisted of

the vessel support skirt, shell, upper and lower heads, closure flanges, nozzles and

penetrations, and closure studs. The original 40-year analyses demonstrated that the

cumulative usage factors (CUFs) for the critical components are below the ASME Code,

Section III limiting value of 1.0. A reanalysis was performed for reactor vessel CUFs as part

of EPU implementation at all four Dresden and Quad Cities units. A subset of the bounding

reactor vessel components was evaluated as a part of this reanalysis. The current boundingcase analysis (worst CUFs for all four reactor vessels) lists the following values for the 40-year

CUFs for the limiting components:

* shroud support 0.820

* support skirt 0.862

* feedwater nozzle (safe end) 0.748

* closure studs 0.750

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The original code analysis of the reactor vessel included fatigue analyses of the feedwater

nozzles and the control rod drive hydraulic system return line nozzles. These nozzles were

found to be susceptible to cracking caused by a number of factors, including rapid thermal

cycling.' The control rod drive hydraulic system return line nozzles were therefore capped and

removed from service. A reanalysis was also performed on the feedwater nozzles and

modifications implemented to reduce or eliminate the effects of the high thermal cycling.

The applicant stated that the fatigue of the reactor vessel, including the support skirt, shell,

upper and lower heads, closure assembly, nozzles and penetrations, and nozzle safe ends,

will be managed by the Metal Fatigue of Reactor Coolant Pressure Boundary Aging

Management Program (Metal Fatigue AMP). The program is discussed in Section B.1.34 of'

the LRA. All governing reactor vessel fatigue analyses have been reviewed to establish a

bounding set of reactor locations for inclusion in the Metal Fatigue AMP. Eight locations where

the 40-year CUFs are expected to exceed the threshold value of 0.4 will be included in the

program. These locations are listed in Table 4.3.1-1 of the LRA and include the four locations

listed in the bullets above. The other locations are on the recirculation outlet nozzle, the

recirculation inlet nozzle, the core spray nozzle, and the vessel shell. These components were

selected because they are listed in NUREG/CR-6260. The feedwater nozzle safe end was

also selected because it is one of the components listed in NUREG/CR-6260.

The applicant stated that Dresden and Quad Cities have installed programs to track thermal

and pressure cycles and to assess their effect on vessel fatigue. The requirements from these

procedures will be incorporated into the Metal Fatigue AMP. All necessary plant transient

events will be tracked to ensure that the CUF remains less than 1.0 for all monitored

components. In the event that the CUF for any component is projected to exceed 1.0 during

the period of extended operation, appropriate corrective action will be taken in accordance with

the Exelon Corrective Action Program. This program is discussed in Section B.2.1 of the LRA.

4.3.1.2 Fatigue Analysis of the Reactor Internals

In Section 4.3.2 of the LRA, uFatigue Analysis of Reactor Vessel Internals," the applicant

stated that a review of the CLBs for Dresden and Quad Cities identified only two fatigue

analyses of reactor vessel internals.

In Section 4.3.2.1 of the LRA, "Low Cycle Thermal Fatigue Analysis of the Core Shroud and

Repair Hardware," applicable to Quad Cities only, the applicant identified in the CLB an

evaluation for low-cycle mechanical fatigue of the core shroud and the rod stabilizers in the

core shroud repair hardware because of a cold feedwater transient. The CUF for the core

shroud was found to be negligible, while the CUF for the rod stabilizers for a 40-year plant life

was calculated as less than 0.11. The applicant indicated that the design of the core shroud

support hardware for fatigue effects is valid for the period of extended operation, in

accordance with 10 CFR 54.21 (c)(1)(i).

In Section 4.3.2.2 of the LRA, "High-Cycle Flow-induced Vibration Fatigue Analysis of Jet

Pump Riser Braces," applicable to Dresden Unit 2 only, the applicant identified core flow or

single recirculation loop operation as a cause of significant vibration levels of reactor vessel

internal components. To address this concern, the Dresden Unit 2 reactor vessel internals

were instrumented and tested for vibration levels during startup of the plant. Limiting criteria

were established such that vibration stress levels were assured to remain below material

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endurance limits over the life of the plant. Various operating conditions were evaluated,

including those associated with increased core flow and transient unbalanced flow conditions.

The limiting components were found to be the jet pump riser braces. Although reactor

internals are not code pressure boundary components, the evaluation of the Dresden Unit 2 jet

pump riser braces used methods and fatigue curves similar to those of ASME Code, Section

Ill, Class 1 fatigue analyses.

The applicant stated that the EPU analyses found that Dresden and Quad Cities reactor

internal components, with the exception of the Dresden Unit 2 jet pump riser braces, can

operate at EPU conditions for the period of extended operation without exceeding the original

design vibration criteria or developing increased vibration levels because of recirculation pump

vane passing frequencies. The EPU project evaluated possible effects of the power uprate

and found that, with some possible exceptions, including the Dresden Unit 2 riser braces, the

stress ranges of the reactor internals would remain within the original endurance limit.

The EPU evaluation of flow-induced vibration of reactor internals found that the Dresden Unit 2

jet pump riser braces might be damaged by the recirculation pump vane passing frequency

vibration if operation is permitted in the maximum extended load line limit analysis region.

Operation in this region might produce fatigue cracks and failure in the riser braces at Dresden

Unit 2 only. The Dresden Unit 2 jet pump riser braces are susceptible to resonance effects,

whereas the jet pump riser braces at Dresden Unit 3 and Quad Cities have shown no such

effects and therefore present no concern.

The applicant stated in the LRA that the Dresden Unit 2 riser braces will be repaired or

replaced before the start of the period of extended operation, and, pursuant to 10 CFR

54.21 (c)(1)(ii), will be qualified for the period of extended operation.

4.3.1.3 ASME Code, Section III, Class 1 Reactor Coolant Pressure Boundary Piping and

Component Fatigue Analysis

The applicant stated in Section 4.3.3.1 of the LRA, "ASME Section III Class 1 Reactor Coolant

Pressure Boundary Piping and Component Fatigue Analysis," that the Dresden Unit 3

recirculation system piping is the only RCPB piping that was analyzed for fatigue per ASME

Code, Section III, Class 1 rules at either Dresden or Quad Cities. The Dresden Unit 3

recirculation piping was replaced under the Generic Letter (GL) 88-01 intergranular stresscorrosion cracking mitigation program. The analysis included portions of the connected

shutdown cooling system, the low-pressure coolant injection system, the isolation condenser

system, and the reactor water cleanup system. All other Class 1 piping at both plants was

initially designed to USAS B31.1, 1967 Edition.

The applicant stated that, in accordance with 10 CFR 54.21 (c)(1)(iii), the Dresden Unit 3 RCPB

piping will be managed by the Metal Fatigue AMP. This program is described in Section

B.1.34 of the LRA. The program will monitor CUFs through the cycle-based fatigue monitoring

option. All Dresden Unit 3 RCPB piping fatigue analyses have been evaluated to establish a

bounding set of piping locations for inclusion in the Metal Fatigue AMP. All locations where the

40-year CUFs are expected to exceed a threshold value of 0.4 will be included in the AMP.

The ASME Code, Section 1I1, Class 1 analyses for the Dresden Unit 3 recirculation line and

attached large-bore piping replacement inside the drywell show calculated CUFs at seven

locations that exceed the 0.4 threshold. These locations are listed in Table 4.3.3.3-1 of the

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LRA. All applicable plant transient events will be tracked to ensure that the CUF remains less

than the ASME Code, Section 1II, Class 1 fatigue limit of 1.0 at the monitored locations. In the

event the CUF at a location is predicted to exceed 1.0 before 60 years of operation, the

applicant stated that the necessary corrective action will be taken in accordance with the

Exelon Corrective Action Program, described in Section B.2.1 of the LRA. The required

implementing actions will be completed before the period of extended operation. The

requirements of these procedures will also be incorporated into the Metal Fatigue AMP.

4.3.1.4 Reactor Coolant Pressure Boundary Piping and Components Designed to USAS

B31.1, ASME Code, Section I//, Classes 2 and 3, orASME Code, Section Vil,

Classes B and C

In Section 4.3.3.2 of the LRA, "Reactor Coolant Pressure Boundary Piping and Components

Designed to USAS B31.1, ASME Section III Class 2 and 3, or ASME Section Vil Class B and

C," the applicant stated that the RCPB and non-RCPB piping for the Dresden and Quad Cities

units, including the portions of the main steam and safety relieve valve (SRV) discharge lines

inside the drywell, was designed to USAS B31.1 except for the replaced RCPB piping in

Dresden Unit 3, described in Section 4.3.3.1 of the LRA. None of these codes requires explicit

fatigue analysis. However, the RCPB and non-RCPB piping within the scope of license

renewal that is designed to USAS B31.1 or ASME Code, Section III, Classes 2 and 3 requires

the application of a stress reduction factor to the allowable thermal bending stress range if the

number of full-range cycles exceeds 7000. The applicant also stated that, with the exception

of containment vent and process bellows, no components within the scope of license renewal

designed to ASME Code, Section III or Section VilI require design, or were designed, for

thermal cycling. This applies to the reactor recirculation pumps, which were designed per

ASME Code, Section III, Class C (1965), and the Quad Cities residual heat removal (RHR)

system heat exchangers, which were designed to ASME Code, Section III, Class C (1996)

requirements on the shell side and Section Vil on the tube side. The RHR system includes no

TLAAs other than the piping design for USAS B31.1 stress range reduction factors.

The applicant indicated that the assumed thermal cycle count for the analyses can be

approximated by the thermal-cycles used in the reactor vessel fatigue analysis. These thermal

cycles are listed in UFSAR Table 3.9-1. The total count of all these listed thermal cycles is

less than 2200 over the 40-year plant life. For the 60-year extended operating period, the

number of assumed operating cycles would be increased to 3300, considerably less than the

7000-cycle threshold in USAS B31.1. In accordance with 10 CFR 54.21 (c)(1)(i), the applicant

indicated that the existing piping analyses within the scope of licence renewal containing

assumed thermal-cycle counts are valid for the period of extended operation.

4.3.1.5 Fatigue Analysis of the Isolation Condenser

In Section 4.3.3.3 of the LRA, "Fatigue Analysis of the Isolation Condenser," the applicant

stated that the Dresden isolation condensers (which provide core cooling when the reactor

vessel becomes isolated from the main turbine and the main condenser) were initially

designed for 280 thermal isolation operations. The ASME Code, Section III, Class 1 fatigue

analysis of the critical components of the condensers determined that the 40-year CUF is

below the ASME Code Section III limiting value of 1.0.

4-25
Based on the number of reactor scrams experienced since the start of operation and the

number of recorded isolation operations, the applicant determined that the number of expected

isolation condenser operations would be 181 through the 60-year extended period of

operations. This projected cycle count is below the 280 isolation condenser operating design

limit. On this basis the applicant indicates that, according to 10 CFR 54.21(c)(1)(i), the design

fatigue analysis remains valid through the period of extended operation.

4.3.1.6 Effects of Reactor Coolant Environment on Fatigue Life of Components and Piping

(Generic Safety Issue 190)

In Section 4.3.4 of the LRA, the applicant described the actions taken to address the issue of

environmentally assisted fatigue. Generic Safety Issue (GSI) 190 addresses the effects of

reactor coolant environment on fatigue life of components and piping. Although GSI 190 is

resolved, Section 4.3.1.2 of NUREG-1 800 states that for license renewal, the applicant's

consideration of the effects of coolant environment on component fatigue life is an area of

review.

The applicant stated that plant-specific calculations will be performed for Dresden and Quad

Cities for the following fatigue sensitive component locations identified in NUREG/CR-6260 for

older vintage BWRs:

* reactor vessel (lower head to shell transition)

* feedwater nozzle

* recirculation system (RHR return line tee)

* core spray system (nozzle and safe end)

* residual heat removal line (tapered transition)

* limiting Class 1 location in a feedwater line

This list does not specifically include the feedwater line reactor core isolation cooling (RCIC)

tee location identified in NUREGICR-626, because Dresden does not have an RCIC system

and the RCIC tee location in Quad Cities is located in the outside containment in the Class 2

portion of the feedwater line. However, the applicant has committed to evaluate for each plant

the limiting Class 1 feedwater piping location as stated above.

The applicant stated that for each location listed above, detailed environmental fatigue

calculations will be performed using the appropriate Fen relationships from NUREG/CR-6583

"Effects of LWR Coolant Environments on Fatigue Design Curves of Carbon and Low-Alloy

Steels," for carbon and alloy steels and those from NUREG/CR-5704 "Effects of LWR Coolant

Environments on Fatigue Design Curves of Austenitic Stainless Steels," for stainless steel, as

appropriate for the material. These calculations will be completed before the period of

extended operation, and appropriate corrective action will be taken if the resulting end-of-life

CUF values exceed 1.0. The applicant also stated that it reserves the right to modify this

position in the future, based on the results of ongoing industry activities on this topic, subject to

NRC approval before changes in this position.

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4.3.2 Staff Evaluation

4.3.2.1 Reactor Vessel Fatigue Analysis

The applicant has identified CLB fatigue analyses associated with the reactor vessels as

TLAAs, in conformance with the provisions of 10 CFR 54.21 (c)(1) and the components listed in

the appropriate tables in NUREG-1801. The applicant listed the 40-year bounding CUFs

associated with these TLAAs and indicated that the CUFs for several locations exceeded a

threshold value 0.4. These locations therefore have the potential to exceed the limiting value

of 1.0 during the period of extended operation. -The staff reviewed these locations and

determined that they conform to the locations or components listed in NUREG-1801. The

applicant has therefore committed to monitor, as'part of the Metal Fatigue AMP, eight locations

where the CUFs are expected to exceed the threshold value during the 40-year plant life. This

is Commitment #34 in Appendix A of this SER. The applicant stated that as part of the Metal

Fatigue AMP, all necessary plant transient events will be tracked and the CUFs calculated, to

verify that the CUF remains less than 1.0 for all monitored components and locations. In the

event that the CUF for any component is projected to exceed 1.0 before 60 years of operation,

the applicant commits to take appropriate corrective action in accordance with the Exelon

Corrective Action Program, described in Section B.2.1 of the LRA. This is Commitment #39 in

Appendix A of this SER. The staff finds this acceptable because, pursuant to 10 CFR

54.21 (c)(1)(iii), the applicant has provided assurance that an adequate margin of safety for the

reactor vessel will be maintained for the period of extended operation, as reflected in its

commitment to meet the ASME Code, Section 1I1, Class 1 fatigue analysis criterion associated

with the Metal Fatigue AMP, or to implement corrective actions associated with the Exelon

Corrective Action Program. The applicant's supplements for the Dresden and Quad Cities

UFSARs regarding the reactor vessel fatigue analyses are provided in Section A.3.2.1 of the

respective LRAs. The staff has reviewed these supplements and finds them acceptable

because they provide a reasonable summary of the information presented in Section 4.3.1 of

the LRA.

4.3.2.2 Fatigue Analysis of the Reactor Internals

The staff has reviewed the sections of the LRA pertaining to the fatigue of reactor internals.

Based on a 40-year highest CUF of 0.11 for Quad Cities core shrouds and core shroud repair,

the staff concurs with the applicant that the design of core shroud repair hardware for fatigue

effects is valid for the period of extended operation, in accordance with the requirements of 10

CFR 54.21 (c)(1)(i).

In RAI 4.3.2.2, the staff requested that the applicant provide justification why vibration levels

resulting from conditions such as increased core flow or single recirculation loop operation do

not cause concerns for fatigue of jet pump riser braces or other internal components at

Dresden Unit 3 or Quad Cities, similar to those at Dresden Unit 2. The applicant stated in its

response that the potential for flow-induced vibration of reactor internals at Dresden and Quad

Cities was evaluated as part of the EPU. The EPU analyses indicated that, except for the

Dresden Unit 2 jet pump riser braces, the Dresden and Quad Cities plants can operate at the

increased flow associated with EPU conditions for a 60-year plant life without exciting the

safety-related reactor internal components above their established vibration limits during

balanced (dual loop) recirculation flow operation and without developing resonance problems

4-27
because of vane passing frequency excitation. The EPU analyses also considered single

recirculation loop operation and indicated that, with the existing flow restrictions that apply to

single recirculation loop operation, there is no resonance problem because of vane passing

frequency excitation at EPU operating conditions. The exception involving the Dresden Unit 2

jet pump riser braces occurs because these braces were designed differently from the

Dresden Unit 3 and Quad Cities jet pump riser braces. In accordance with LRA Section

4.3.2.2, the applicant committed to repair or replace the Dresden Unit 2 jet pump riser braces

before the period of extended operation. This is Commitment #48 in Appendix A of this SER.

The applicant also stated in LRA Section 4.3.2.2 that the repaired or replaced braces will be

qualified for the period of extended operation, in accordance with the requirements of 10 CFR

54.21(c)(1)(ii). The staff finds this acceptable because it will provide a margin of safety for the

Dresden Unit 2 braces similar to that of Dresden Unit 3 and Quad Cities.

The applicant's supplements for the Dresden and Quad Cities UFSARs regarding the fatigue

analyses of reactor vessel internals are provided in Section A.3.2.2 of the respective LRAs.

The staff has reviewed this supplement and finds it acceptable because it provides a

reasonable summary of the information presented in Section 4.3.2 of the LRA.

4.3.2.3 ASME Code, Section 111, Class 1 Reactor Coolant Pressure Boundary Piping and

Component Fatigue Analysis

The applicant has identified CLB ASME Code, Section III, Class 1 fatigue analyses associated

with the recirculation piping system at Dresden Unit 3 as TLAAs, in conformance with the

provisions of 10 CFR 54.21 (c)(1) and the piping components listed in the appropriate tables in

NUREG-1801. The applicant listed the 40-year CUFs for several components which

exceeded a threshold value of 0.4. The CUFs of these components therefore have the

potential of exceeding the limiting value of 1.0 during the period of extended operation. The

staff reviewed these locations and determined that they conform with components listed in

NUREG-1801. Pursuant to 10 CFR 54.21(c)(1)(iii), the applicant has therefore committed to

monitor, as part of the Metal Fatigue AMP, seven components where the CUFs are expected

to exceed the threshold value during the 40-year plant life. This is Commitment #34 in

Appendix A of this SER. The applicant stated that as part of the Metal Fatigue AMP, all

necessary plant transient events will be tracked and the CUFs calculated, to verify that the

CUF remains less than 1.0 for all monitored components. In the event that the CUF for any

component is projected to exceed 1.0 before 60 years of operation, the applicant commits to

implement appropriate corrective actions in accordance with the Exelon Corrective Action

Program, described in Section B.2.1 of the LRA, before the period of extended operation. This

is Commitment #39 in Appendix A of this SER. The staff finds this acceptable because the

applicant has provided assurance that an adequate margin of safety for the recirculation piping

system at Dresden Unit 3 will be maintained for the period of extended operation, as reflected

in its commitment to meet the ASME Code, Section lii, Class 1 fatigue analysis criterion within

the Metal Fatigue AMP or to implement corrective actions associated with the Exelon

Corrective Action Program.

The applicant's supplement for the Dresden UFSAR regarding the recirculation piping system

fatigue analyses is provided in Section A.3.2.3.1 of the LRA. The staff has reviewed this

supplement and finds it acceptable because it provides a reasonable summary of the

information presented in Section 4.3.3.1 of the LRA.

I

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4.3.2.4 Reactor Coolant Pressure Boundary Piping and Components Designed to USAS

B31. 1, ASME Code, Section III, Classes 2 and 3, or ASME Code, Section VIII,

Classes B and C

The applicant indicated that RCPB piping systems other than the recirculation piping at

Dresden Unit 3 were designed to the requirements of USAS B31.1, 1967 Edition, or ASME

Code, Section III, Classes 2 and 3. These codes consider fatigue implicitly in the design

calculations by applying stress range reduction factors to the allowable stress range to account

for cyclic thermal conditions. The applicant approximated the number of cycles over a 40-year

plant life by the thermal cycles used in the reactor vessel fatigue analysis. These thermal

cycles are listed in UFSAR Table 3.9-1. For a 60-year plant life, the total count of all these

listed thermal cycles is less than 3300. This is substantially less than the 7000 cycle' limit in

USAS B31.1 or ASME Code, Section III, Classes 2 and 3. The staff therefore finds that the

applicant has demonstrated that an adequate margin of safety for the RCPB piping systems at

Dresden Unit 2 and Quad Cities designed to USAS B31.1 or ASME Code, Section III, Classes

2 and 3 will be maintained for the period of extended operation, because the margin conforms

with accepted industry practice. The staff concludes that the applicant has demonstrated that

the existing analyses will remain valid for the period of extended operation in accordance with

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

The applicant's supplement for the Dresden and Quad Cities UFSAR regarding the RCPB

piping system fatigue analyses is provided in Section A.3.2.3.2 of the LRA. The staff has

reviewed this supplement and finds it acceptable because it provides a reasonable summary of

the information presented in Section 4.3.3.2 of the LRA.

4.3.2.5 Fatigue Analysis of the Isolation Condenser

In Section B.1.34, the applicant stated that as an enhancement to the Metal Fatigue AMP the

program will provide for tracking of fatigue stress cycles for the Dresden isolation condensers.

In RAI 4.3.3.3, the staff requested that the applicant provide an explanation of why this

enhancement to the AMP does not conflict with the disposition of this item stated in Section

4.3.3.3 of the LRA. (The applicant indicated that the fatigue analysis remains valid for the

period of extended operation, in accordance with 10 CFR 54.21 (c)(1)(i).)

The applicant stated that the isolation condensers are included in the manual cycle counting

option of the FatiguePro monitoring program of the Metal Fatigue AMP because RCPB piping'

locations associated with the condenser have predicted CUFs greater than 0.4. Because the

thermal transients associated with the isolation condensers can affect the CUFs of these

locations, the applicant has conservatively elected to include the isolation condenser locations

in the monitoring program. In accordance with -10 CFR 54.21 (c)(1)(iii), the staff finds this

acceptable because cycle monitoring of the isolation'condensers as proposed by the applicant

will provide assurance that the margin of safety of the condensers and associated piping will

be maintained for the period of extended operation, in conformance with the CLB design

requirements of the condensers.

The applicant's supplement for the Dresden UFSAR regarding the isolation condenser fatigue

analysis is provided in Section A.3.2.3.3 of the LRA. The staff has reviewed this supplement

and finds it acceptable because it provides a reasonable summary of the information

presented in Section 4.3.3.3 of the LRA.

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4.3.2.6 Effects of Reactor Coolant Environment on Fatigue Life of Components and Piping

(Generic Safety Issue 190)

GSI-1 66, "Adequacy of the Fatigue Life of Metal Components," raised concerns regarding the

conservatism of the fatigue curves used in the design of the RCS components. Although

GSI-166 was resolved for the current 40-year design life of operating components, the staff

identified GSI-1 90, "Fatigue Evaluation of Metal Components for 60-Year Plant Life," to

address license renewal. The NRC closed GSI-190 in December 1999, with the following

conclusion:

The results of the probabilistic analyses, along with the sensitivity studies performed, the

iterations with industry (NEI and EPRI), and the different approaches available to the licensees to

manage the effects of aging, lead to the conclusion that no generic regulatory action is required,

and that GSI-190 is closed. This conclusion is based pmarily on the negligible calculated

increases in core damage frequency in going from 40 to 60 year lives. However, the calculations

supporting resolution of this issue, which included consideration of environmental effects, and the

nature of age-related degradation indicate the potential for an increase in the frequency of pipe

breaks as plants continue to operate. Thus, the staff concludes that, consistent with existing

requirements in 10 CFR 54.21, licensees should address the effects of coolant environment on

component fatigue life as aging management programs are formulated in support of license

renewal.

The applicant has committed to evaluate the component locations listed in NUREG/CR-6260,

that are applicable to an older vintage BWR plant for the effect of the environment on the

fatigue life of the components, not including the RCIC tee located on the feedwater line. This

is Commitment #48 in Appendix A of this SER. The applicant justified this on the basis that

there is no RCIC system at Dresden and therefore this component does not exist at Dresden,

and that at Quad Cities this tee is located in the Class 2 portion of the feedwater line.

However, the applicant stated that for both plants, alternate limiting Class 1 locations on the

feedwater piping will be evaluated for environmental fatigue effects.

The applicant stated that for each location, detailed environmental fatigue calculations will be

performed using the appropriate Fen relationships from NUREG/CR-6583, "Effects of LWR

Coolant Environments on Fatigue Design Curves of Carbon and Low-Alloy Steels," for carbon

and alloy steels, and those from NUREG/CR-5704, "Effects of LWR Coolant Environments on

Fatigue Design Curves of Austenitic Stainless Steels," for stainless steel, as appropriate for

the material. These calculations will be completed prior to the period of extended operation,

and appropriate corrective action will be taken if the resulting end-of-life CUF values exceed

1.0. The staff finds this acceptable because it concurs with the staff position on environmental

effects on metal fatigue of Class 1 components.

The applicant also stated that it reserves the right to modify this position in the future, based

on the results of ongoing industry activities on this topic, subject to NRC approval prior to

changes in this position. The staff concurs with this statement since any licensee always has

the option of submitting a license amendment that would be subject to review and approval by

the staff.

In RAI 4.3.4, the staff requested that the applicant identify the alternate limiting Class 1

feedwater piping locations and provide the calculated CUF for these locations. In response,

the applicant stated that the entire Class 1 portion of a feedwater line was structurally

modeled, based on the bounding geometry for all eight feedwater loops (two loops per unit),

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and a fatigue analysis was performed using ASME Code, Section liI, NB-3600 methodology.

The results of the fatigue analysis determined that the location with the highest fatigue usage

(CUF=0.0859, not including environmental effects) was at the tee joining a riser pipe to a

header (Node 15a in the structural model). This location will be used to perform plant-specific

environmental fatigue calculations. (This location is different from the reactor vessel feedwater

nozzle location specified in NUREG/CR-6260, since this location will be separately evaluated

for environmental effects.) The staff finds this acceptable because the selection of the limiting

location was performed in accordance with the basis for selection of the locations for older

vintage BWR plants, stated in NUREG/CR-6260 for a similar portion of the feedwater lines.

In accordance with 10 CFR 54.21(d), the applicant has included a section addressing the

effects of reactor coolant environment on fatigue life of components and piping (Issue 190) in

the UFSAR Supplement Section A.3.2.4 for Dresden and for Quad Cities. The applicant has

committed to perform plant-specific calculations for environmental effects on the fatigue life of

the components listed in NUREG/CR-6260 and the limiting location on the feedwater line, and

take appropriate corrective actions if the resulting projected end-of-life CUF values exceed 1.0.

This is Commitment #48 in Appendix A of this SER. The calculations will include appropriate

environmental fatigue effect factors from NUREG/CR-6583 and NUREG/CR-5704. The

applicant also stated in the UFSAR Supplement that it reserves the right to modify this position

in the future, based on the results of ongoing industry activities on this topic, subject to NRC

approval prior to changes in this position. The staff concurs with this statement since any

licensee always has the option of submitting a license amendment that would be subject to

review and approval by the staff. The staff finds this supplement acceptable because it

provides a reasonable summary of the information presented in Section 4.3.4 of the LRA.

4.3.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21 (c)(1)(i), that the analyses remain valid for the period

of extended operation for the low-cycle thermal fatigue analysis of the core shroud and repair

hardware; the reactor coolant pressure boundary piping and components designed to USAS

B31.1, ASME Code, Section III, Classes 2 and 3, or ASME Code, Section Vill, Classes B and

C; and the fatigue analysis of the isolation condenser TLAAs. The staff also concludes that

the UFSAR Supplement contains an appropriate summary description, as required by 10 CFR

54.21 (d), of the low-cycle thermal fatigue analysis of the core shroud and repair hardware; the

reactor coolant pressure boundary piping and components designed to USAS B31.1, ASME

Code, Section 1II, Classes 2 and 3, or ASME Code, Section Vill, Classes B and C; and the

fatigue analysis of the isolation condenser TLAA evaluations for the period of extended

operation.

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21 (c)(1)(ii), that the analyses have been projected to

the end of the period of extended operation for the high-cycle flow-induced vibration fatigue

analysis of jet pump riser braces and the effects of reactor coolant environment on fatigue life

of components and piping TLAAs. The staff also concludes that the UFSAR Supplement

contains an appropriate summary description of the high-cycle flow-induced vibration fatigue

analysis of jet pump riser braces and the effects of reactor coolant environment on fatigue life

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I

of components and piping TLAA evaluations for the period of extended operation, as reflected

in the license condition required by 10 CFR 54.21(d).

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21 (c)(1)(iii), that the effects of aging on the intended

functions will be adequately managed for the period of extended operation for the reactor

vessel fatigue analyses and the ASME Code, Section 111, Class 1 reactor coolant pressure

boundary piping and component fatigue analysis TLAAs. The staff also concludes that the

UFSAR Supplement contains an appropriate summary description of the reactor vessel fatigue

analyses and the ASME Code, Section III, Class 1 reactor coolant pressure boundary piping

and component fatigue analysis TLAA evaluations for the period of extended operation, as

required by 10 CFR 54.21 (d).

Therefore, the staff has reasonable assurance that the safety margins established and

maintained during the current operating term will be maintained during the period of extended

operation, as required by 10 CFR 54.21(c)(1).

4.4 Environmental Qualification

4.4.1 Environmental Qualification Program TLAA

The NRC has established nuclear station environmental qualification (EQ) requirements in

Crieterion 4 of Appendiz A to 10 CFR Par 50 and 10 CFR 50.49. The latter 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 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. Also, 10 CFR 50.49 requires that the effects of significant aging

mechanisms be addressed as part of EQ. For the purpose of license renewal, only those

components with a qualified life of 40 years or greater would require TLAAs.

The staff has reviewed LRA Section 4.4, "Environmental Qualification of Electrical Equipment"

in which the applicant described the technical bases and justification for why the Dresden and

Quad Cities EQ Programs, together with other plant programs and processes, adequately

manages the effects of aging on the intended function(s) of electrical components for the

period of extended operation. The staff reviewed this section of the LRA to determine whether

the applicant had demonstrated that the effects of aging on the intended function(s) of the

electrical equipment will be adequately managed through the Dresden and Quad Cities EQ

Programs, together with other programs and processes, during the period of extended

operations, as required by 10 CFR 54.21 (c)(1)(iii).

4.4.1.1 Summary of Technical Information in the Application

The Dresden and Quad Cities EQ Programs are established to demonstrate that certain

electrical components located in an environment that is subject to a LOCA, HELB, or postLOCA radiation are qualified to perform their safety function after inservice aging. The

Dresden and Quad Cities EQ Programs comply with the requirements of 10 CFR 50.49(e)(5)

for aging considerations that affect functionality and make provisions to replace the

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components or establish ongoing qualification when the demonstrated qualified life has

expired. The EQ-related equipment is identified in a controlled equipment database with a

qualification binder that is maintained with records on performance specifications, electrical

characteristics and environmental conditions.

The Dresden and Quad Cities EQ Programs manage thermal, radiation and cyclic aging as

applicable for all electrical components within the scope of 10 CFR 50.49 and for components

that are presently qualified in accordance with the DOR guidelines. Compliance with 10 CFR

50.49 provides evidence that the component will perform its intended functions during and

after a design-basis event after experiencing the effects of inservice aging.

Under 10 CFR 54.21(c)(1)(iii), the Dresden and Quad Cities EQ Programs, which implement

the requirements of 10 CFR 50.49 (as further clarified by the DOR guidelines, NUREG-0588,

and RG 1.89, Revision 1), are viewed as an AMP for license renewal. Aging evaluations of

electrical components in the Dresden and Quad Cities EQ Programs that specify qualification

of at least 40 years are TLAAs. Reanalysis will be applied to EQ components now qualified for

the current operating term of 40 years.

The reanalysis of an aging evaluation may be performed to extend the qualification by

reducing margin or excess conservatism incorporated in the prior evaluation. Reanalysis of an

aging evaluation to extend the qualification of a component may be performed as part of the

EQ Program. While a component life-limiting condition may be result from 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, unrealistically low activation energy, or in the application of a

component as de-energized instead of energized. The important attributes of reanalysis will

include analytical methods, data collection and conservative reduction methods, underlying

assumptions, acceptance criteria, and corrective actions (if acceptance criteria are not met), as

discussed below.

Analytical Methods: The analytical models used in the reanalysis of an aging evaluation are

the same as those previously applied during the previous evaluation. The Arrhenius

methodology is an acceptable thermal model for performing an aging evaluation. The

analytical method used for a radiation aging evaluation demonstrates 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, and cycles) used in the previous aging

evaluation is the chief method used for a reanalysis. Temperature data used in an aging

evaluation should 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). When used, a representative number of temperature

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measurements is 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 (1) directly applying the plant temperature data in the evaluation, or (2) using the plant

temperature data to demonstrate conservatism when using plant-design temperatures for an

evaluation. Any changes to material activation energy values as part of a reanalysis are

justified on a case-specific basis. Similar methods of reducing excess conservatism in the

component service conditions used in prior aging evaluations may be used for radiation and

cyclical aging.

Underlying Assumptions: EQ component aging evaluations contain sufficient conservatism to

account for most environmental changes occurring because of 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 maintained, replaced, or requalified prior to exceeding the period

for which the current qualification remains valid. A reanalysis is performed in a timely manner

(that is, sufficient time is available to maintain, replace, or requalify the component if the

reanalysis is unsuccessful).

Environmental Qualification of Electrical Components: As stated in LRA Section B.1.35, the

Environmental Qualification of Electrical Components AMP is implemented through station

procedures and predefined tasks. The Dresden and Quad Cities EQ Programs comply with 10

CFR 50.49, "Environmental Qualification of Electrical Equipment Important to Safety for

Nuclear Power Plants." All EQ equipment is included within the scope of license renewal. The

program provides for maintenance of the qualified life for electrical equipment important to

safety within the scope of 10 CFR 50.49. Program activities establish, demonstrate, and

document the level of qualification, qualified configuration, maintenance, surveillance, and

replacement requirements necessary to meet 10 CFR 50.49. Qualified life is determined for

equipment within the scope of the EQ Program, and appropriate actions such as replacement

or refurbishment are taken prior to or at the end of the qualified life of the equipment so that

the aging limit is not exceeded.

NUREG-1801 Consistency: The Environmental Qualification of Electrical Components AMP is

consistent with the 10 elements of AMP X.E1, "Environmental Qualification (EQ) of Electrical

Components," specified in NUREG-1 801.

Operating Experience: The Environmental Qualification of Electrical Components AMP

provides for consideration of operating experience to reconcile qualification bases and

conclusions, including the equipment qualified life. Operating experience and information

related to systems, equipment, or components, as reported through NRC bulletins, notices,

circulars, generic letters, and Part 21 notifications, are evaluated for applicability. The

evaluations are documented and corrective actions are identified. Operating experience has

demonstrated that the program manages aging as required by 10 CFR 50.49. When problems

have been identified through industry or plant-specific experience, corrective actions have

been taken to prevent recurrence.

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4.4.1.2 Staff Evaluation

The staff reviewed the information in Section 4.4 of the LRA to determine whether the

applicant has demonstrated that the effects of aging on the intended function(s) of electrical

components will be adequately managed through its existing program, together with other

plant programs/processes, during the period of extended operation as required by 10 CFR

54.21 (c)(1)(iii).

The applicant's program activities establish, demonstrate, and document the level of

qualification, qualified configuration, maintenance, surveillance, and replacement requirements

necessary to meet 10 CFR 50.49. Qualified life is determined for equipment within the scope

of the EQ Program and appropriate actions, replacement, or refurbishment are taken prior to

or at the end of qualified life of the equipment so that aging limits or acceptable margins are

not exceeded. In response to RAI 4.3-0, the applicant committed to the following

(Commitment #49 in Appendix A of this SER) in a letter dated October 3, 2003:

The Dresden/Quad Cities license renewal evaluations were based upon the plant environmental

conditions associated with EPU implementation. Prior to the pefiod of extended operation, the

Environmental Qualification (EQ) Binders for components within the scope of 10 CFR 50.49 will be

updated to include environmental conditions associated with EPU implementation together with an

extended operating period of 60 years.

The applicant's Environmental Qualification of Electrical Components AMP provides

reasonable assurance that aging effects are adequately managed so that the intended

functions of components within the scope of 10 CFR 50.49 are maintained during the period of

extended operation.

The staff also reviewed the UFSAR Supplement for this TLAA and concluded that it provided

an adequate summary description of the TLAA to satisfy the requirement of 10 CFR 54.21 (d).

4.4.1.3 Conclusions _

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21 (c)(1)(iii), that the effects of aging on the intended

function(s) will be adequately managed for the period of extended operation for the EQ of

electrical equipment TLAA. The staff also concludes that the UFSAR Supplement contains an

appropriate summary description of the EQ of electrical equipment TLAA evaluation for the

period of extended operation, as required by 10 CFR 54.21 (d). Therefore, the staff has

reasonable assurance that the safety margins established and maintained during the current

operating term will be maintained during the period of extended operation, as required by 10

CFR 54.21 (c)(1).

4.4.2 Generic Safety Issue 168, "Environmental Qualification of Low-Voltage

Instrumentation and Control (I&C) Cables"

4.4.2.1 Summary of Technical Information in the Application

The applicant states that NRC guidance for addressing GSI-1 68 "Environmental Qualification

of Low Voltage Instrumentation and Control (I&C) Cables," for license renewal is contained in

the June 2, 1998, NRC letter to NEI. In the letter, the NRC states:

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"With respect to addressing GSI-168 for license renewal, until completion of an ongoing research

program and staff evaluations the potential issues associated with GSI-168 and their scope have

not been defined to the point that a license renewal applicant can reasonably be expected to

address them at this time. Therefore, an acceptable approach described in the Statement of

Consideration is to provide a technical rationale demonstrating that the current licensing basis for

environmental qualification pursuant to 10 CFR 50.49 will be maintained in the period of extended

operation. Although the Statement of Consideration also indicated that an applicant should provide

a brief description of one or more reasonable options that would be available to adequately manage

the effects of aging, the staff does not expect an applicant to provide the options at this time."

This is consistent with the above NRC guidance, no additional information is required to

address GSI-168 in a license renewal application at this time.

4.4.2.2 Staff Evaluation

GSI-168, "Environmental Qualification of Low Voltage Instrumentation and Control (I&C)

Cables," was developed to address environmental qualification of electrical equipment. The

staff guidance to the industry (letter dated June 2, 1998, from Mr. C.l. Grimes (NRC) to Mr.

D,J. Walters (NEI) states the following:

* GSI-168 issues have not been identified to a point that a license renewal applicant can be

reasonably expected to address these issues, specifically at this time

* An acceptable approach is to provide a technical rationale demonstrating that the CLB for

EQ will be maintained in the period of extended operation.

For the purpose of license renewal, as discussed in the Statements of Consideration (60 FR

22484, May 8, 1995), there are three options for addressing issues associated with a GSI:

* If the issue is resolved before the renewal application is submitted, the applicant can

incorporate the resolution in the LRA.

* An applicant can submit a technical rationale that demonstrates that the CLB will be

maintained until some later point in the period of extended operation, at which time one or

more reasonable options would be available to adequately manage the effects of aging.

* An applicant can develop a plant-specific AMP that incorporates the resolution of the aging

issue.

On May 2, 2003, the staff issued NRC Regulatory Issue Summary (RIS) 2003-09,

"Environmental Qualification of Low-Voltage Instrumentation and Control Cables," providing the

results of the staff's technical assessment of GSI-168 following completion of the NRCsponsored cable test research. The staff concluded that typical l&C cable qualification test

programs include numerous conservative practices that collectively provide a high level of

confidence that the installed I&C cables will perform their intended functions during and

following design-basis events, as required by 10 CFR 50.49. These conservative practices

continue to support the current use of a single prototype test specimen during qualification

testing, and as such, a successful test provides a high level of confidence that these cables will

be able to perform their safety functions during and following design-basis events. However,

I&C cable LOCA test failures during the NRC-sponsored research program indicate that the

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original margin and conservatism inherent in the qualification process have been reduced.

Therefore, licensee awareness of the operating service environments (temperature, radiation,

and moisture) is essential to ensure that the operating conditions in nuclear power plants do not

exceed the qualification parameters that were assumed during qualification testing.

RIS 2003-09 further states that licensees that have addressed license renewal recognize that

knowledge of the operating service environments is essential to extending the qualified life of

l&C cables. Where measured environmental service conditions are less severe than those

used in the original qualification and when the cables are not degraded, the licensee assessed

the difference between the operating environment and the original qualification environment to

extend the qualified life of the cables to 60 years by reanalysis. This approach, based on the

Arrhenius methodology, has been found acceptable by the staff during its review of license

renewal applications.

In response to RAI 4.4-1, the applicant provided the following in a letter dated October 3, 2003:

Exelon performed an analysis for all EQ-related equipment and has qualified all low-voltage l&C

cables for 60 years of service without lowering the original environmental service conditions. No

measured environmental service conditions were used in the analysis, but the qualification files

have not been updated to support 60-year life. For Dresden and Quad Cities, the EQ TLAA

ensures the effects of aging will be adequately managed for the period of extended operation per the provision of 10 CFR 54.21(c)(1)(iii). Therefore, with respect to GSI-168, Section 4.4 of the

application should have stated: 'Adherence to the EQ program and use of current EQ process for

Dresden and Quad Cities stations will provide reasonable assurance through the extended period of operation that the equipment qualification will be maintained in compliance with the applicable

NRC requirements."

The staff finds that the applicant has adequately addressed the issues associated with GSI-1 68

for license renewal because the applicant will continue to manage the effects of aging through

the EQ Program for the period of extended operation.

4.4.2.3 Conclusions

On the basis of its review, the staff concludes that the applicant has adequately addressed the

issues associated with GSI-168 for license renewal as required by 10 CFR 54.21(c)(1)(iii). The

staff has also reviewed the UFSAR Supplement and the staff concludes the applicant has

provided an adequate description of its evaluation of this TLAA for the period of extended

operation as required by 10 CFR 54.21 (d).

4.5 Loss of Prestress in Concrete Containment Tendons

None of the Dresden or Quad Cities containments have prestress tendons. As such, this

topic is not a TLAA.

4.6 Fatigue of Primary Containment, Attached Piping. and Components

The applicant stated in Section 4.6 of the LRA that the cyclic loads acting on the primary

containment and the attached piping and components include reactor building interior

temperature variation during the heatup and cooldown of the RCS, a LOCA, annual outdoor

temperature variations, thermal loads on containment penetrations because of high-energy

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piping lines (such as steam and feedwater lines), seismic loads, and pressurization resulting

from periodic Type A integrated leak rate tests.

The metal containments, penetration sleeves (including dissimilar metal welds), and penetration

bellows may be designed in accordance with the requirements of Section III of the ASME Boiler

and Pressure Vessel Code. If a plant's code of record requires a fatigue analysis, then this

analysis may be a TLAA and must be evaluated in accordance with 10 CFR 54.21 (c)(1) to

ensure that the effects of aging on the intended functions will be adequately managed for the

period of extended operation.

The adequacy of the metal containment, penetration sleeves, and penetration bellows is

reviewed for the period of extended operation. Section 4.3 of this SER includes a separate

review of the fatigue analysis of the pressure boundary of process piping.

The primary containments at Dresden and Quad Cities were designed in accordance with

ASME Code Section III, 1965 Edition with Addenda up to and including Winter 1965.

Subsequent to the original design, elements of the Dresden and Quad Cities containments

were reanalyzed in response to discoveries of unevaluated loads because of assumed pressure

and temperature cycles resulting from SRV discharge and design-basis LOCA events. This

reevaluation was performed under Mark I Containment Program plant-unique analyses and

reported in plant unique analysis reports (PUARs).

The applicant also stated the following:

In the absence of hydrodynamic loads, fatigue is not a concern in containment design except at

penetrations or other stress concentration areas. The licensing and design basis documents do

not reflect the existence of any fatigue analyses for the drywell or its penetrations. However, the

drywell process bellows, including replacement bellows for Quad Cities, were specified for a finite

number of operating cycles.

4.6.1 Summary of Technical Information in the Application

4.6.1.1 Fatigue Analysis of the Suppression Chamber, Vents and Downcomers

The applicant stated that the Dresden and Quad Cities PUARs describe the fatigue analyses of

the suppression chambers and suppression chamber (torus) vents, including the vent headers

and downcomers. The analyses assumed a limited number of SRV actuations during the plant

transients, based on a survey of plant data extrapolated to 40 years. Each SRV actuation was

assumed to result in one thermal, one pressure, and five dynamic load cycles.

The applicant listed the transients and corresponding design cycles used for the fatigue

analysis of the suppression chamber shells and the associated welds, as well as the

suppression chamber vent headers, downcomers, and associated welds for both Dresden and

Quad Cities. Table 4.6-1 of the LRA lists the calculated CUFs exceeding 0.4 for a 40-year

period of operation for each component and associated weld. The worst-location CUF is 0.92,

located at the intersection of the vent headers and the downcomers.

For most shell, vent, and penetration locations, the predicted 40-year CUF is less than 0.666.

In accordance with 10 CFR 54.21 (c)(1 )(i), the fatigue analyses of these locations remain valid

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because the CUFs for the period of extended operation will be less than 1.0. However, the

applicant stated that a CUF of 0.666 provides no analytical or event margin. The applicant

stated that the validation will therefore be applied to locations with calculated 40-year CUFs less

than 0.4. The locations where this threshold value is expected to be exceeded will be included

in the Metal Fatigue AMP, in accordance with 10 CFR 54.21 (c)(1)(iii). These locations, listed in

Table 4.6.1-2 of the LRA, consist of the suppression chamber weld and the vent header at the

downcomer-vent header intersection (for Dresden Units 2 and 3) and the suppression chamber

shell (for Quad Cities Units 1 and 2). These locations represent or bound all other locations for

both plants. All necessary plant transients will be tracked to ensure that the CUF remains less

than 1.0 for all monitored components. In the event fatigue usage is predicted to exceed 1.0 for

any component before 60 years of operation, appropriate action will be taken in accordance

with the Exelon Corrective Action Program, described in Section B.2.1 of the LRA. The

required implementing actions will be completed prior to the period of extended operation.

4.6.1.2 Fatigue Analysis of Safety Relief Valve Discharge Piping Inside the Suppression

Chamber, External Suppression Chamber Attached Piping, and Associated

Penetrations

The applicant stated that the PUARs for each site describe the fatigue analyses of the SRV

discharge lines and their penetrations through the vent lines, the suppression chamber (torus)

shell and the attached piping systems, and the T-quenchers inside the suppression chamber.

These analyses assume a limited number of SRV actuations throughout the 40-year life of the

plant and are therefore TLAAs.

The fatigue analysis of the external torus attached piping and Class 2/3 SRV discharge lines

assumed 800 SRV actuations with 5 cycles per actuation for a 40-year plant life. Other thermal

cycles resulting from normal operating conditions were considered to have a negligible effect.

The analysis indicated that these lines would have a CUF less than 0.5 at the end of 40 years

of operation.

The SRV discharge line-vent line penetrations and associated sections of the SRV discharge

lines are classified as Class MC components. The fatigue analyses of these components were

based on 110 isolation events, each with 2 actuations. The analyses show maximum CUFs of

0.09 for Dresden and 0.18 for Quad Cities.

The fatigue calculations of the Class MC penetration components and attachments assumed

220 SRV actuations of 5 dynamic cycles each, plus 4050 cycles caused by condensation

oscillation or chugging. The alternating stress intensity corresponding to the total sum of these

cycles was determined. These analyses did not calculate the CUFs. Instead, the applicant

specified that the alternating stress intensity at the highest stress location should be smaller

than that corresponding to the assumed number of cycles. This, in effect, ensures that the

CUF will be less than 1.0 for the entire period of plant operation. This concept is applicable

only with the stress monitoring option of the Metal Fatigue AMP, evaluated in Section 3.1.2.3.9

of this SER.

To address concerns associated with potential plugging and unacceptable head loss, the

emergency core cooling system (ECCS) suction strainers were replaced with larger units at

both Dresden and Quad Cities. This replacement required revised stress and fatigue analyses.

The fatigue analyses of these penetrations were based on the generic Mark I owners group

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analysis for 40-years of plant life. For Dresden Unit 2, the highest calculated CUF for these

components is 0.142. For Dresden Unit 3, the highest CUF for these components is 0.0832.

For Quad Cities, the highest calculated CUF for these components is 0.3087.

The highest 40-year CUFs for the suppression pool shell attached piping, SRV discharge lines,

and penetrations are listed in Table 4.6.2-1 of the LRA. The applicant stated that th Metal

Fatigue AMP, described in Section B. 1.34 of the LRA, will include all locations where the 40-

year CUF exceeds the threshold value of 0.4. Since only the SRV load cases contribute to

fatigue of these components during normal operation, the contribution to the CUF at a particular

location resulting from the number of SRV actuations will be monitored to ensure that it does

not exceed 1.0 minus the CUF contribution from a postulated LOCA plus operating based

events.

4.6.1.3 Drywell-to-Suppression Chamber Vent Line Bellows Fatigue Analyses

The applicant stated that Mark I containment designs include a drywell-to-suppression chamber

vent line. A bellows assembly is provided at the penetration of the vent line to the suppression

chamber. The bellows allows differential movement of the vent system and suppression

chamber without developing significant interaction loads. The fatigue analyses of these bellows

are included in the Mark I Containment Long-Term Program plant-unique analysis.

Dresden and Quad Cities have external vacuum breakers which include 24-in. bellows. There

are differences between the bellows configurations at the two plants, but the effect of these

differences in the overall vent system analysis was found to be insignificant. At Quad Cities,

these bellows were included in the vent system analysis. At Dresden, these bellows were

evaluated as part of the penetrations. The applicant referenced an NRC SER which concluded

that the owners' comparison of the Dresden external vacuum breakers to the stress criteria of

ASME Code, Section III, Subsection NC, 1977 Edition with Summer 1977 Addenda,

demonstrated that the fatigue usage factors in the vacuum breakers and their attachments (and

at Dresden, their penetrations) are bounded by other analyzed locations and therefore are not

limiting. The SER therefore concluded that the design was adequate.

The applicant stated that the analysis of the vent line bellows was based on a total of 150

thermal and internal pressure-load cycles for the 40-year life of the plant and are therefore

adequate for fatigue, since they have a rated capacity of 1000 cycles at maximum

displacement. The number of load cycles for the period of extended operation is 225, which is

less than 25 percent of the rated capacity. The applicant indicated that, pursuant to

10 CFR 54.21 (c)(1)(i), the fatigue adequacy of the bellows is valid for the period of extended

operation.

4.6.1.4 Primary Containment Process Penetration Bellows Fatigue Analysis

The applicant stated in Section 4.6.4 of the LRA that at Dresden and Quad Cities the only

containment process piping expansion joints subject to significant thermal expansion and

contraction are those between the drywell shell penetrations and process piping. Thermal

cycles on the bellows are imposed by thermal cycles experienced by the attached piping. The

assumed thermal-cycle count can be approximated by the thermal cycles used in the reactor

vessel fatigue analysis, which are listed in Table 3.9-1 of the UFSAR. The total count of all

these cycles is 2200 for a 40-year plant life. For a 60-year plant life, the number of thermal

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cycles for the piping penetration bellows analyses increases to 3300. The bellows are designed

for 7000 operating cycles, corresponding to the design code for the piping. The applicant

indicated that, pursuant to 10 CFR 54.21 (c)(1)(i), the containment penetration bellows fatigue

analysis remains valid for the period of extended operation.

4.6.2 Staff Evaluation

The staff has reviewed the technical information in Section 4.6 of the LRA regarding fatigue of

primary containment, attached piping, and components. In RAI 4.6, the staff requested

justification for the statement that "in the absence of hydrodynamic loads, fatigue is not a

concern in containment design, except at penetrations or other stress concentration areas." The

applicant stated that the primary containments for Dresden and Quad Cities were initially

designed in accordance with ASME Code, Section III, 1965 Edition, with Addenda up to and

including Winter 1965. These containments are Mark I containments that were originally

designed to stress limits without requiring fatigue analyses (Class B vessels). The discovery of

significant hydrodynamic loads caused by SRV discharges and small, intermediate and design

basis pipe break discharges into the torus suppression pool, for which the containment had not

been initially analyzed, was identified as an unresolved safety issue by the NRC, requiring the

reanalysis of the torus, vents, and torus attached piping and internal structures, including

fatigue analysis at limiting locations. The generic suppression pool hydrodynamic load

definition and structural assessment techniques that were to be used to design plant

modifications necessary to restore the Mark I containments were described in NUREG-0661,

"Safety Evaluation Report-Mark I Containment Long Term Program." This report specified a

long-term program to establish the structural and mechanical elements that were to be

analyzed in a plant unique analysis. The long-term program plant-unique analyses for Dresden

and Quad Cities were reported in a PUAR for each plant, which demonstrated that all applicable

Mark I criteria in NUREG-0661 had been met. The NRC staff performed a post-implementation

audit review of the PUARs and concluded that with the required containment modifications, the

original design margins of the containment had been restored. The staff has reviewed this

response and concludes that the applicant has provided satisfactory justification for the

statement questioned in RAI 4.6.

The applicant's supplement for the Dresden and Quad Cities UFSARs regarding containment

fatigue is provided in Section A.3.4 of the LRA. The staff has reviewed this supplement and

finds it acceptable because it provides a reasonable summary of the information presented in

Section 4.6 of the LRA.

4.6.2.1 Fatigue Analysis of the Suppression Chamber, Vents, and Downcomers

The staff has reviewed the technical information in Section 4.6.1 of the LRA regarding the

fatigue TLAA of the suppression chamber,-vents, and downcomers. The staff has also

reviewed the applicant's disposition of this TLAA and finds it acceptable because the applicant

has selected a threshold limit of CUF=0.4 for 40 years of operation as a criterion for

determining if the fatigue analyses performed under the Dresden and Quad Cities PUARs will

remain valid for the period of extended operation. The staff concurs with the applicant that this

criterion will provide additional analytical or event margin over the minimum CUF value of 0.666

for the period of extended operation. Those locations not exceeding the threshold criterion will

therefore remain valid for the period of extended operation, in accordance with 10 CFR

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54.21(c)(1)(i). In accordance with 10 CFR 54.21(c)(1)(iii), for locations where the CUF exceeds

the criterion above, the staff finds the applicant's commitment to manage the effects of fatigue

for the period of extended operation with the Metal Fatigue AMP (B.1.34) acceptable because it

will provide assurance that the monitored CUF at a location will not exceed the ASME Code,

Section III CUF limit of 1.0. If the CUF is projected to exceed this limit the applicant has

committed to take appropriate corrective action, as stated in Section 4.6.1 of the LRA, in

accordance with the Exelon Corrective Action Program (described in Section B.2.1 of the LRA).

This is Commitment #39 in Appendix A of this SER.

The applicant's supplement for the Dresden and Quad Cities UFSARs regarding the

suppression chamber, vents, and downcomers fatigue TLAA is provided in Section A.3.4.1 of

the LRA. The staff has reviewed this supplement and finds it acceptable because it provides a

reasonable summary of the information presented in Section 4.6.1 of the LRA.

4.6.2.2 Fatigue Analysis of Safety Relief Valve Discharge Piping Inside the Suppression

Chamber, External Suppression Chamber Attached Piping, and Associated

Penetrations

The staff has reviewed the technical information in Section 4.6.2 of the LRA regarding the

fatigue TLAA of the SRV discharge piping inside the suppression chamber, the external

suppression chamber attached piping, and the associated piping penetrations. The staff has

also reviewed the applicant's disposition of this TLAA and finds it acceptable because the

applicant has selected a threshold limit of CUF=0.4 for 40 years of operation as a criterion for

determining if the fatigue analyses performed under the Dresden and Quad Cities PUARs will

remain valid for the period of extended operation. The staff concurs with the applicant that this

criterion will provide additional analytical or event margin over the minimum CUF value of 0.666

for the period of extended operation. Those locations on the inside or outside of the piping not

exceeding the threshold criterion will therefore remain valid for the period of extended

operation, in accordance with 10 CFR 54.21(c)(1)(i). In accordance with 10 CFR

54.21 (c)(1)(iii), for locations where the CUF is projected to exceed the criterion above, the staff

finds the applicant's commitment to manage the effects of fatigue for the period of extended

operation with the Metal Fatigue AMP (B.1.34) acceptable because the AMP will provide

assurance that the monitored CUF at a location will not exceed the ASME Code, Section III

CUF limit of 1.0. This is Commitment #34 of Appendix A of this SER. The staff also finds

acceptable that the applicant will use the cycle counting capability of the Metal Fatigue AMP to

monitor the number of SRV lifts for the SRV discharge piping penetration components and

welds. This will implicitly assure that the CUF of these components will remain less than 1.0 for

the period of extended operation.

In RAI 4.6.2, the staff requested that the applicant state what corrective action will be taken if

the SRV lifts exceed the number required to ensure that the CUF at a location remains less

than 1.0. In its response, the applicant stated that a condition report is required to be

generated when the number of cycles approaches or exceeds the design allowable number.

This procedure, along with site implementing procedures, will be revised to ensure that a

condition report will be generated before exceeding any design allowable cycle limit. This will

allow appropriate corrective or mitigating actions to be taken before the number of SRV lifts

exceeds the number required to ensure that the CUF remains less than 1.0. Corrective actions

could include reanalysis of the CUF with more refined techniques or plant modifications as

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appropriate. The staff finds the response acceptable because it conforms to current industry

practice.

The applicant's supplement for the Dresden and Quad Cities UFSARs regarding the fatigue

TLAA of the SRV discharge piping inside the suppression chamber, the external suppression

chamber attached piping, and the associated penetrations is provided in Section A.3.4.2 of the

LRA. The staff has reviewed this supplement and finds it acceptable because it provides a

reasonable summary of the information presented in Section 4.6.2 of the LRA.

4.6.2.3 Drywell-to-Suppression Chamber Vent Line Bellows Fatigue Analyses

The staff has reviewed the technical information in Section 4.6.3 of the LRA regarding the

fatigue TLAA of the drywell-to-suppression chamber vent line bellows. The staff has also

reviewed the applicant's disposition of this TLAA and finds it acceptable because the applicant

has demonstrated that in accordance with 10 CFR 54.21 (c)(1 )(i), the rated cyclic capacity of the

drywell-to-suppression chamber vent line bellows is adequate for the number of pressure and

temperature cycles expected during the period of extended operation.

The applicant's supplement for the Dresden and Quad Cities UFSARs regarding the fatigue

TLAA of the drywell-to-suppression chamber vent line bellows is provided in Section A.3.4.3 of

the LRA. The staff has reviewed this supplement and finds it acceptable because it reflects the

information presented in Section 4.6.3 of the LRA.

4.6.2.4 Primary Containment Process Penetration Bellows Fatigue Analysis

The staff has reviewed the technical information in Section 4.6.4 of the LRA regarding the

fatigue TLAA of the primary containment process penetration bellows. The staff has also

reviewed the applicant's disposition of this TLAA and finds it acceptable because the applicant

has demonstrated that in accordance with 10 CFR 54.21 (c)(1)(i), the rated cyclic capacity of the

drywell-to-shell vent line bellows is adequate for the number of thermal cycles expected during

the period of extended operation.

The applicant's supplement for the Dresden and Quad Cities UFSARs regarding the fatigue

TLAA of the primary containment process penetration bellows is provided in Section A.3.4.3 of

the LRA. The staff has reviewed the supplemental section and finds it acceptable because it

provides a reasonable summary of the information presented in Section 4.6.3 of the LRA.

4.6.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21 (c)(1 )(i) and 10 CFR 54.21 (c)(1 )(iii), that the analyses

remain valid for the period of extended operation. Further, the effects of aging on the intended

functions will be adequately managed for the period of extended operation for the fatigue

analysis of the suppression chamber, vents, and downcomers and the fatigue analysis of safety

relief valve discharge piping inside the suppression chamber, external suppression chamber

attached piping, and associated penetrations TLAAs. The staff also concludes that the UFSAR

Supplement contains an appropriate summary description of the fatigue analysis of the

suppression chamber, vents, and downcomers and the fatigue analysis of safety relief valve

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discharge piping inside the suppression chamber, external suppression chamber attached

piping, and associated penetrations TLAA evaluations for the period of extended operation, as

required by 10 CFR 54.21 (d).

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21 (c)(1)(i), that the analyses remain valid for the period

of extended operation for the drywell-to-suppression chamber vent line bellows and the primary

containment process penetration bellows fatigue analysis TLAAs. The staff also concludes that

the UFSAR Supplement contains an appropriate summary description of the fatigue analysis of

the drywell-to-suppression chamber vent line bellows fatigue analyses and the primary

containment process penetration bellows fatigue analysis TLAA evaluations for the period of

extended operation, as required by 10 CFR 54.21(d).

Therefore, the staff has reasonable assurance that the safety margins established and

maintained during the current operating term will be maintained during the period of extended

operation, as required by 10 CFR 54.21(c)(1).

4.7 Other Plant-Specific Time-Limited Aging Analyses

4.7.1 Reactor Building Crane Load Cycles

4.7.1.1 Summary of Technical Information in the Application

The applicant stated that the reactor building overhead cranes at Dresden and Quad Cities

were designed to meet the design fatigue loading requirements of the Crane Manufacturers

Association of America (CMAA) Specification 70, Class Al. This evaluation of expected cycles

over a 40-year plant life is the basis of a safety determination and is therefore a TLAA.

The applicant stated that the reactor building overhead crane is designed for 100,000 loading

cycles. The weldments are categories B and C, which permit a stress range of 28,000-33,000

psi. The maximum allowable stress in the girders with rated load is 17,600 psi and the

minimum stress (no load) is approximately 2,400 psi. The maximum stress range in the girders

will not exceed 15,200 psi. Because the maximum stress permitted in other weldments is

14,000 psi, they have a smaller range and better fatigue resistance than the girders. According

to the applicant these ranges are satisfactory for approximately 2 million loading cycles. This

would be equivalent to approximately 50,000 125-ton loads per year handled in the center of

the span over a 40-year period.

The applicant estimated that these cranes will see fewer than 5000 cycles at rated capacity and

a larger number of cycles at significantly less than rated capacity. For this reason, the applicant

indicated that fatigue life is not significant to the operation of this equipment.

4.7.1.2 Staff Evaluation

The reactor building cranes are designed to CMAA-70 Class Al. Based on its review of the

design evaluations the staff concurs with the applicant that all components are qualified for

100,000 loading cycles (i.e., 100,000 lifts at rated capacity). The staff also concurs with the

applicant's estimate of the maximum stress ranges of 15,200 psi and 14,000 psi for the reactor

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building overhead cranes and the weldments respectively The 40-year estimated cycles equal

most 5000 rated-capacity load cycles, or up to 7500 if extended to a 60-year life. The 60-year,

7,500-cycle estimate remains a small fraction of the 100,000 cycle minimum design. Therefore,

fatigue life is not significant to the operation of this equipment and remains valid for the period

of extended operation. The applicant has provided a satisfactory validation of 10 CFR

54.21 (c)(1)(i).

4.7.1.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21 (c)(1)(i) that the analyses remain valid for the reactor

building crane load cycles TLAA. The staff also concludes that the UFSAR Supplement

contains an appropriate summary description of the reactor building crane load cycles TLAA

evaluation for the period of extended operation, as required by 10 CFR 54.21 (d). Therefore,

the staff has reasonable assurance that the safety margins established and maintained during

the current operating term will be maintained during the period of extended operation, as

required by 10 CFR 54.21 (c)(1).

4.7.2 Metal Corrosion

4.7.2.1 Corrosion Allowance for Power-Operated Relief Valves

4.7.2.1.1 Summary of Technical Information in the Application

The applicant stated in Section 4.7.2.1 of the LRA, "Corrosion Allowance for Power Operated

Relief Valves," that power-operated relief valves (PORVs) were installed at Quad Cities in 1995

to replace the main steam line electromagnetic relief valves. The specification for the PORVs is

cited in the Quad Cities UFSAR Section 5.2.2. These valves were designed with a corrosion

allowance for 40 years of operation. The evaluation of the effects of corrosion on these PORVs

is based on a predicted corrosion rate for the plant lifetime and is therefore a TLAA. The

applicant stated that because the valves were installed more than 20 years into the current

license, the corrosion rate and allowance remain applicable for the period of extended

operation.

4.7.2.1.2 Staff Evaluation

The staff concurs with the applicant that the 40-year PORVs corrosion rate and the corrosion

allowance remain valid since the remaining life of the PORVs will exceed the period of extended

operation. The staff concludes that, in accordance with 10 CFR 54.21(c)(1)(i), the applicant

has demonstrated that the margin against excessive corrosion which is specified for 40-year

plant life will be maintained during the period of extended operation.

In RAI 4.7.2.1, the staff requested that the applicant include a section in the supplement to the

UFSARs regarding the corrosion allowance TLAA for PORVs. In its response dated December

17, 2003, the applicant provided supplemental Section A.3.5.2.3 and committed to include it in

the UFSARs supplements. Subsequently, the staff reviewed page A-57 of the applicant's

submittal dated March 5, 2004 and found that Section A.3.5.2.1 of the UFSAR Supplement

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clarified that the corrosion allowance for the Quad Cities, Unit 2 PORVs were evaluated and

found to be valid for the period of extended operation. The staff finds this acceptable.

4.7.2.1.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21 (c)(1 )(i) that the analyses remain valid for the

corrosion allowance for PORV TLAA. The staff also concludes that the UFSAR Supplement

contains an appropriate summary description of the corrosion allowance for PORV TLAA

evaluation for the period of extended operation, as required by 10 CFR 54.21 (d). Therefore,

the staff has reasonable assurance that the safety margins established and maintained during

the current operating term will be maintained during the period of extended operation, as

required by 10 CFR 54.21 (c)(1).

4.7.2.2 Degradation Rates of Inaccessible Exterior Drywell Plate Surfaces

4.7.2.2.1 Summary of Technical Information in the Application

In Section 4.7.2.2 of the LRA, the applicant stated that the Mark I containment design (all four

units) includes an inaccessible 'sand pocket' around the drywell. The applicant recognized that

the potential for degradation of the containment exists because of conditions that allow the

introduction of water into the annulus (expansion gap) between the containment and the

primary containment shield wall. Water can be introduced from leakage of the refuel cavity past

the refueling bellows drain line expansion joints during refueling or because of the introduction

of water at other drywell penetrations. This water migrates to the sand pocket under the bottom

elevation of the containment and then passes through the sand pocket drain lines. The

applicant explains that if the drain lines become clogged, the water remains in the sand pocket

and creates an environment that may be corrosive to the containment steel plates.

In response to GL 87-05, "Potential Degradation of Mark I Drywell," Dresden and Quad Cities

projected corrosion rates for the steel drywell plates in this area and determined that the wall

thickness was sufficient for the remainder of the 40-year license period. The applicant's

evaluation of the remaining life of the drywell steel thickness based on a specified corrosion

rate is a TLAA.

Also in response to GL 87-05, the applicant stated that it performed an inspection of the drain

lines on all four units to detect leakage in the pocket region. As a result of these actions, the

applicant determined that the sand pocket drains were clogged on Dresden Unit 3 and

performed an evaluation of actual plate thickness on this unit. The applicant also stated that

the design of the Dresden Unit 3 containment vessel is such that margin exists between the

required shell thickness and the actual thickness of the steel plate provided. A reevaluation of

the required shell thickness in the region of the sand pocket was performed based on loads and

data compatible with the original certified containment vessel stress report by Chicago Bridge &

Iron Company. It was determined that the thickness of the plates in the sand pocket region

may be reduced to approximately 0.25 in. below the nominal and still be within ASME Code

allowable stress limits.

Actual UT thickness measurements were made of the Dresden Unit 3 drywell steel plate at the

sand pocket level. All thickness measurements were on the high side (above the nominal

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1.0625 in.). The measurements were taken during the 18th year-of operation for Dresden Unit

3. In response to GL 87-05, the applicant stated that it made conservative estimates of

corrosion rates that might occur. Starting with the minimum as-found steel plate thickness of

1.08 in. and assuming a corrosion rate of 0.01 in. per year, the applicant indicated that 27 years

of service would remain before the effects of corrosion on stresses would become significant.

The corrosion rate was based upon a worst-case rate of 10 mils per year (miVy) for fresh river

water.

The final response to GL 87-05 indicated that the amount of moisture found in the sand pocket

drains at Quad Cities was negligible in comparison to that at Dresden Unit 3 and that it was not

expected that any corrosion occurred on either unit. The final response also indicated that

there was no reason to expect adverse thickness of the drywell liner on Dresden Unit 2.

However, the Dresden Unit 3 plate thickness estimates were used to bound Dresden Unit 2 and

both units at Quad Cities. The conservatively analyzed years of service life (18 + 27 = 45)

would not be sufficient for the extended license period.

Based on the above findings, the applicant used the provision of 10 CFR 54.21 (c)(1 )(ii) (i.e., the

projected analysis will be valid during and to the end of the extended period of operation), to

state the following:

The corrosion rate assumptions used in the calculation will be confirmed by a UT inspection prior

to the period of extended operation. The inspection will be performed at Dresden and the results

will be used to revise the corrosion calculation and validate that an acceptable wall thickness will

remain to the end of the 60 year license operating period.

4.7.2.2.2 Staff Evaluation

The staff has identified the following three principal concerns regarding the applicant's analysis:

* failure to address the preventive measures that would alleviate the root cause of the

problem (i.e., preventing water leakage from refueling canal)

* sole dependence on Dresden Unit 3 examinations for monitoring the condition of the drywell

shell in the other units

* no consideration of potential drywell shell corrosion in the inaccessible portion of the straight

portion of the drywell

In Section 4.7.2.2.1 of this SER, the applicant recognized the root cause and stated the

following:

The potential for degradation of the containment exists due to conditions that allow the introduction

of water into the annulus (expansion gap) between the containment and the primary containment

shield wall. Water can be introduced due to leakage of the refuel cavity past the refueling bellows

drain line expansion joints during refueling or due to the introduction of water at other drywell

penetrations. This water migrates to the sand pocket under the bottom elevation of the

containment and then passes through the sand pocket drain lines.

The applicant explained that if the drain lines become clogged, the water remains in the sand

pocket and creates an environment that may be corrosive to the containment steel plates.

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I

In RAI 2.4-3, the staff requested information regarding the aging management of refueling

seals through which the water has leaked in the past and is likely to leak during the extended

period of operation. The applicant provided the following partial response:

The refueling seals (the drywell-to-reactor building refueling) seal and the reactor pressure vessel

(RPV)-to-drywell refueling are not safety-related, and they are not relied upon to remain functional

during design basis events to ensure (i) the integrity of the reactor coolant pressure boundary, (ii)

the capability to shutdown the reactor and maintain it in a safe shutdown condition, or (iii) the

capability to prevent or mitigate potential offsite exposures comparable to those referred to in 10

CFR 50.34(a)(1), 50.67(b)(2), or 100.11. Thus, the refueling seals are not brought into scope of

license renewal by 10 CFR 54.4(a)(1).

The staff reviewed the applicant's response and identified the following potential concerns

resulting from the water leakage through the drywell-to-refueling (DR) seal:

* corrosion of the steel shell between the straight portion of the drywell and the containment

shield wall

* corrosion of the steel shell in the sand pocket areas

A small amount of water leakage may be absorbed by the insulation in the annulus space and

may not affect the sand cushion areas. However, this moisture accumulation could corrode the

drywell shell plate. The applicant's TLAA addresses only the corrosion of the shell in the sand

pocket areas. The steel shell in the annulus area is inaccessible for direct inspection.

Based on industry-wide and plant-specific operating experience with the performance of the DR

seal, the staff believes that managing the performance of this seal will minimize the potential for

corrosion in both these areas. Accordingly, to complete its review, the staff requested the

applicant to provide the following supplemental information:

* the methodology for managing the potential corrosion of the drywell shell in the inaccessible

annulus areas.

* justification for not managing the DR seal as a preventive measure against corrosion of the

drywell shell plate.

In its response, the applicant emphasized that no operating experience records were found to

support an assumption that water had actually accumulated in this area and that related wall

thinning had actually occurred. However, the applicant also agreed that, "Potential corrosion

that could lead to wall thinning of the annulus areas of the drywell shell can be postulated

based upon an assumption of moisture accumulation in the annulus space." The applicant also

discussed the industry experience related to corrosion of the cylindrical portion of the drywell,

and proposed the following monitoring program:

Exelon proposes that a monitoring program be instituted for the Dresden Unit 3 inaccessible

annulus areas to ensure that potential corrosion has not occurred . As previously described,

Dresden Unit 3 is considered the limiting case for potential drywell corrosion among the four

Dresden and Quad Cities units.

The program will consist of inspection of a sample of locations in the cylindrical and upper

spherical areas of the drywell, using ultrasonic measurements of the drywell shell thickness made

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from accessible areas of the drywell interior. A minimum of four sample locations will be selected

in each 90-degree quadrant of the drywell. At least one of the four sample locations will be

performed in the spherical portion of the drywell below the annulus region in proximity to the

location of the 1986 drywell liner fire.

A baseline inspection will be performed prior to the period of extended operation. A follow-up

inspection consisting partly of the same locations and partly of variable locations will be based on

the operating experience records, Exelon believes no detrimental corrosion has or will occur on the

exterior of the cylindrical portion of the drywell shell. Regardless, Exelon proposes that a

monitoring program be instituted for the Dresden Unit 3 inaccessible annulus areas to ensure that

potential corrosion does not occur. As previously described, Dresden Unit 3 is considered the

limiting case for potential drywell corrosion among the four Dresden and Quad Cities units.

As the same location will allow trending of wall thickness data, variable locations will allow flexibility

to ensure that wall thickness integrity is maintained during the period of extended operation. The

follow-up inspection will be used to determine whether any corrosion is occurring and that any

observed corrosion rate will not threaten drywell integrity during the extended 60-year plant life.

The results of the inspections will undergo an engineering evaluation to determine if further

follow-up inspections are warranted, or if more locations in the accessible drywell liner interior

should be monitored.

These inspections will be added to LR program B.1.26, ASME Section Xl, Subsection IWE, for

Dresden 3.

This is part of Commitment #26 of Appendix A of this SER. The staff finds the proposed

monitoring program acceptable, as it will ensure that any corrosion occurring in the inaccessible

areas of the cylindrical and spherical portions of the drywell will be monitored and trended, and

corrective actions will be taken to ensure the integrity of the drywell during the extended period

of operation.

Regarding the second concern, the staff reviewed the applicant's detailed response to

RAI 3.5-5, which includes a table showing the UT measurements of the Dresden Unit 3 shell

during the inspections performed in 1988, 1997, 1998, 2000, and 2002. The staff finds the

applicant's justification for not performing periodic UT examination for the remaining three units

acceptable, provided th6 applicant has in place a surveillance program to periodically verify the

performance of sand-pocket drains in all units. The measured shell wall thickness in Dresden

Unit 3 (based on the table) is well within the 10 percent allowable reduction of Subsection IWE

of the ASME Code. However, the 0.25 in. allowable corrosion limit (about 25 percent of the

shell thickness), which has been established as the long-term acceptance criterion, appears to

be excessive. To address this concern regarding the corrosion of the drywell steel plate and to

complete its review, the staff requested the following supplemental information:

* clarification of whether the performance of sand drains is (and will be) monitored at every

outage on all four units.

* clarification of where the engineering evaluation performed to set the 0.25 in. (below the

nominal thickness of the shell) criterion incorporates the effects of discontinuities and stress

concentration under all load combinations. Provide a summary of the calculations

performed.

* the procedures used for re-coating any corroded steel areas.

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In its response, the applicant provided the following information about the drywell liner

surveillance program:

* Dresden and Quad Cities conduct a surveillance of the drywell liner drains once per

operating cycle to make sure that there is no leakage from the drywell liner sand pocket

drain lines on all four units. The surveillance is conducted during refueling operations when

the refueling cavity is flooded and the potential for water leakage exists. These surveillances

are conducted under the direction of Quad Cities Technical Specification 0820-11,

"Surveillance of Dryer Separator Pool, Spent Fuel Pool, and Drywell Liner Drains," and

Dresden Quad Technical Specifications 1600-06, "Drywell Liner Leakage Inspection." Both

site procedures have been credited for aging management and are included under aging

management program B.1.26, ASME Code, Section Xl, Subsection IWE.

* In response to a follow-up question from the staff, the applicant also stated that the Dresden

inspection procedure currently includes steps to ensure that the sand pocket drains are

clear. A similar requirement will be added to the Quad Cities procedure. This is part of

Commitment #26 of Appendix A of this SER.

* As stated in the response to RAI 3.5-5(b), the reference to a minimum required plate

thickness of 0.25 in. below nominal at the sand pocket region is based on information

contained in Section 6.2.1.2.1.2 of the Dresden UFSAR. The calculation took the existing

design loads and load combinations from the original certified containment vessel stress

report generated by Chicago Bridge & Iron Company, and used those cases to calculate the

minimum required thickness. Normal operating, refueling, and accident loads were included

in the calculation using ASME Code Case N-284 stress allowable limits.

* As stated in the applicant's response to RAI 3.5-5(b), initial thickness measurements

supported the conclusion that significant corrosion was not occurring in the drywell steel

plate at the sand pocket region. All measurements to date at Dresden Unit 3 have

remained within the 10 percent limit below nominal of Subsection IWE of the ASME Code

(most measurements are still above nominal wall thickness). Evaluations performed

following the fire in 1986 concluded that the zinc chromate primer coat on the outer shell

surface was intact following the fire, and that no corrosion had taken place. No recoating

activities have been performed on the drywell exterior. Any recoating activities performed

on the drywell interior are performed using proper procedures. No recoating activities

performed to date are related to corrosion of the sand pocket region.

With the procedural commitment to inspect the sand pocket drains in all four units of Dresden

and Quad Cities, and to explicitly describe the procedure for evaluating the corroded areas,

when found, the staff finds the applicant's response acceptable. This is Commitment #50 in

Appendix A of this SER.

A review of the UT measurement table provided as part of the applicant's response to RAI 3.5-5

indicates that within two digits after the decimal points, there is no consistency in the measured

results. Some measurements taken at the same locations (e.g., locations 157.5.1.1A and

202.5.1.1A) show an increase in thicknesses in subsequent years, after the 1988

measurements. To complete its review, the staff requested the following supplemental

information regarding these measurements:

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O
* Provide the basis for selecting the locations where the UT measurements are taken. State

whether the measurement locations indicated in the table have shown visual evidence of

corrosion, or if they are in close proximity to the corroded areas.

* One location, 337.5.1.2B, shows gradually decreasing thickness, with a total reduction in

thickness of 0.18 in. Although the minimum thicknessis still close to the nominal thickness,

indicate if this reduction implies a 0.18 in corrosion of the shell at that location between

1988 and 2002.

* State whether the nominal thickness of 1.0625 in. is the same for the drywell shells in all

four units.

* Provide the permissible tolerances of the nominal shell thickness in the as-delivered

condition. Indicate if the records of the actual as-delivered thicknesses are available.

* Provide a discussion of the accuracy of the UT measurements.

In response, the applicant provided the following additional information for evaluating the

existing corrosion in the Dresden Unit 3 sand pocket areas:

* The UT measurements are taken at various locations around the floor of the Dresden Unit 3

drywell in the sand pocket region. This area was chosen in 1988 as the most likely area to

experience potential corrosion resulting from the presence of moisture (Reference 1). The

drywell floor is a poured concrete slab that fills the bottom portion of the steel enclosure to

an elevation of 502'-4" (refer to elevation view of the containment sand pocket, Figure 6.2-9

of Dresden UFSAR). The slab was divided into sectors and measurement locations were

selected at random within each sector. The process used a standard statistical sampling

basis. Certain portions of the floor slab are inaccessible because of equipment mounted on

the floor. These locations are therefore not part of the measurement population. This

sampling approach was described in detail in the August 1988 letter from ComEd (W.E.

Morgan) to the NRC.

* The shell was made accessible for measurement by drilling 2.5 in. core holes in the

concrete at 22 accessible measurement locations. The holes range in depth from 1 to 3

feet, and are capped during normal plant operation. The UT probe is inserted into each

hole to provide the thickness measurement. No visual inspection of the shell is possible

because of the slab inside the steel liner and the sand pocket outside the steel liner.

* Evaluations performed following the fire in 1986 concluded that the zinc chromate primer

coat on the outer shell surface was intact following the fire, and that no corrosion had taken

place.

* The point in question had an abnormally high reading in the 1988 measurements. In the

Reference 1 submission, it was speculated that one non-standard plate section could have

been substituted in the drywell shell, resulting in thickness measurements exceeding the

nominal tolerance on the high side at some locations. However the recent measurements

from 1997-2002 have been relatively consistent at all of these locations and do not provide

indication of progressive wall thinning.

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* The drywell shell thickness varies throughout the structure. The nominal thickness of

1.0625 in. in the sand pocket region applies to Dresden, and bounds the Quad Cities

nominal thickness of 1.25 in. in the same area.

* No as-delivered thickness measurements are available. Based upon normal mill tolerances

for 1-1/16 in. plate a range from 1.0525 in. to 1.1755 in. could be expected.

* The initial UT measurements in 1988 were performed with an instrument calibrated to

0.020 in., using a carbon steel standard ranging in thickness from 0.25 in. to 2.0 in. (as

described in the August 1988 letter). The instrumentation in use for current UT

measurements should attain comparable accuracy. Per current Exelon ultrasonic

measurement procedures, UT instrumentation for material thickness measurements is

calibrated to an accuracy of 2 percent, which is the same accuracy that was used in 1988.

This response provides the process used in evaluating the findings of corrosion in the sand

pocket areas of Dresden Unit 3. The staff has reviewed this response and finds the sampling

and measurement calibration process used in the evaluation to be acceptable, as the TLAA

based on these initial findings will be continued through the period of extended operation, and

will ensure the integrity of the containment drywells at Dresden and Quad Cities.

In Section A.3.5.2.1 (UFSAR Supplement) of the LRA, the applicant summarized this TLAA and

reiterated that the calculations will be revised for the realistic environment and for a full 60-year

design life in accordance with 10 CFR 50.54.21 (c)(1)(ii). The staff finds the UFSAR

Supplement adequate.

4.7.2.2.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21 (c)(1)(ii), that the analyses have been projected to the

end of the period of extended operation for the degradation rates of inaccessible exterior

drywell plate surfaces TLAA. The staff also concludes that the UFSAR Supplement contains an

appropriate summary description of the degradation rates of inaccessible exterior drywell plate

surfaces TLAA evaluation for the period of extended operation, as required by 10 CFR

54.21 (d). Therefore, the staff has reasonable assurance that the safety margins established

and maintained during the current operating term will be maintained during the period of

extended operation, as required by 10 CFR 54.21 (c)(1).

4. 7.2.3 Galvanic Corrosion in the Containment Shell and Attached Piping Components due to

Stainless Steel Emergency Core Cooling System Suction Strainers

4.7.2.3.1 Summary of Technical Information in the Application

In Section 4.2.7.3 of the LRA, the applicant stated that suction strainers at Dresden and Quad

Cities were replaced with larger stainless steel strainers, to address potential plugging and

unacceptable head loss concerns. This modification created direct contact between the carbon

steel support flanges and the stainless steel strainer components through uncoated bolt holes

in the carbon steel flanges, resulting in galvanic corrosion effects. The evaluation of the effects

of galvanic corrosion on the ECCS suction strainer flanges is based on a predicted corrosion

rate for the plant lifetime and is therefore a TLAA. The calculation of the corrosion effects on

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the support flanges assumes a corrosion rate of 4 miVy and a design life of 33 years, which is

not sufficient to encompass the entire period of extended operation.

4.7.2.3.2 Staff Evaluation

In RAI 4.7.2.3(a), the staff requested that the applicant describe (1) the nature of the TLAA

calculations and the basis for the assumed corrosion rate of 4 miVy for 33 years used in the

calculation, and to (2) substantiate that this is a bounding corrosion rate for all foreseeable

conditions in both plants, including any credible nonstandard water chemistry conditions.

The applicant stated that calculations were performed to evaluate and qualify the bolted flange.

connections between the ECCS suction strainers and the associated torus penetration nozzles.

During an earlier NRC review of the modifications associated with the replacement of the -

suction strainers, the NRC identified a concern that the calculations did not sufficiently account

for the effects of galvanic corrosion. These calculations were revised to include a corrosion

allowance in the determination of the stresses at the bolt circles in the existing carbon steel

flanges, in accordance with ASME Code, Section III, Subsection NC, 1977 Edition with Summer

1997 Addenda.

The corrosion rate (4 miVy) was obtained from Uhlig's Corrosion Handbook, 2 nd Edition, a

standard industrial reference source on corrosion. The revised calculation did not include any

specific consideration of nonstandard water chemistry conditions. However, the subject

strainers are located within the suppression chambers of the respective units. Water quality is

maintained within strict limits and sampled quarterly in accordance with plant procedures. It is

sampled frequently enough to allow prompt identification and correction of any nonstandard

water chemistry conditions capable of increasing corrosion of the flanges. The staff finds the

applicant's justification acceptable because it conforms with standard industry practice.

In RAI 4.7.2.3(b), the applicant was requested to show how the location of a single ultrasonic

inspection, to confirm the assumptions used in the corrosion rate calculations will be selected,

and how it will represent the most aggressive corrosion conditions in both plants. The applicant

stated that UT inspections will be performed on a randomly selected flange in each Dresden

unit. Initial thickness measurements will be made at two to four adjacent bolt locations on the

flange. Separate thickness measurements at the same locations will be made in a subsequent

outage to establish the actual corrosion rate. The applicant also stated that this method of

selection is acceptable to provide assurance that the results are representative of the most

aggressive corrosion conditions at both plants because (1) the water chemistries are similar at

each site and are required to be maintained within limits established by the same procedures,

(2) the strainers at both plants were installed in approximately the same time frame

(1997/1998), and (3) the strainer flange configurations are similar at both plants. The staff finds

that the applicant has provided a reasonable procedure for determining corrosion rates, and

has provided adequate justification to show that the corrosion rates will be similar for all ECCS

strainer flanges at both plants.

In RAI 4.7.2.3(c), the applicant was requested to state the corrective measures that will be

taken in the event that the revised galvanic corrosion calculation indicates that an unacceptable

reduced flange wall thickness will be reached before the end of the period of extended

operation. The applicant stated that in this event, the Exelon Corrective Action Program will be

used to develop appropriate corrective actions, among which are the inspection of additional

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flanges, establishment of root causes and corrective actions including periodic UT inspections

of the affected flanges, and implementation of possible modifications and/or replacement of the

affected flanges and/or interfacing components. The staff finds this acceptable because the

applicant has made a commitment to take appropriate measures in the event that galvanic

corrosion is determined to potentially affect the structural integrity of the strainer flanges and

suppression chamber attachments. This is Commitment #50 in Appendix A of this SER.

The staff has also reviewed Section A.3.5.2.2 in the supplement to the Dresden and Quad

Cities UFSARs. The section does not reflect the applicant's commitment to take appropriate

measures in the event that galvanic corrosion is determined to potentially affect the structural

integrity of the strainer flanges and suppression chamber attachments. In RAI A.3.5.2.2, the

applicant was requested to include the commitment to take the appropriate measures in the

supplement to the UFSARs. The applicant stated in its response to the RAI, dated December

17, 2003, that a statement will be added to the UFSAR section stating that in the event that the

measured galvanic corrosion rate will not ensure acceptable thickness to the end of the 60-year

licensed operating period, appropriate corrective action will be identified and implemented to

maintain the structural integrity of the strainer flanges. With this additional information, the staff

finds Section A.3.5.2.2 acceptable, because it provides a reasonable summary of the

information presented in Section 4.7.2.3 of the LRA.

4.7.2.3.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21 (c)(1)(ii), that the analyses have been projected to the

end of the period of extended operation for the galvanic corrosion in the containment shell and

attached piping components caused by stainless steel emergency core cooling system suction

strainers TLAA. The staff also concludes that the UFSAR Supplement contains an appropriate

summary description of the galvanic corrosion in the containment shell and attached piping

components caused by stainless steel emergency core cooling system suction strainers TLAA

evaluation for the period of extended operation, as required by 10 CFR 54.21 (d). Therefore,

the staff has reasonable assurance that the safety margins established and maintained during

the current operating term will be maintained during the period of extended operation, as

required by 10 CFR 54.21 (c)(1).

4.7.3 Crack Growth Calculation of a Postulated Flaw in the Heat Affected Zone of an Arc

Strike in the Suppression Chamber Shell

4.7.3.1 Summary of Technical Information in the Application

The applicant reported in the LRA that arc strikes found during 1990 in the Dresden and Quad

Cities suppression chamber walls were evaluated using a common analysis. The evaluation

included crack growth calculations that assumed 850 load cycles resulting from SRV and other

operations over 40 years of plant life. A further evaluation in 1997 determined that the depth of

the arc strike at Dresden was not sufficient to warrant any final repairs. Assuming an operating

limit of 850 SRV load cycles, the applicant indicated that no further action was warranted. The

applicant performed an ultrasonic measurement at Quad Cities that it claimed validated that no

flaw existed in the heat-affected zone of the original arc strike. The applicant performed an

evaluation and determined that further repairs or inspections were not warranted.

4-54
The LRA noted that the number of.SRV actuations used in the QUad Cities containment

analysis is 550 for 40 years compared to the 850 actuations assumed for the flaw evaluation.

The applicant stated that the expected number of SRV actuations from the year that the flaw

was repaired (1990) to the end of the extended operating period in 2032 would be at most

(550/40) x (2032-1990) = 577.5, which is less than the 850 actuations assumed for flaw

evaluation. Therefore, the applicant indicated that the evaluation remains valid for Quad Cities

for the extended period of operation.

The LRA noted that the number of SRV actuations used in the Dresden containment analysis is

300 for 40 years compared to the 850 actuations assumed for the flaw evaluation. The current

license for Dresden Unit 3 will expire in 2011, and the Dresden flaw was repaired in 1991. The

applicant stated that the expected number of SRV actuations from the year the flaw was

repaired to the end of the extended operating period in 2031 would be at the most (300/40) x

(2031-1991) = 300, which is less than the 850 actuations assumed for the flaw evaluation.

Therefore, the applicant indicated that the evaluation remains valid for Dresden for the

extended period of operation.

4.7.3.2 Staff Evaluation

Per 10 CFR 54.21 (c)(1), applicants for license renewal must demonstrate that TLAAs have

been projected through the end of the period of extended operation and remain valid for the

period of extended operation. Alternatively, the applicant may demonstrate that the effects of

aging that are applicable to the components evaluated by the TLAAs will be managed during

the period of extended operation. The applicant stated that the crack growth calculations for

arc strikes will project through the end of the period of extended operation.

The staff reviewed the information provided in the LRA and in a letter dated August 7, 2003,

requested that the applicant clarify information provided on this TLAA. In RAI 4.7.3, the

applicant was requested to clarify if flaws were actually detected or were only postulated flaws,

to clarify if ASME Code Section Xl fracture mechanics methodology and acceptance criteria

were used for evaluation of crack growth, and to describe any alternative method and

acceptance criteria that were used.

In a letter dated October 3, 2003, the applicant responded to the staff's request for additional

information. The response to the RAI indicated that the flaws were largely of a postulated

nature and were assigned to bound possible damage at the arc strikes. In many cases, further

ultrasonic examination indicated that no flaws were detected at the locations of concem. The

applicant further responded that fracture mechanics evaluation applied the acceptance criteria

of the ASME Code as defined in NUREG-0661, "Safety Evaluation Report, Mark 1 Containment

Long Term Program, Resolution of Generic Technical Activity." Because the applicant applied

the methodology of the ASME Code which has been previously approved by the staff, the staff

finds the response acceptable.

4.7.3.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21 (c)(1)(i) that the analyses remain valid for the crack

growth calculation of a postulated flaw in the heat-affected zone of an arc strike in the

suppression chamber shell TLAA. The staff also concludes that the UFSAR Supplement

4-55
contains an appropriate summary description of the crack growth calculation of a postulated

flaw in the heat-affected zone of an arc strike in the suppression chamber shell TLAA

evaluation for the period of extended operation, as required by 10 CFR 54.21 (d). Therefore,

the staff has reasonable assurance that the safety margins established and maintained during

the current operating term will be maintained during the period of extended operation, as

required by 10 CFR 54.21(c)(1).

4.7.4 Radiation Degradation of Drywell Shell Expansion Gap Polyurethane Foam

4.7.4.1 Summary of Technical Information in the Application

The applicant describes the analysis of radiation degradation of the drywell shell expansion gap

polyurethane foam in Section 4.7.4 of the LRA. The drywell shell is described as being largely

enclosed within the structural and shielding concrete of the reactor building. To accommodate

thermal expansion of the drywell, compressible foam was used to form an expansion gap

between the concrete and the drywell shell. An analysis performed by the applicant evaluated

the increase in external compressive loads on the drywell exterior from additional compression

of this foam for normal, refuel, and accident conditions. The effect on this analysis of a

postulated increase in the foam stiffness resulting from a radiation dose is a TLAA.

The applicant stated that the polyurethane foam material was chosen for its resistance to the

environmental conditions likely to exist during its service life and with characteristics such that

the effects of compression during a LOCA resulting in thermal expansion of the drywell would

not exceed ASME Code allowable limits. Test results established that there was no detectable

change in resilience bel9w 108 rads. The original design considered the effects of a 40-year

lifetime dose of 2.5 x 10 rads on the foam material. Thus, the applicant stated that the resilient

characteristics of the polyurethane foam will remain intact during the 40-year design life.

The LRA indicated that a 20-year increase in the design lifetime to 60 years, combined with

approvesi increases in power rating, would conservatively result in a total radiation exposure of

4.2 x 10 rads which is less than the 10 rads qualified radiation exposure. Therefore, the

applicant indicated that material properties will remain within the limits assumed by the original

design analysis, in accordance with the aging assumptions assumed by the original design, for

the 60-year extended operating period.

4.7.4.2 Staff Evaluation

Per 10 CFR 54.21 (c)(1), applicants for license renewal must demonstrate that TLAAs for

license renewal have been projected through the end of the period of extended operation for

their facilities, remain valid for the period of extended operation, or demonstrate that the effects

of aging that are applicable to the components evaluated by the TLAAs will be managed during

the period of extended operation.

The staff reviewed the information provided in the LRA and in a letter dated August 7, 2003,

requested additional information from the applicant related to the test methods used and factors

considered in determining the radiation stability of the polyurethane (RAI 4.7.4). In a letter

dated October 3, 2003, the applicant responded, noting that the irradiation testing of the

polyurethane foam was conducted more than 30 years ago and that additional information on

4-56
the tests is not available. For justification that the tests provide a satisfactory basis for

predicting of the acceptable dose within the required uncertainty limits, the applicant relied on

the test results showing no predictable loss of resiliency below 1 08 rads and the predicted end

of life exposure to be 4.2 x 10 rads. The staff identified that the polyurethane foam radiation

limit was previously reviewed by the staff in an SER, and the limit is considered part of the

applicant's CLB. The staff finds the applicant's analysis acceptable because the analysis has

been projected through the end of the period of extended operation and remains within the

limits established in the applicant's CLB.

Based on the review of the LRA and the applicant's response to RAI 4.7.4, the staff found that

the analysis performed to evaluate the effects of extended life on the radiation degradation of

the drywell shell expansion gap polyurethane foam is appropriate and provides a basis for

concluding that the safety margins established and maintained during the current operating

period will be maintained during the extended period of operation.

4.7.4.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21 (c)(1 )(i) that the analyses remain valid for the

radiation degradation of drywell shell expansion gap polyurethane foam TLAA. The staff also

concludes that the UFSAR Supplement contains an appropriate summary description of the

radiation degradation of drywell shell expansion gap polyurethane foam TLAA evaluation for the

period of extended operation, as required by 10 CFR 54.21 (d). Therefore, the staff has

reasonable assurance that the safety margins established and maintained during the current

operating term will be maintained during the period of extended operation, as required by 10

CFR 54.21 (c)(1).

4.7.5 High-Energy Line Break Postulation Based on Fatigue Cumulative Usage Factor

This issue is included only because it is listed as a possible TLAA in NUREG-1800. Neither the

Dresden nor the Quad Cities postulated break locations are based on a fatigue usage factor

criterion, nor are any break locations based on any other evaluation of fatigue effects. This is

not a TLAA for either Dresden or Quad Cities.

4.8 Conclusion for Time-Limited Aging Analyses

The staff has reviewed the information in Section 4 of the LRA. On the basis of its review,

the staff concludes that the applicant has provided an adequate list of TLAAs, as defined in

10 CFR 54.3. Further, the staff concludes that the applicant has demonstrated that the

TLAAs (1) will remain valid for the period of extended operation, as required by

10 CFR 54.21 (c)(1)(i), (2) have been projected to the end of the period of extended operation,

as required by 10 CFR 54.21 (c)(1)(ii), or (3) the aging effects will be adequately managed for

the period of extended operation, as required by 10 CFR 54.21(c)(1)(iii). In addition, the staff

concludes that there are no plant-specific exemptions in effect that are based on TLAAs,

as required by 10 CFR 54.21(c)(2). On this basis, the staff has reasonable assurance that the

aging effects associated with the structures and components subject to TLAAs will perform their

intended functions in accordance with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

4-57
5. REVIEW BY THE ADVISORY COMMITTEE ON REACTOR

SAFEGUARDS

The NRC staff issued its safety evaluation report (SER) with open items related to the renewal

of operating licenses for Dresden Nuclear Power Station, Units 2 and 3, and Quad Cities

Nuclear Power Station, Units 1 and 2, on February 12, 2004. On April 14, 2004, the applicant

presented its license renewal application, and the staff presented its review findings, to the

ACRS Plant License Renewal Subcommittee. The staff reviewed the applicant's comments on

the SER and completed its review of the license renewal application. The staff's evaluation is

documented in this SER that was issued by letter dated July 23, 2004.

During the 515th meeting of the ACRS, September 9-11, 2004, the ACRS completed its review

of the Dresden and Quad Cities license renewal application and the NRC staff's SER. The

ACRS documented its findings in a letter to the Commission dated September 16, 2004. A

copy of this letter is provided on the following pages of this SER Section. The Committee

recommended approval of the license renewal application with the inclusion of two conditions.

The staff's response to these recommendations is discussed below.

With regard to operating experience at extended power uprate (EPU) levels, the Committee

noted that Dresden and Quad Cities have limited operating time at EPU levels and the staff

should, prior to entering the period of extended operation, require that the applicant conduct an

evaluation of operating experience at all four units and at other BWR plants operating at EPU

levels. The letter also noted that all license renewal applicants that plan to operate during the

license renewal period at EPU levels that are substantially higher than experienced in the bases

supporting their license renewal applications should conduct similar evaluations of operating

experience at EPU levels. Exelon will perform such an evaluation and will submit this

evaluation to the NRC for review and approval prior to entering the period of extended

operation. This is Commitment #51 in Appendix A of this SER.

With regard to the steam dryers being in the scope of license renewal for Dresden and Quad

Cities, the Committee noted that the applicant had not provided appropriate justification for their

exclusion. The steam dryers are not safety related, but structural failure can cause pieces to

pass through safety related components, and could cause them to fail to operate properly. The

staff agrees with this recommendation and the applicant has now included the steam dryers into

the scope of license renewal for the Dresden Units 2 and 3 and Quad Cities Units 1 and 2, as

discussed in Section 2 of this SER. This is also consistent with the requirement in

10 CFR 54.4(a)(2) for structures, systems, and components within the scope of license

renewal. The staff is currently working with the industry to develop generic guidance in this

area. The aging management program would be the NRC approved Boiling Water Reactor

Vessel Internals Program (BWRVIP) Steam Dryer Inspection and Evaluation Guidelines as

approved by the staff. Exelon has committed to follow this NRC/Industry effort and has

committed to that, if the BWRVIP Steam Dryer Inspection and Evaluation Guideline is not

approved by the staff, then a plant-specific aging management program will be submitted to the

NRC for review and approval by December 22, 2007, which is 2 years before the first Dresden

unit enters the period of extended operation. This is part of Commitment #9 in Appendix A of

this SER.

5-1
- '>UNITED STATES

NUCLEAR REGULATORY COMMISSION

ADVISORY COMMI7TEE ON REACTOR SAFEGUARDS ACRSR-2091 A WASHINGTON, DC 20555- 0001

September 16, 2004

The Honorable Nils J. Diaz

Chairman

U.S. Nuclear Regulatory Commission

Washington, DC 2005-0001

SUBJECT: REPORT ON THE SAFETY ASPECTS OF THE LICENSE RENEWAL

APPLICATION FOR THE DRESDEN 2 AND 3 AND QUAD CITIES 1 AND 2

NUCLEAR POWER STATIONS

Dear Chairman Diaz:

During the 5 15th meeting of the Advisory Committee on Reactor Safeguards, September 9-11,

2004, we completed our review of the license renewal application for Dresden Units 2 and 3

and Quad Cities Units 1 and 2 Nuclear Power Stations and the final Safety Evaluation Report

(SER) prepared by the NRC staff. Our Plant License Renewal Subcommittee also reviewed

this matter during a meeting on April 14, 2004. During our review, we had the benefit of

discussions with representatives of the NRC staff and Exelon Generation Company, LLC

(Exelon). We also had the benefit of the documents referenced.

RECOMMENDATIONS AND CONCLUSION

1. With the inclusion of the conditions in Recommendations 2 and 3, the application for

license renewal for Dresden Units 2 and 3 and Quad Cities Units 1 and 2 should be

approved.

2. The staff should require that, prior to entering the period of extended operation, Exelon

conduct an evaluation to ensure that operating experience at extended power uprate

(EPU) levels is properly addressed by the aging management programs. The staff

should review and approve this evaluation.

3. The steam dryers should be included in the scope of license renewal for Dresden and

Quad Cities.

4. The staff should develop guidance to apply Recommendations 2 and 3 to future boiling

water reactor (BWR) license renewal applications.

BACKGROUND AND DISCUSSION

This report fulfills the requirement of 10 CFR 54.25, which states that the ACRS review and

report on all license renewal applications. Dresden Units 2 and 3 and Quad Cities Units 1 and 2

5-2
are General Electric BWR/3 plants, with Mark 1 containments. Exelon requested renewal of

their operating licenses for 20 years beyond the current license terms, which expire on

December 22, 2009, for Dresden Unit 2 and January 12, 2011, for Dresden Unit 3, and

December 14, 2012, for both Quad Cities units. The Dresden units were designed with

isolation condensers for core isolation cooling whereas the Quad Cities units have the more

typical reactor core isolation cooling system. The Dresden units have a separate shutdown

cooling system whereas Quad Cities units have the more typical arrangement in which

shutdown cooling is achieved as an operational mode of the residual heat removal system.

Dresden Units 2 and 3 share the site and surrounding areas with Unit 1, a dual-cycle BWR that

has been placed in a safe storage condition until Units 2 and 3 are ready for decommissioning.

Unit 1 systems, structures, and components (SSCs) which support the operation of Units 2 and

3 are included in the scope of license renewal.

The final SER documents the staff's review of the information submitted by Exelon, including

commitments that were necessary to resolve open items identified by the staff in the initial SER.

The staff reviewed the completeness of the applicant's identification of SSCs that are within the

scope of license renewal; the integrated plant assessment process; the applicant's identification

of the plausible aging mechanisms associated with passive, long-lived components; the

adequacy of the applicant's aging management programs; and the identification and

assessment of time-limited aging analyses (TLAAs) requiring review.

The staff also conducted several inspections at Exelon's engineering offices and at the Dresden

and Quad Cities sites to verify the adequacy and implementation of the methodology described

in the application. During our Plant License Renewal Subcommittee meeting on April 14, 2004,

the staff presented a well structured and effective overview of its inspections and audits.

Dresden and Quad Cities have been approved for an EPU to 2957 MWt. The EPU increased

power output by 17% at both Dresden units and 17.8% at both Quad Cities units. Shortly after

operating at the EPU level, Quad Cities Unit 2 experienced unexpected high moisture

carryover, which was caused by a damaged steam dryer. The applicant repaired the dryer and

the unit was returned to service. Shortly thereafter, similar damage was identified in Unit 1 and

then again in Unit 2. The applicant has since chosen to operate Quad Cities Units 1 and 2 at

pre-EPU power levels until the root cause of the dryer damage can be determined.

Dresden and Quad Cities have limited operating time at the EPU levels and during that period,

several problems believed to be associated with the EPU have occurred at Quad Cities. Most

notable is the steam dryer damage, but other problems with limit and pressure switches have

also occurred. After operation at the higher power level (2957 MWt), but prior to entering the

period of extended operation, the staff should require that the applicant conduct an evaluation

of operating experience at all four units and at other plants operating at EPU levels, to ensure

that this experience has been properly addressed by the aging management programs. The

staff should review and approve this evaluation.

Such an evaluation should be required of all license renewal applicants that plan to operate

during the license renewal period at EPU levels that are substantially higher than experienced

in the bases supporting their license renewal applications. Such an evaluation is consistent

with the intent of 10 CFR 54.17(c) that substantial operating experience be reflected in the

bases supporting the license renewal application. Current operating experience at EPU levels

5-3
is limited and an understanding of the impact of operation at such levels on plant components is

only now beginning to develop. A recent BWR Owners Group (BWROG) survey of EPU plants

has identified component failures, potential decreases in time between failures, unexpected

increases in component wear, and a significant number of events, which are all directly

attributable to EPUs. It is therefore important that the staff require, after sufficient plant-specific

operating experience is available at the EPU level but before entering the period of extended

operation, that license renewal applicants ensure applicable operating experience at EPU levels

has been properly addressed by aging management programs. The staff should also provide

guidance in this area.

During our review, we questioned why certain SSCs were not included in the scope and, in all

but one case, the applicant provided appropriate justification for the exclusions. That case was

the steam dryers at these plants. Although the dryers are not safety related, structural failure at

Quad Cities caused pieces to pass down the main steamlines and some of these pieces were

found on the turbine stop valve screens. These pieces passed through the Main Steam

Isolation Valves (MSIVs), which are safety related components, and could have caused these

valves to fail to operate properly. Since the MSIVs are safety related, this meets the criteria for

inclusion of the steam dryers in the scope of license renewal in accordance with 10 CFR

54.4(a)(2). The steam dryers at Dresden and Quad Cities should be included in scope even if

an analysis demonstrates that future failures are unlikely. Further, steam dryers for all BWRs

seeking license renewal should be within scope based on 10 CFR 54.4(a)(2). The staff should

develop guidance on this topic so that the NRC position on this matter is clearly understood by

the industry.

The applicant performed a comprehensive aging management review of all SSCs that are

within the scope of license renewal. The application describes 48 aging management programs

for license renewal, which include existing, augmented, and new programs. As with other

applicants, we encouraged Exelon to establish a schedule for implementing license renewal

commitments well ahead of the beginning of the license renewal period to preclude placing an

unreasonable demand on applicant and NRC resources.

Aging degradation of reactor vessel internals has been an ongoing problem in BWRs. The

applicant has committed to programs developed by the BWR Vessel and Internals Project

(BWRVIP) to manage these problems. We questioned if the clamping device installed in 1995

to mitigate core shroud cracking had been evaluated for the period of extended operation. The

applicant has committed to follow the BWRVIP-76 program, as approved by the staff, to

manage aging effects on the core shroud and other hardware. The staff is currently reviewing

this program and will evaluate the adequacy of the recommended inspection intervals in light of

the accumulating evidence of fluence, strength, and surface effects on cracking of (for

example) 31 6L and the lack of comparable data for XM-1 9 and X750.

In 1994, Dresden experienced a failure due to corrosion of the carbon steel piping to the

instrument air receiver. We questioned whether this corrosion was an ongoing aging effect.

The staff responded that this piping has been replaced with stainless steel and that the air

receiver was replaced with one having epoxy coating applied to the interior. The moisture

separator drain trap was also modified. These modifications should reduce moisture

accumulation and corrosion. The applicant has also instituted a periodic blowdown program

and no subsequent failures have occurred.

5-4
In the license renewal application, Exelon has identified the components that are supported by

TLAAs. Their review of the TLAAs shows that the analyzed components have sufficient margin

to operate for the period of extended operation.

We reviewed the Reactor Vessel Upper Shelf Energy for limiting plates and welds for all four

units. All are acceptable for the period of extended operation, including the most limiting weld

at Quad Cities Unit 2, which was found acceptable based on a plant-specific equivalent margins

analysis. We are satisfied with the staff's review of the applicant's data and calculations.

The staff is currently reviewing BWRVIP-1 16, 'BWR Integrated Surveillance Program

Implementation for License Renewal.' The applicant has agreed to a license condition to notify

the NRC, before entering the period of extended operation, of their decision to implement either

the staff-approved BWRVIP integrated surveillance program (ISP) or a staff-approved plantspecific ISP.

On the basis of our review of the final SER, we agree with the staff's conclusion that all open

and confirmatory items have been appropriately closed. We also concur with all three license

conditions requiring the applicant to take certain actions before beginning the period of

extended operation.

With the inclusion of commitments to perform an evaluation of operating experience at the EPU

levels before entering the period of extended operation and to include steam dryers in the

scope of license renewal, the application for license renewal for Dresden Units 2 and 3 and

Quad Cities Units 1 and 2 should be approved.

Sincerely

IRAI

Mario V. Bonaca

Chairman

References:

1. U.S. Nuclear Regulatory Commission, "Safety Evaluation Report Related to the License

Renewal of the Dresden Nuclear Power Station, Units 2 and 3 and Quad Cities Nuclear

Power Station, Units 1 and 2," July 2004.

2. Exelon Generation Company, "License Renewal Application for Dresden Nuclear Power

Station (DNPS), Units 2 and 3, and Quad Cities Nuclear Power Station (QCNPS), Units

1 and 2," January 2003.

3. U.S. Nuclear Regulatory Commission, "Safety Evaluation Report with Open Items

Related to the License Renewal of the Dresden Nuclear Power Station, Unit 2 and 3 and

Quad Cities Nuclear Power Station, Unit 1 and 2." February 2004.

4. U.S. Nuclear Regulatory Commission Inspection Reports 50-237,249/03-04 and 50-

254,265/03-04, NRC License Renewal Scoping/Screening Inspection Report,

September 15, 2003.

5. U.S. Nuclear Regulatory Commission Inspection Report 50-237,249/03-1 0, NRC Aging.

Management Program Inspection Report, December 5, 2003.

5-5
6. U.S. Nuclear Regulatory Commission Inspection Report 50-254,265/03-14, NRC Aging

Management Program Inspection Report, December 5, 2003.

7. Electric Power Research Institute, *BWR Vessel and Internals Project BWR Core

Shroud Inspection and Flaw Evaluation Guidelines (BWRVIP-76),w January 2000.

8. Electric Power Research Institute, 'BWRVIP-1 16: BWR Vessel and Internals Project

Integrated Surveillance Program (ISP) Implementation for License Renewal," July 2003.

5-6
6. CONCLUSIONS

The staff reviewed the license renewal application for the Dresden Nuclear Power Station,

Units 2 and 3, and Quad Cities Nuclear Power Station, Units 1 and 2, in accordance with

Commission regulations and the NUREG-1800, "Standard Review Plan for Review of License

Renewal Applications for Nuclear Power Plants," dated July 2001. The standards for issuance

of renewed license are provided in Title 10, Section 54.29, of the Code of Federal Regulations

(10 CFR 54.29).

On the basis of its evaluation of the application, as discussed above, the staff concludes that

the requirements of 10 CFR 54.29(a) have been met, and all open items and confirmatory items

of this safety evaluation report have been resolved.

The staff notes that any requirements of Subpart A of 10 CFR Part 51 are documented in the

final plant-specific supplement to the Generic Environmental Impact Statements issued on June

29, 2004 for Dresden, and June 30, 2004, for Quad Cities.

6-1
APPENDIX A

COMMITMENTS FOR LICENSE RENEWAL

During the review of the Dresden/Quad Cities Nuclear Power Station (D/QCNPS) license

renewal application (LRA) by the U.S. Nuclear Regulatory Commission (NRC) staff, the

applicant made commitments related to aging management programs (AMPs) to manage aging

effects of structures, systems, and components (SSCs) before the period of extended

operation. The following table lists these commitments, along with the implementation schedule

and the source of the commitment.

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THIS PAGE IS INTENTIONALLY LEFT BLANK

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Appendix A - DIQCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

1) ASME Code, Existing program is credited. Both Dresden and A.1.1 Prior to the LRA Section B.1.1; Response tc

Section Xl Quad Cities will be implementing RI-ISI and its period of RAI 3.1-25 and RAI B.1.1, letter

Inservice alternative inspections for Class 1 and 2 piping extended RS-03-181, dated October 3,

Inspection, within the scope of license renewal. The operation 2003

Subsections IWB, requirements of ASME Code, Section Xl will be

IWC, and IWD implemented in accordance with 10 CFR 50.55(a).

2) Water Existing program Is credited. The program will be A.1.2 Prior to the LRA Section B.1.2

Chemistry enhanced to provide increased sampling to verify period of

corrective actions are taken to address abnormal extended

chemistry conditions. The Quad Cities procedure for operation

turbine building sample panel collection will be

revised to assure maintenance of the integrity of

chemistry samples.

3) Reactor Head Existing program is credited. A.1.3 Ongoing LRA Section B.1.3

Closure Studs

4) BWR Vessel Existing program is credited A.1.4 Ongoing LRA Section B.1.4

ID Attachment

Welds:

5) BWR Existing program is credited. The program will be A.1.5 Prior to the LRA Section B.1.5; Response tc

Feedwater Nozzle enhanced to implement the recommendations of period of Supplemental RAI B.1.5, letter

Revision 1, Version A of report GE-NE-523-A71- extended RS-03-223, dated November

0594-A, Revision 1, which was approved by the operation 21, 2003

NRC staff.

6) BWR Control Existing Program is Credited A.1.6 Ongoing LRA Section B.1.6

Rod Drive Return

Line Nozzle

A-3
Appendix A - DIQCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

7) BWR Stress Existing program is credited. The program will be A.1.7 End of 2018 (plus LRA Section B.1.7; Response t

Corrosion enhanced to include an additional ultrasonic or minus 2 years) Supplemental RAI 3.1-1, letter

Cracking examination of the Quad Cities Unit 2 reactor vessel RS-03-235, dated December

head crack (detected in 1990) to verify that the 17, 2003

relevant indication has remained essentially

unchanged. The examination will be completed by

the end of 2018 (plus or minus 2 years).

8) BWR Existing program is credited. A.1.8 Ongoing LRA Section B.1.8

Penetrations I

A-4

I,
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

9) BWR Vessel Existing program is credited. The program will be A.1.9 As approved by LRA Section B.1.9; Response t

Internals enhanced as follows: the NRC RAIs 4.2-BWRVIPs and B.1.9,

(1) Additional inspections will be performed when letter RS-03-181, dated Octobe

new inspection techniques and tooling are 3, 2003; responses to

developed, incorporated into applicable BWRVIP Supplemental RAls 4.2-

document(s), and approved by the NRC. BWRVIP and B.1.9(d), letter

(2) Dresden and Quad Cities agree to perform RS-03-223, dated November

inspections of the.top guide similar to inspections of 21, 2003; RS-04-080, dated

the control rod drive housing guide tube. However, May 27, 2004; RS-04-145,

Exelon reserves the right to modify the above dated October 8, 2004

agreed upon inspection program should the

BWRVIP-26 be revised In the future.

(3) .The steam dryers will be in the scope of

license renewal for Dresden andQuad Cities for

1OCFR54.4(a)(2). The aging effect that needs to be

managed Is cracking. The aging management

program will be the NRC approved BWRVIP Steam

Dryer Inspection and Evaluation Guideline. If the

BWRVIP Steam Dryer Inspection and Evaluation

Guideline is not approved by the NRC in a timely

manner, then a plant specific aging management

program will be submitted to the NRC for review and

approval by December 22, 2007, which is 2 years

before the first Dresden unit enters the period of

extended operation.

A-5
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

10) Thermal Aging An aging management program will be implemented A.1.10 Prior to the LRA Section B.1.10

and Neutron for thermal aging and neutron irradiation period of

Irradiation embrittlement of CASS reactor internal components extended

Embrittlement of within the scope of license renewal. A component operation

Cast Austenitic specific evaluation for the loss of fracture toughness

Stainless Steel will be included. For those components where the

(CASS) loss of fracture toughness may affect the function of

the component, an inspection will be performed as

part of the ISI program.

11) Flow- Existing program is credited. The program will be A. 1.1 1 Prior to the LRA Section B.1.1 1, response

Accelerated enhanced to include portions of the main steam and period of to RAI 3.1-18, letter RS-03-181,

Corrosion the reactor vessel head vent systems that are within extended dated October 3, 2003

the scope of license renewal. operation

A-6

I
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) - Schedule Source

12) Bolting Existing program is credited. The program will be A.1.12 Prior to the LRA Section B.1.12; response

Integrity enhanced to do the following: period of to Supplemental RAI 3.5-13,

(1) Credit periodic in-service Inspection piping and extended letter RS-03-227, dated

component preventive maintenance inspections, operation December 5, 2003; response to

system engineering walkdowns, and routine RAI 3.1-13, letter RS-03-181,

walkdowns to inspect for leakage and visual dated October 3, 2003;

indications of loose bolts; trend walkdown results response to Supplemental RAI

(2) Manage the loss of preload for closure bolting 3.1-13, letter RS-03-223, dated

in the reactor vessel system, recirculation pumps, November 21, 2003; response

reactor recirculation valves, reactor vessel head vent to RAI B.1.12(d), letter RS-03-

valves, and the reactor pressure boundary portion of 181, dated October 3, 2003

all other systems.

(3) Credit periodic inspections of the closure bolting

in accordance with the ASME Code Section Xl

requirements.

(4) Inspect bolted joints of diesel generator system

components, component bolted joint inspections in

high-humidity/moisture areas (pump vaults), and

reactor vessel-to-ring girder bolting.

(5) Enhance implementing procedure to reference

NUREG-1339.

A-7
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation Item Number Commitment (LRA App. A) Schedule Source

13) Open-Cycle Existing program is credited. The program will be A.1.13 Prior to the LRA Section B. 1.13; response Cooling Water enhanced to include periodic inspections of cooling period of to Supplemental RAI B.1.13(a),

Program water pump internal linings, additional heat extended letter RS-03-235, dated

exchangers and sub-components, external surfaces operation December 17, 2003

of various submerged pumps, components in the

high humidity/moisture environments of the pump

vaults, and piping. At Dresden only, periodic visual

inspections will be performed of strainer internals in

the CCSW supply line to the main control room

HVAC.

14) Closed-Cycle Existing program is credited. The program will be A.1.14 Prior to the LRA Section B.1.14

Cooling Water enhanced to provide monitoring of specific period of

Program parameters in accordance with EPRI TR-107396 extended

guidance. This will include provisions for monitoring operation

parameters such as pH, specific gravity, freeze

point, reserve alkalinity, percent glycol and

suspended solids in glycol based systems as

appropriate. At Dresden, the program will include

monitoring of pH and ammonia in the diesel

generator jacket water.

15) Inspection of Existing program is credited. The program will be A.1.15 Prior to the LRA Section B.1.15

Overhead Heavy enhanced to include specific inspections for rail wear period of

Load and Light and proper crane travel on the rails, and for extended

Load (Related to corrosion of crane structural components. operation

Refueling)

Handling Systems

A-8

I
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

16) Compressed Existing program is credited. The program will be A.1.16 Prior to the LRA Section B.1.16; response

Air Monitoring enhanced to include periodic inspections on those period of to Supplemental RAI B.1.16-01,

portions of the instrument air distribution piping in extended letter RS-04-073, dated May 18,

the scope of license renewal. The program will also operation 2004

include additional air sample points representative of

the in-scope piping. Additionally, at Dresden only,

periodic blowdowns will be provided of the

instrument air receiver tanks.

17) BWR Reactor Existing program Is credited. A.1.17 Ongoing LRA Section B.1.17

Water Cleanup

System

A-9
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

18) Fire Protection Existing program is credited. The program will be A.1.18 Prior to the LRA Section B.1.18; response

enhanced as follows: period of to Supplemental RAI B.1.18-01,

(1) Specific guidance will be provided to check fire extended letter RS-03-222, dated

doors for wear and holes in skin. At Quad Cities operation November 20, 2003; NRC AginE

only, the program will be revised to include the Management Program Audit

requirement to check fire door clearances. Report, dated April 23, 2004

(2) Periodic inspections will be performed for

corrosion on the external surfaces of piping and

components for the carbon dioxide systems; and for

the external surfaces of the Dresden halon system.

(3) Specific guidance will be provided for

examining the fire pumps and the Dresden isolation

condenser makeup pump diesel fuel supply systems

for leaks during pump tests.

(4) Periodic capacity tests will be performed on the

Dresden isolation condenser diesel-driven makeup

pumps.

(5) At Dresden, frequency of inspections will be

provided for fire doors and spill barriers.

(6) The program will be revised to perform a visual

inspection (VT-1 or equivalent) on a 10% sample

population of each type of fire seal on a refueling

outage frequency. Additionally, the program will be

revised to expand the sample population by 10% if

any of the inspected seals are found to have

abnormal degradation that could prevent the seal

from performing its intended function.

A-10

0
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

19) Fire Water Existing program is credited. The program will be A.1.19 Prior to the LRA Section B.1.19

System enhanced as follows: period of

(1) Periodic non-intrusive wall thickness extended

measurements will be provided of selecte'd portions operation

of the fire water system.

(2) Periodic inspections will be performed on the

external surfaces of submerged fire pumps, outdoor

fire hydrants, and outdoor transformer deluge

system components.

(3) Sampling of sprinklers will be performed in

accordance with NFPA 25, Inspection, Testing, and

Maintenance of Water-Based Fire Protection

Systems."

20) Above-ground Existing program is credited. The program will be A.1.20 Prior to the LRA Section B.1.20; responses

Carbon Steel enhanced as follows: period of to Supplemental RAIs B.1.2 and

Tanks (1) Periodic system engineer walkdowns will be extended B.1.20, letter RS-03-222, dated

performed on the nitrogen storage tanks utilizing operation November 20, 2003; NRC Aging

stand-alone procedures. Management Program

(2) At Quad Cities, a one-time UT thickness Inspection Report

inspection will be performed of the aluminum 05000237/200301 0(DRS):

condensate storage tank or demineralized water 05000249/200301 0(DRS),

storage tank. 05000254/2003014(DRS);

(3) At Dresden, periodic internal/external 05000265/2003014(DRS),

inspections of the aluminum storage tanks will be dated December 5, 2003

performed, and periodic UT thickness inspections

will be performed of the bottoms will be performed

A-11
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

21) Fuel Oil Existing program is credited. The program will be A.1.21 Prior to the LRA Section B.1.21; response

Chemistry enhanced to include inspection of the fuel oil storage period of to RAI B.1.21, letter RS-03-180,

tank interiors for corrosion during regularly extended dated October 3, 2003

scheduled tank cleanings. operation

22) Reactor Existing program is credited. The program will be A. 1.22 Prior to the LRA Section 3.1.1.1.4, LRA

Vessel enhanced as follows: period of Section B.1.22, response to RAI

Surveillance (1) The Integrated Surveillance Program (ISP) for extended B.1.22, letter RS-03-181, dated

the license renewal period (in accordance with operation October 3, 2003; response to

proposed BWRVIP-116) will be implemented when Supplemental RAI B.1.22, letter

approved by the NRC. RS-03-223, dated November

(2) If BWRVIP-116 is not approved, a plant-specific 21, 2003

surveillance plan will be provided for the license

renewal period in accordance with Appendices G

and H to 10 CFR Part 50

A-12
__ ..  __ .. . - _.. 1. - .- _- -1. .. . .. .

Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

23) One-Time One-time inspection sampling will be performed on A.1.23 Prior to the LRA Sections 3.2.1.1.3,

Inspection the following: period of 3.2.1.1.5, 3.5.1.1.6, and B.1.23;

(1) at Dresden, spent fuel pool cooling and extended response to Supplemental RAI

demineralizer system components for corrosion in operation B.1.23-2.1, letter RS-04-014

stagnant locations dated January 26, 2004;

(2) condensate and torus water components for response to RAls 3.5-7 and 3.1 -

corrosion in stagnant locations 9, letter RS-03-201 dated

(3) compressed gas system piping components for October 3, 2003; response to

corrosion Supplemental RAI 3.1-21(b),

(4) compressed gas system flexible hoses for age letter RS-03-223, dated

related degradation November 21, 2003; response

(5) lower sections of carbon steel fuel oil and to Supplemental RAIs B.1.2,

lubricating oil tanks for reduced thickness B.1.2-1, and 3.1-21 (a), letter

(6) fuel oil and lubricating oil piping and RS-03-238, dated December

components for corrosion 22, 2003; responses to

(7) control room ventilation, EDG ventilation, SBO Supplemental RAIs 3.5-15 and

building ventilation, reactor building ventilation, and 3.5-17, letter RS-03-227, dated

standby gas treatment system components for loss December 5, 2003; letter RSof material 04-046, dated December 25,

(8) HPCI lubrication oil hoses for age related 2004

degradation

(9) non-safety-related vent and drain components

for age related degradation

(10) 10 CFR 54.4(a)(2) components for corrosion

(11) piping exposed to containment atmosphere for

loss of material

(12) torus saddle supports to confirm condition of

drywell radial beam lubrite baseplates

A-13
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

24) Selective A sample of components that are made of A.1.24 Prior to the LRA Section B.1.24

Leaching of susceptible materials will be visually inspected for period of

Materials evidence of selective leaching. The sample will be extended

expanded if failed conditions are identified. operation

25) Buried Piping Existing program is credited. The program will be A.1.25 Prior to the LRA Section B.1.25; response

and Tanks enhanced as follows: period of to RAI B.1.25, letter RS-03-181,

Inspection (1) A one-time visual inspection will be performed extended dated October 3, 2003;

on the external surface of a section of buried ductile operation response to Supplemental RAI

iron fire main piping (including a mechanical joint). B.1.25-1, letter RS-04-046,

(2) A one-time internal UT of one buried steel tank dated March 25, 2004

per site will be performed.

(3) At Quad Cities, periodic leakage checks will be

performed on buried carbon steel fuel oil storage

tanks.

A-14
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation Item Number Commitment (LRA App. A) Schedule Source

26) ASME Code, Existing program is credited. The program will be A.1.26 Prior to the Response to RAI B.1.26, letter

Section Xl, enhanced as follows: period of RS-03-180, dated October 3, Subsection IWE (1) The program will be based on the latest edition extended 2003; responses to

and addenda, which is approved by the NRC 12 operation Supplemental RAls 2.4-3, 3.5-5, months prior to the end of the current 120-month 4.7.2.2-1, and 4.7.2.2-02, letter

inspection interval. RS-03-227, dated December 5, (2) The program will be updated in accordance with 2003; response to

10 CFR 50.55(a). Supplemental RAI B.1.27, letter

(3) Additional inspections of the Dresden Unit RS-04-046, dated March 25, containment shell for corrosion will be provided. 2004; LRA Section B.1.26,

(4) Requirements will be provided in Quad Cities response to RAI 3.5-6, letter

procedures to ensure that sand pocket drains are RS-03-227, dated December 5, clear. 2003

(5) The pressurized testing methodology will be

credited for managing the aging of bellows.

A-15
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

27) ASME Code, Existing program is credited. The program will be A.1.27 Prior to the LRA Section B.1.27; Open Item

Section Xl, enhanced to include inspection of Class MC period of 3.5.2.3.2.2-1; response to RAI

Subsection IWF component supports consistent with NUREG-1801, extended 3.5-7, letter RS-03-180, dated

Chapter III, Section B1.3. The ASME Code, Section operation October 3, 2003; response to

Xl, Subsection IWF program will manage the aging Supplemental RAI 2.4-2, letter

of the following Class MC supports: RS-03-0227, dated December

(1) Biological Shield to Containment Stabilizer 5, 2003; response to

(2) RPV Male Stabilizer Attached to Outside of Supplemental RAI B.1.27, letter

Drywell Shell RS-04-046, dated March 25,

(3) RPV Female Stabilizer and Anchor Rods 2004

(4) Suppression Chamber Ring Girder Vertical

Supports and Base Plates

(5) Suppression Chamber Saddle Supports and

Base Plates

(6) Suppression Chamber Seismic Restraints and

Base Plates

(7) Vent Header Vertical Column Supports

28) Appendix J of Existing program is credited. A.1.28 Ongoing LRA Section B.1.28

10 CFR Part 50,

29) Masonry Wall Existing program is credited. A.1.29 Ongoing LRA Section B.1.29

Program

A-16
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

30) Structures Existing program is credited. The program will be A.1.30 Prior to the LRA Sections B.1.30, 3.3.1.2.1,

Monitoring enhanced to add the following which will be period of 3.5.1.1.7, 3.5.1.2.6, and

Program implemented prior to the period of extended extended 3.5.1.2.7; response to

operation: operation Supplemental RAI B.1.30, letter

(1) inspections of structural steel components in RS-03-227, dated December 5,

secondary containment, flood barriers, electrical 2003; response to

panels and racks, junction boxes, instrument panels Supplemental RAI B.1.27, letter

and racks, and offsite power structural components RS-04-046, dated March 25,

and their foundations, and the Quad Cities discharge 2004; response to Open Item

canal weir as part of the ultimate heat sink 3.5.2.3.2-1, letter RS-04-057,

(2) periodic reviews of chemistry data on below- dated April 9, 2004 and letter

grade water to confirm that the environment remains RS-04-088 dated June 22,

non-aggressive for aggressive chemical attack of 2004, teleconference summary

concrete or corrosion of embedded steel dated July 13, 2004.

(3) inspection of a sample of non-insulated indoor

piping external surfaces at locations immediately

adjacent to periodically inspected piping supports

and inspection of standard components such as

snubbers, struts, and spring cans.

(4) program reference to specific insulation

inspection criteria for existing cold weather

preparation and inspection procedures for outdoor

insulation, and the establishment of new inspections

for various indoor area piping and equipment

insulation

(5) inspection parameters for non-structural joints,

roofing, grout pads and isolation gaps

(6) Extension of inspection criteria to the structural

A-17
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

31) RG 1.127, Existing program is credited. The program will be A.1.31 Prior to the LRA Section B.1.31; response

Inspection of enhanced to add the following: period of to Supplemental RAIs 3.5-12

Water-Control (1) monitoring of crib house concrete walls and extended and B.1.31, letter RS-03-227,

Structures slabs with an opposing side in contact with river operation dated December 5, 2003

Associated with water

Nuclear Power (2) inspection for structural integrity of concrete

Plants and steel components and identification of specific

types of components to be inspected

(3) periodic monitoring of the Dresden discharge

outfall concrete structure

(4) at Quad Cities, periodic inspections of the

concrete of the discharge flume/canal and the weir

gate in the discharge canal

32) Protective Existing program is credited. The program will be A.1.32 Prior to the LRA Section B.1.32

Coating enhanced as follows: period of

Monitoring and (1) visual inspection of Service Level I coatings extended

Maintenance near sumps or screens associated with the operation

Program emergency core cooling system

(2) pre-inspection review of previous reports so

that trends can be identified for the program

(3) analysis of coating failures to determine

reasons for failures

A-18
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

33) Electrical A program will be developed that is consistent with A.1.33 Prior to the LRA Section B.1.33; response

Cables and NUREG-1 801 AMP XI.E1 for electrical cables and period of to RAI B.1.33-3, letter RS-03-

Connections Not connections installed in adverse localized extended 177, dated October 3, 2003

Subject to 10 CFR environments not subject to 10 CFR 50.49 operation

50.49 environmental qualification requirements.

Environmental

Qualification

Requirements _.

34) Metal Fatigue Existing program is credited. The program will be A.1.34, A.3.4 Prior to the LRA Sections 4.3.1, 4.3.2,

of Reactor enhanced to utilize the EPRI-licensed FatiguePro period of 4.3.3.1, 4.6.1, 4.6.2 and B.1.34;

Coolant Pressure computer program for monitoring fatigue at bounding extended response to RAI B.1.34, letter

Boundary locations for reactor pressure vessel, Class I piping, operation. RS-03-180, dated October 3,

torus, torus vents, and torus attached piping and 2003

penetrations, SRV discharge lines, and the Dresden

isolation condenser.

35) Environmental Existing program is credited. A.1.35 Ongoing LRA Section B.1.35

Qualification (EQ)

of Electrical

Components :

36) Boraflex Existing program is credited. A.1.36 Ongoing LRA Section B.1.36

Monitoring

A-19
Appendix A - DIQCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

37) Electrical A program will be developed to manage aging of A.1.37 Prior to the LRA Section B.1.37; Responses

Cables Not cables in sensitive instrumentation circuits with low- period of to RAIs 3.6-9 and B.1.33-1,

Subject to 10 CFR level signals in the Nuclear Instrumentation Systems extended letter RS-03-177, dated Octobe

50.49 and Radiation Monitoring Systems. The program operation 3, 2003; response to

Environmental will include a review of calibration and surveillance Supplemental RAI 3.6-09, letter

Requirements results, and cable testing every 24 months (SRM, RS-03-238, dated December

Used in IRM circuits) for cable aging degradation before the 22, 2003

Instrument period of extended operation and every 10 years

Circuits thereafter. This program applies to the cables of the

Nuclear Instrumentation Systems which includes

source range monitors, intermediate range monitors,

local power range monitors, and Radiation

Monitoring Systems which includes drywell high

range radiation monitors, main steam line radiation

monitors, and the steam jet air ejector radiation

monitors.

38) Inaccessible At Dresden, a new condition monitoring program will A.1.38 Prior to the LRA Section B.1.38; Response

Medium-Voltage be provided in accordance with NUREG-1801, AMP period of to Supplemental RAI 3.6-3,

Cables Not XI.E3 to manage aging of five inaccessible medium- extended letter RS-03-222, dated

Subject to 10 CFR voltage cables feeding the service water pumps. operation November 20, 2003

50.49 The cables will be tested at least once every ten

Environmental years. The end of the cribhouse duct bank will be

Requirements inspected annually to verify that the duct run is not

plugged with debris.

39) Corrective Existing program is credited. A.2.1 Ongoing LRA Section B.2.1

Action Program

A-20
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation Item Number Commitment (LRA App. A) Schedule Source

40) Periodic A program will be developed and implemented to A.2.2 Prior to the LRA Section B.2.2; response to

Inspection of Non- periodically inspect non-segregated bus ducts that period of RAI 3.6-4, letter RS-03-177,

EQ, Non- connect the reserve auxiliary transformers (RATs) to extended dated October 3, 2003;

Segregated 4160V ESS buses, the non-segregated bbs ducts operation responses to Supplemental Electrical Bus that connect the EDG to the ESS buses, and, for RAls 3.6-4, 3.6-7, and B.2.2-01,

Ducts Dresden only, the non-segregated bus ducts that letter RS-03-227, dated

connect ESS buses. The bus duct internal December 5, 2003; response to

components and materials will be visually inspected Supplemental RAI B.t2.2-1, lette

for signs of aging degradation. The program will RS-03-238, dated December

include the following: 22, 2003.

(1) inspection of accessible normally energized

non-segregated bus duct internal components such

as insulation materials, bus duct support pieces,

gaskets, insulating boots, taped connections, and

bus bar sleeves for material surface anomalies for

non-segregated bus duct that connects the RATs to

the 4160V ESS buses

(2) inspection of bus bar insulation material at the

accessible bolted connections of the non-segregated

bus duct that connects the RATs to the 4160V ESS

buses -

(3) inspection of 10% of the splice insulation

material at the bolted connections (including all

visible insulation in both directions beyond the

location of the bolted connection splice insulation

inspected) for the non-segregated bus duct that

connects the EDG to the ESS buses and, for

Dresden only, the non-segregated bus duct that

A-21
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

41) Periodic Existing program is credited. The program will be A.2.3 Prior to the LRA Section B.2.3; letter RSInspection of enhanced to include inspection of aging of all period of 03-235, dated December 17,

Ventilation System elastomers, flexible boots, access door seals and extended 2003

Elastomers gaskets, filter seals and gaskets, and RTV silicone operation

used as a duct sealant, in the components of the

SBO ventilation and Reactor Building ventilation

systems for Dresden, and the SBO ventilation and

EDG Room ventilation systems for Quad Cities. The

inspections will be performed to detect cracking, loss

of material, and other evidence of aging. Tests of

seals for hardening will be included if evidence of

aging is found.

42) Periodic Existing program is credited. A.2.4 Ongoing LRA Section B.2.4

Testing of Drywell

and Torus Spray

Nozzles

A-22
Appendix A - DIQCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

43) Lubricating Oil Existing program is credited. The program will be A.2.5 Prior to the LRA Section B.2.5; Response tc

Monitoring enhanced to include those components exposed to period of RAI B.1.23-2, letter RS-03-180,

Activities an environment of lubricating oil in the following extended dated October 3, 2003;

systems: operation Supplemental RAIs B.1.23-02.3

(1) the reactor core isolation cooling system (Quad and B.1.23-02.4, letter RS-04-

Cities only) 014, dated January 26, 2004

(2) the main generator hydrogen seal oil system

(Quad Cities only)

(3) the high pressure coolant injection system

(4) the emergency diesel generator and auxiliaries

system

(5) the station blackout diesel system

(6) the electro-hydraulic control system

A-23
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

44) Heat An aging management program will be developed A.2.6 Prior to the LRA Section B.2.6; response to

Exchanger Test and implemented for heat exchangers in the scope period of Supplemental RAI 3.1-11, letter

and Inspection of license renewal that are not tested and inspected extended RS-03-223, dated November

Activities by the Open-Cycle Cooling Water System and operation 21, 2003; response to

Closed-Cycle Cooling Water System aging Supplemental RAI 3.1-11, letter

management programs. RS-03-238, dated December

Specifically, for the Dresden isolation condensers, 22, 2003

the augmentation activities identified in NUREG1801, lines IV.C1.4-a and IV.C1.4-b to manage loss

of material and cracking will also be included in this

aging management program, and will provide the

following:

(1) temperature and radioactivity monitoring of the

shell-side (cooling) water

(2) eddy current testing of the tubes

(3) visual inspections of the channel head, tube

sheets, and internal surfaces of the shell

45) Generator Existing program is credited. A.2.7 Ongoing LRA Section B.2.7

Stator Water

Chemistry

Activities

46) Periodic An aging management program will be developed A.2.8 Prior to the LRA Section B.2.8; Response tc

Inspection of Plant and implemented to inspect components in the Plant period of RAI 8.1.23, letter RS-04-046,

Heating System Heating system once before the end of the current extended dated March 25, 2004

operating term and periodically at intervals not to operation

exceed once every 5 years during the period of

extended operation.

A-24
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

47) Time-Limited Revised P-T limits will be prepared and submitted to A.3.1.5 Prior to the LRA Section 4.2.5; response to

Aging Analysis the NRC for approval prior to the start of the period of RAI 4.3.0, letter RS-03-180,

(TLAA) - Neutron extended period of operation using an approved extended dated October 3, 2003

Embrittlement of fluence methodology for Dresden and Quad Cities. operation

the Reactor

Vessel and

Internals

48) TLAA - Metal The Dresden Unit 2 jet pump riser braces will be A.3.2.2.1 Prior to the LRA Section 4.3.2.2; response

Fatigue repaired or replaced prior to the period of extended period of to RAI 4.3.0, letter RS-03-180,

operation. extended dated October 3, 2003;

operation response to RAI 4.3.2.2, letter

RS-03-180, dated

October 3, 2003

Plant-specific calculations will be performed for A.3.2.4 Prior to the LRA Section 4.3.4; response to

applicable locations identified In NUREG/CR 6260, period of Supplemental RAI 4.3.4, letter

"Application of NUREG/CR-5999 Interim Fatigue extended RS-03-235, dated December

Curves to Selected Nuclear Power Plant operation 17, 2003

Components," for older-vintage BWR plants, to

assess potential effects of reactor coolant on

component fatigue life in accordance with 10 CFR

54.21(c)(1)(ii). Exelon reserves the right to modify

this position in the future based on the results of

industry activities currently underway, or based on

other results of improvements in methodology,

subject to NRC approval prior to changes in this

position.

A-25
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source

49) TLAA - A reanalysis will be applied to EQ components now A.3.3 Prior to the LRA Section 4.4; response to

Environmental qualified for the current operating term of 40 years. period of RAI 4.3.0, letter RS-03-180,

Qualification of The EQ Binders for components within the scope of extended dated October 3, 2003

Electrical 10 CFR 50.49 will be updated to include operation

Equipment environmental conditions associated with EPU

implementation together with an extended operating

period of 60 years.

50) TLAA - Other The corrosion rate assumptions used in the A.3.5.2.1 Prior to the LRA Section 4.7.2.2

Plant-Specific calculation of the drywell steel plate remaining period of

TLAAs thickness at the sand pocket level will be confirmed extended

by a Dresden Unit 3 UT inspection prior to the period operation

of extended operation. The results will be used to

revise the associated corrosion calculation and

validate that an acceptable wall thickness will remain

to the end of the 60-year licensed operating period.

The corrosion rate assumptions used in the A.3.5.2.2 Prior to the LRA Section 4.7.2.3

calculation of the ECCS Suction strainer flange period of

remaining thickness will be confirmed by an extended

ultrasonic inspection. One bounding inspection will operation

be performed and results will be used to validate the

corrosion rate for both sites. Based upon the results

of the inspection, a revised galvanic corrosion

calculation will be performed to ensure acceptable

wall thickness to the end of the 60-year licensed

operating period.

A-26

I.
Appendix A - D/QCNPS Commitment List Associated with Renewal of the Operating Licenses

UFSAR

Supplement Location Implementation

Item Number Commitment (LRA App. A) Schedule Source. .

51)BWR Exelon will perform an evaluation of operating Prior to the RS-04-145, dated October 8,

Operating experience at extended power uprate (EPU) levels period of 2004

Experience - EPU prior to the period of extended operation to ensure extended

levels that operating experience at EPU levels is properly operation

addressed by the aging management programs. The

evaluation will include the Dresden and Quad Cities

units and other plants operating at EPU levels.

Exelon will submit this evaluation to the NRC for

review prior to entering the period of extended

operation for each facility.

A-27
APPENDIX B

CHRONOLOGY

This appendix contains a chronological listing of correspondence between the U.S. Nuclear

Regulatory Commission (NRC) staff and Exelon Generation Company, LLC (Exelon), related to

the NRC staff's review, under Title 10, Part 54, of the Code of Federal Regulations (10 CFR

Part 54), of Exelon's license renewal application (LRA) for the Dresden Nuclear Power Station,

Units 2 and 3, and Quad Cities Nuclear Power Station, Units 1 and 2. All documents, with the

exception of those containing proprietary information, have been placed in the Commission's

Public Document Room, at One White Flint North, 11555 Rockville Pike (first floor), Rockville,

Maryland, and are available electronically from the Public Electronic Reading Room found on

the Internet at http://www.nrc.aov/readina-rm.html. From this site, the public can gain access to

the NRC's Agencywide Documents Access and Management System (ADAMS), which provides

text and image files of the NRC's public documents in the Publicly Available Records (PARS)

component of ADAMS. The ADAMS accession numbers for each document are included

below.

January 3, 2003

January 24, 2003

February 7, 2003

February 26, 2003

April 17,2003

May 5, 2003

Letter from Mr. Jeffrey A. Benjamin, Exelon Generating Company, LLC

(Exelon) to the NRC, submitting the application for the renewal of the

operating licenses for the Dresden Nuclear Power Station, Units 2 and 3,

and Quad Cities Nuclear Power Station, Units 1 and 2 (Accession No.

ML030090203)

Letter from the NRC to Mr. John L. Skolds, Exelon, forwarding the Notice

of Receipt and Availability of the application for the renewal of the

operating licenses for the Dresden Nuclear Power Station, Units 2 and 3,

and Quad Cities Nuclear Power Station, Units 1 and 2 (Accession No.

ML030240603)

Letter from Mr. Patrick R. Simpson, Exelon, to the NRC, submitting the

Aging Management Review Aid and revised table links between LRA

Chapters 2 and 3 (Accession No. ML030500245)

Letter from the NRC to Mr. John L. Skolds, Exelon, forwarding the Notice

of Acceptance for Docketing and Opportunity for Hearing associated with

the application for the renewal of the operating licenses for the Dresden

Nuclear Power Station, Units 2 and 3, and Quad Cities Nuclear Power

Station, Units 1 and 2 (Accession No. ML030570654)

Letter from Mr. Patrick R. Simpson, Exelon, to the NRC, submitting the

Corrected Fluence Tables for Dresden Nuclear Power Station, Units 2

and 3, associated with LRA (Accession No. ML031190598)

Letter from the NRC to Mr. John L. Skolds, Exelon, forwarding revision to

the NRC's review schedule (Accession No. ML031260004)

B-1
July 21, 2003

July 21, 2003

August 4, 2003

August 4, 2003

August 7, 2003

September 9, 2003

October 3, 2003

October 3, 2003

October 3, 2003

October 3, 2003

October 3, 2003

October 15, 2003

Letter from the NRC to Mr. John L. Skolds, Exelon, forwarding the first

set of Request for Additional Information (RAls) associated with the LRA

(Accession No. ML032020080)

Letter from the NRC to Mr. John L. Skolds, Exelon, forwarding the

second set of Request for Additional Information associated with the LRA

(Accession No. ML032020170)

Letter from the NRC to Mr. John L. Skolds, Exelon, forwarding the third

set of Request for Additional Information associated with the LRA

(Accession No. ML032180267)

Letter from the NRC to Mr. John L. Skolds, Exelon, forwarding the fourth

set of Request for Additional Information associated with the LRA

(Accession No. ML032180382)

Letter from the NRC to Mr. John L. Skolds, Exelon, forwarding the fifth

set of Request for Additional Information associated with the LRA

(Accession No. ML032310093)

Letter from the NRC to Mr. John L. Skolds, Exelon, forwarding a

Supplemental Request for Additional Information associated with the LRA

(Accession No. ML032530371)

Letter (RS-03-177) from Mr. Patrick R. Simpson, Exelon, to the NRC,

submitting the requested additional information (Accession No.

ML032810579)

Letter (RS-03-178) from Mr. Patrick R. Simpson, Exelon, to the NRC,

submitting the requested additional information (Accession No.

ML032810563)

Letter (RS-03-179) from Mr. Patrick R. Simpson, Exelon, to the NRC,

submitting the requested additional information (Accession No.

ML032810692)

Letter (RS-03-180) from Mr. Patrick R. Simpson, Exelon, to the NRC,

submitting the requested additional information (Accession No.

ML032820273)

Letter (RS-03-181) from Mr. Patrick R. Simpson, Exelon, to the NRC,

submitting the requested additional information (Accession No.

ML032810682)

Letter (RS-03-201) from Mr. Patrick R. Simpson, Exelon, to the NRC,

submitting the requested additional information (Accession No.

ML033010396)

B-2
'.'- -:' il '- ?

October 20, 2003

November 14, 2003

November 20, 2003

November 21, 2003

December 5, 2003

December 12, 2003

December 17, 2003

December 22, 2003

January 26, 2004

February 3, 2004

March 5, 2004

March 25, 2004

April 9, 2004

April 23, 2004

May 18, 2004

Letter from the NRC to Mr. John L. Skolds, Exelon, forwarding an

Inspection-related Open Item associated with the LRA (Accession No.

ML032940056)

E-mail from T. Kim to A. Fulvio

Letter (RS-03-222) from Mr. Patrick R. Simpson, Exelon, to the NRC,

submitting supplemental information (Accession No. ML033320342)

Letter (RS-03-223) from Mr. Patrick R. Simpson, Exelon, to the NRC,

submitting supplemental information (Accession No. ML033360714)

Letter (RS-03-227) from Mr. Patrick R. Simpson, Exelon, to the NRC,

submitting supplemental information (Accession No. ML033500404)

Letter (RS-03-232) from Mr. Patrick R. Simpson, Exelon, to the NRC,

submitting supplemental information (Accession No. ML033580647)

Letter (RS-03-235) from Mr. Patrick R. Simpson, Exelon, to the NRC,

submitting supplemental information (Accession No. ML033580635)

Letter (RS-03-238) from Mr. Patrick R. Simpson, Exelon, to the NRC,

submitting supplemental information (Accession No. ML033640630)

Letter (RS-04-14) from Mr. Patrick R. Simpson, Exelon, to the NRC,

submitting supplemental information (Accession No. ML040340487)

Letter (RS-04-020) from Mr. Patrick R. Simpson, Exelon, to the NRC,

Consolidated List of Commitments for License Renewal (Accession No.

ML040420164)

Letter (RS-04-039) from Mr. Patrick R. Simpson, Exelon, to the NRC,

Amendment to the Application for Renewed Operating Licenses for

Dresden and Quad Cities Nuclear Power Stations (Accession No.

ML040711186)

Letter (RS-04-046) from Mr. Patrick R. Simpson, Exelon, to the NRC,

submitting the requested supplemental information (Accession No.

ML040900466)

Letter (RS-04-057) from Mr. Patrick R. Simpson, Exelon, to the NRC,

submitting responses to the draft SER Open Items and Confirmatory

Items (Accession No. ML041070456)

Audit Report Related to the License Renewal Application for Dresden

Nuclear Power Station and Quad Cities Nuclear Power Station

Letter (RS-04-073) from Mr. Patrick R. Simpson, Exelon, to the NRC,

submitting supplemental information (Accession No. ML041480178)

B-3
May 27, 2004

June 22, 2004

June 29, 2004

June 30, 2004

July 13,2004

September 16, 2004

October 8, 2004

Letter (RS-04-080) from Mr. Keith R. Jury, Exelon, to the NRC, License

Renewal Commitment for Scoping of Steam Dryers and the Dresden and

Quad Cities Nuclear Power Stations (Accession No. ML041550270)

Letter (RS-04-088) from Mr. Patrick R. Simpson, Exelon to the NRC,

submitting supplemental information (Accession No. ML041820207)

Final Supplement 17 to the Generic Environmental Impact Statement

Regarding License Renewal for Dresden Nuclear Power Station, Units 2

and 3 (Accession Number ML041830675)

Final Supplement 16 to the Generic Environmental Impact Statement

Regarding License Renewal for Quad Cities Nuclear Power Station, Units

1 and 2 (Accession No. ML041830462)

Summary of telephone conference held on July 13,2004, between the U.S.

Nuclear Regulatory Commission and the Exelon Generation Company

Regarding the Resolution of Open Item 3.5.2.3.2-1 and Confirmatory Item

3.0.3.14.2-1

In a letter (signed by M. Bonaca), the Advisory Committee on Reactor

Safeguards provided its conclusions and recommendations on the renewal

of the operating licenses for Dresden and Quad Cities (Accession No.

ML042610045)

Letter (RS-04-145) from Mr. Keith R. Jury, Exelon, to the NRC, Additional

Commitments for License Renewal

B-4
APPENDIX C

PRINCIPAL CONTRIBUTORS

NAME

T. Kim

R. Auluck

W. Burton

B. Wong

H. Ashar

S. Bailey

T. Chan

K. Chang

K. Corp

K. Coyne

P. Y. Chen

S. Coffin

B. Elliot

J. Fair

T. Ford

G. Galletti

R. Goel

M. Hartzman

G. Hatchett

R. Hemandez-Figueroa

J. Honcharik

N. lqbal

V. Klco

T. Koshy

P.T. Kuo

A. Lee

S. Lee

J. Lehning

Y.Li

L. Lund

J.Ma

K. Manoly

R. McNally

C. Munson

M. Murphy

Q. Nguyen

A. Pal

P. Patnaik

P. Prescott

J. Rajan

M. Razzaque

D. Shum

J. Strnisha

RESPONSIBILITY

Project Manager

Project Manager

Project Manager

Project Manager

Mechanical Engineering

Mechanical Engineering

Management Supervision

Technical Support

Technical Support

Quality Assurance

Technical Support

Management Supervision

Materials Engineering

Mechanical Engineering

Reactor Systems

Quality Assurance

Plant Systems

Civil Engineering

Plant Systems

Plant Systems

Materials Engineering

Plant Systems

Plant Systems

Electrical Engineering

Management Supervision

Mechanical Engineering

Management Supervision

Plant Systems

Mechanical Engineering

Management Supervision

Mechanical Engineering

Management Supervision

Mechanical Engineering

Civil Engineering

Chemical Engineering

Technical Support

Electrical Engineering

Materials Engineering

Quality Assurance

Civil Engineering

Reactor Systems

Plant Systems

Mechanical Engineering

C-1
A. Stubbs

D. Terao

D. Thatcher

H. Wagage

H. Wang

S. Weerakkady

L. Wheeler

B. Wong

C. Wu

Plant Systems

Management Supervision

Management Supervision

Plant Systems

Technical Support

Management Supervision

Environmental Project Manager

Mechanical Engineering

CONTRACTORS

Contractor Technical Area

Argonne National Laboratory Reactor Vessel, Internals, Reactor Coolant System,

and Auxiliary Systems

Brookhaven National Laboratory Containment, Structures, and Component Supports

Information Systems Laboratories Fire Protection and Aging Management Programs

Pacific Northwest National Laboratory Engineered Safety Features and Steam/Power

Conversion Systems

C-2
APPENDIX D

REFERENCES

* This appendix lists the references used in preparing the safety evaluation report associated with

the license renewal application for the Dresden Nuclear Power Station, Units 2 and 3, and Quad

Cities Nuclear Power Station, Units 1 and 2.

AMERICAN CONCRETE INSTITUTE (ACI)

ACI 301, "Specifications for Structural Concrete for Buildings"

ACI 318-63, "Building Code Requirements for Reinforced Concrete"

AMERICAN SOCIETY OF MECHANICAL ENGINEERS (ASME)

ASME Boiler and Pressure Vessel Code, July 1989

ASME Boilerand Pressure Vessel Code, Section 1II, Rules for Construction of Nuclear Power Plant

Components (through Summer 1979 addenda)

ASME Boiler and Pressure Vessel Code, Section Xl, Rules for Inservice Inspection of Nuclear

Power Plant Components

ASME Boiler and Pressure Vessel Code, Section Xl, Appendix G (1995 edition through 1996

addenda)

AMERICAN SOCIETY FOR TESTING AND MATERIALS (ASTM)

ASTM A307, "Standard Specification for Carbon Steel Bolts and Steels, 60,000 psi Tensile

Strength"

ASTM A325, "Standard Specification for Structural Bolts, Steel, Heat-Treated, 120 ksi and 105

ksi Minimum Tensile Strength"

ASTM A490, "Standard Specification for Heat-Treated Steel Structural Bolts, 150ksi Minimum

Tensile Strength"

ASTM D975-1981, "Standard Specification for Diesel Fuel Oils"

AMERICAN WATER WORKS ASSOCIATION (AWWA)

AWWA C203, "AWWA Standard for Coal-Tar Protective Coatings and Linings for Steel Water

Pipelines - Enamel and Tape - Hot Applied," 1966

BOILING WATER REACTOR VESSEL AND INTERNALS PROJECT (BWRVIP)

BWRVIP-05, "BWR RPV Shell Weld Inspection Recommendations," September 1995

D-1
BWRVIP-18, "Core Spray Internals Inspection and Flaw Evaluation Guidelines," July 1996

BWRVIP-25, "BWR Core Plate Inspection and Flaw Evaluation Guidelines," October 1999

BWRVIP-26, "Top Guide Inspection and Flaw Evaluation Guidelines," December 1996

BWRVIP-27, "Standby Liquid Control System/Core Plate AP Inspection and Flaw Evaluation

Guidelines," April 1997

BWRVIP-38, "Shroud Support Inspection and Flaw Evaluation Guidelines," September 1997

BWRVIP-41, "BWRJet PumpAssembly Inspection and Flaw Evaluation Guidelines," October 1997

BWRVIP-47, "BWR Lower Plenum Inspection and Flaw Evaluation Guidelines," December 1997

BWRVI P-48, "Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines," March 1998

BWRVIP-49, "Instrument Penetration Inspection and Flaw Evaluation Guidelines," March 1998

BWRVIP-74, "BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines,"

September 1999.

BWRVIP-75, "Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules

(NUREG-0313)," October 1999

BWRVIP-76, "BWR Core Shroud Inspection and Flaw Evaluation Guidelines," December 1999

BULLETINS (BL)

NRC BL-80-1 1, "Masonry Wall Design," May 1980

CODE OF FEDERAL REGULATIONS

10 CFR 50.34, "Contents of application; technical information," Section (a)(1)

10 CFR 50.48, "Fire Protection"

10 CFR 50.49, "Environmental Qualification of Electric Equipment Important to Safety for Nuclear

Power Plants"

10 CFR 50.55a, "Codes and Standards"

10 CFR 50.60, "Acceptance Criteria for Fracture Prevention Measures for Light water Nuclear

Power Reactors for Normal Operation"

10 CFR 50.61, "Fracture Toughness Requirements for Protection Against Pressurized Thermal

Shock Events"

D-2
10 CFR 50.62, "Requirements for Reduction of Risk from Anticipated Transients Without Scram

(ATWS) Events for Light-Water-Cooled Nuclear Power Plants"

10 CFR 50.63, "Loss of All Alteriiatlng Current Power"

10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power

Plants"

10 CFR Part 50, Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and Fuel

Reprocessing Plants"

10 CFR Part 50, Appendix G, "Fracture Toughness Requirements"

10 CFR Part 50, Appendix H, "Reactor Vessel Material Surveillance Program Requirements"

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

Regulatory Functions"

10 CFR Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants"

; 10 CFR Part 100, "Reactor Site Criteria"

ELECTRIC POWER RESEARCH INSTITUTE (EPRI)

EPRI NP-5461, "Component Life Estimation: LWR Structural Materials Degradation

Mechanisms," September 1987

EPRI NP-5769, "Degradation and Failure of Bolting in Nuclear Power Plants," Vols. 1 and 2,

Project 2520-7, 1998

EPRI NSAC/202-L, "Recommendations for an Effective Flow-Accelerated Corrosion Program"

EPRI TR-1 03515, "BWR Water Chemistry Guidelines," BWRVIP-29

EPRI TR-1 03840 "BWR Containment License Renewal Industry Report; Revision 1" July 1994

EPRI TR-103842, "Class I Structures Industry Report"

EPRI TR-104873, "Methodologies and Processes to Optimize Environmental Qualification

Replacement Internals," February 1996

EPRI TR-105747, "Guidelines for Reinspection of BWR Core Shrouds," BWRVIP-07, February

1996

EPRI TR-105759, "An Environmental Factor Approach to Account for Reactor Water Effects in

Light Water Reactor Pressure Vessel and Piping Evaluations"

D-3
EPRI TR-1 06092, -Evaluation of Thermal Aging Embrittlement for Cast Austenitic Stainless Steel

Components in LWR Coolant Systems," September 1997

EPRI TR-106740, "BWR Core Spray Internals and Flaw Evaluation Guidelines," BWRIVP-18, July

1996

EPRI TR-107079, Revision 2, "BWR Core Shroud Inspection and Flaw Evaluation Guidelines,"

BWRVIP-01, October 1996

EPRI TR-107285, -BWR Top Guide Inspection and Flaw Evaluation Guidelines," BWRVIP-26,

December 1996

EPRI TR-107286, UBWR Standby Liquid Control System/Core Plate AP Inspection and Flaw

Evaluation Guidelines," BWRVIP-27, April 1997

EPRI TR- 107396, "Closed Cooling Water Chemistry Guidelines," October 1997

EPRI TR-107515, "Evaluation of Thermal Fatigue Effects on Systems Requiring Aging

Management Review for License Renewal for the Calvert Cliffs Nuclear Power Plant"

EPRI TR-107521, -Generic License Renewal Technical Issues Summary," April

EPRI TR-107943, uEnvironmental Fatigue Evaluations of Representative BWR Components"

EPRI TR-108705, UBWR Vessel and Internals Project, Technical Basis for Inspection Relief for

BWR Internal Components with Hydrogen Injection"

EPRI TR-108727, "BWR Lower Plenum Inspection and Flaw Evaluation Guidelines," BWRVIP-47,

December 1997

EPRI TR-108728, -BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines,"

BWRVIP-41, October 1997

EPRI TR-108823, "BWR Shroud Support Inspection and Flaw Evaluation Guidelines,"

BWRVIP-38, September 1997

EPRI TR-108724, "Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines,"

BWRVIP-48, February 1998

EPRI TR-1 10356, "Evaluation of Environmental Thermal Fatigue Effects on Selected Components

in a Boiling Water Reactor Plant"

EPRI TR-112214, "BWR Vessel and Internals Project, Proceedings: BWRVIP Symposium,

November 12-13,1998"

EPRI TR-1 13596, -BWR Vessel and Internals Project BWR Reactor Pressure Vessel Inspection

and Flaw Evaluation Guidelines"

D-4
EPRI TR-114232, -BWR Core Shroud Inspection and Flaw Evaluation Guidelines," BWRVIP-76,

November 1999

EPRI TR-1 13596, "BWR Vessel and Internals Project BWR Reacior Pressure Vessel Inspection

and Flaw Evaluation Guidelines," BWRVIP-74, September 1999

EPRI TR-1 07396, -Closed Cooling Water Chemistry Guidelines"

GENERIC LETTERS (GLs)

NRC GL 85-20, "Resolution of Generic Issue 69: High Pressure Injection/Makeup Nozzle Cracking

in Babcock and Wilcox Plants," November 11,1985

NRC GL 88-01, "NRC Position on IGSCC in BWR Austenitic Stainless Steel Piping," 1989

NRC GL 88-11, -NRC Position on Radiation Embrittlement of Reactor Vessel Materials and Its

Impact on Plant Operations," July 12, 1988

NRC GL 88-14, "Instrument Air Supply System Problems Affecting Safety-Related Equipment,"

August 8, 1988

NRC GL 89-13, "Service Water System Problems Affecting Safety-Related Equipment," July 18,

1989

NRC GL 90-05, "Guidance for Performing Temporary Non-Code Repair of ASME Code

Class 1, 2, and 3 Piping," June 1990

NRC GL 91-17, 'Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear

Power Plants," October 1991

NRC GL 92-01, Revision 1, Supplement 1, "Reactor Vessel Structural Integrity," May 18, 1995

NRC GL 92-08, "Thermo-Lag 330-1 Fire Barriers," December 1992

NRC GL 96-04, "Boraflex Degradation in Spent Fuel Pool Storage Racks," June 26, 1996

GENERIC SAFETY ISSUES (GSIs)

GSI-166, "Adequacy of the Fatigue Life of Metal Components"

GSI-1 68, "Environmental Qualification of Electrical Components"

GSI-1 90, "Fatigue Evaluation of Metal Components for 60-Year Plant Life"

INFORMATION NOTICES (INs)

NRC IN 87-67, "Lesson Learned from Regional Inspections of Licenses Actions in Response to IE

Bulletin 80-11," December 31, 1987

D-5
NRC IN 91-46, "Degradation of Emergency Diesel Generator Fuel Oil Deliver Systems," July 1991

NRC IN 92-20, 'Inadequate Local Leak Rate Testing," March 1992

INSPECTION AND AUDIT REPORTS

NRC Inspection Report 50-237/03-04(DRS); 50-249/03-04(DRS); 50-254/03-04(DRS); 50-265/03-

04(DRS), "Dresden Nuclear Power Station, Quad Cities Nuclear Power Station, NRC License

Renewal Scoping/Screening Inspection, September 15, 2003

NRC Inspection Report 50-237/03-1 0(DRS); 50-249/03-1 0(DRS); 50-254/03-14(DRS); 50-265/03-

14(DRS), "Dresden Nuclear Power Station, Quad Cities Nuclear Power Station, NRC License

Renewal Aging Management Program Inspection, December 5, 2003

INSTITUTE OF ELECTRICAL AND ELECTRONICS ENGINEERS (IEEE)

ANS/IEEE Std. 450-1980, "IEEE Recommended Practice for Maintenance, Testing, and

Replacement of Large Storage Batteries for Generating Stations and Substations"

IEEE Std. 323-1974, "Qualifying Class 1E Equipment for Nuclear Power Generating Stations,"

1974

IEEE 43-1974, "Recommended Practice for Testing Insulation Resistance of Rotating Machinery"

IEEE 95-1977, "Recommended Practice for Insulation Testing of LargeAC Rotating Machinerywith

High Direct Voltage"

NATIONAL FIRE PROTECTION ASSOCIATION (NFPA)

NFPA-25, "Standard for the Inspection, Testing, and Maintenance of Water-Based Fire

Protection Systems"

NUCLEAR ENERGY INSTITUTE

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

54-The License Renewal Rule," August 2001

NUREG REPORTS

NUREG-0588, "Interim Staff Position on Environmental Qualification of Safety-Related

Electrical Equipment," November 1979

NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants," July 1980

NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking,

Resolution of Generic Technical Activity A 10," November 1980

NUREG-0737, "Clarification of TMI Action Plan Requirements," November 1980

D-6
NUREG-1275, Volume 3, "Operating Experience Feedback Report-Service Water System Failure

and Degradations," March 1993

NUREG-1339, 'Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear

Power Plants," June 1990

NUREG-1526, "Lessons Learned from Early Implementation of Maintenance Rule at Nine Nuclear

Power Plants," June 1995

NUREG-1568, "License Renewal Demonstration Program: NRC Observations and Lessons

Learned," December 1996

NUREG-1800, Standard Review Plan for the Review of License Renewal Applications for Nuclear

Power Plants," April 2001

NUREG-1801, Generic Aging Lessons Learned Report, July 2001

NUREG/CR-5704, "Effects of LWR Coolant Environment on Fatigue Design Curves of Austenitic

Stainless Steels," April 1999

NUREG/CR-6260, "Application of NUREG/CR-5999, 'Interim Fatigue Curves to Selected

Nuclear Power Plant Components," March 1995

NUREG/CR-6335, "Fatigue Strain-Life Behavior of Carbon and Low-Alloy Steels, Austenitic

Stainless Steels, and Alloy 600 in LRA Environments," August 1995

NUREG/CR-6384, "Literature Review of Environmental Qualification of Safety-Related Electric

Cables," Vol. 1, Brookhaven National Laboratory, prepared for the NRC, April 1996

NUREG/CR-6583, "Effects of LWR Coolant Environments in Fatigue Design Curves of Carbon and

Low-Alloy Steels," March 1998

REGULATORY GUIDES (RGs)

NRC RG 1.46, Revision 0, "Protection Against Pipe Whip Inside Containment," withdrawn August

11, 1985

NRC RG 1.89, Revision 1, "Environmental Qualification of Certain Electrical Equipment Important

to Safety for Nuclear Power Plants," June 1984

NRC RG1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials," May 1988

NRC RG 1.154, "Format and Content of Plant-Specific Pressurized Thermal Shock Safety Analysis

Reports for Pressurized Water Reactors"

NRC RG DG 1.188, "Standard Format and Content for Applications to Renew Nuclear Power Plant

Operating Licenses"

D-7
I I

U.S. DEPARTMENT OF ENERGY (DOE)

SAND 93-7070.UC-523, "Aging Management Guideline for Commercial Nuclear Power Plants -

Heat Exchangers" July 1984

SAND 96-0344, "Aging Management Guideline for Commercial Nuclear Power Plants -

Electrical Cables and Terminations," United States Department of Energy

USA STANDARDS INSTITUTE (USASI)

ANSI USAS B31.1.0, 'USA Standard Code for Pressure Piping," 1968

ANSI USAS B31.7, -USA Standard Code for Pressure Piping, Nuclear Power Piping," 1968

USAS B31.7, "Nuclear Power Piping"

Exelon Controlled Documents

Desktop Guide, Revision 2, "Scoping & Screening of Systems, Structures and Components"

GE-NE-LRTI-2000, Revision 6, "Technical Instruction for Exelon Dresden/Quad Cities License

Renewal Project - Scoping and Screening of Systems, Structures and Components for License

Renewal"

LRTI-16, Revision 0, "Identification of Non Safety Related Structures and Components Which

Spatially or Structurally Interact With Safety Related Systems"

PP-DRE Revision 03 560, "Systems and Structures Relied Upon to Demonstrate Compliance with

10 CFR 50.63 (Station Blackout) Dresden Station - Units 2 and 3"

PP-DRE-QDC Revision 02 AP, "Active/Passive Classification and Intended Function Determination

of Structures and Components"

PP-DRE-QDC Revision 01 SPACES, "Scoping and Screening Position Paper for Electrical

Components based on Electrical Spaces Approach for Aging Management Review"

PP-QDC Rev.03 SBO, "Systems and Structures Relied Upon to Demonstrate Compliance with

10CFR50.63 (Station Blackout) Quad Cities Station - Units 1 and 20

PP-QDC-DRE Rev 00 IN, "Treatment of Pipe/Equipment Insulation During Scoping and Screening

Systems for License Renewal"

D-8
NRC FORM 335 Us. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER

(9.2004) (Assigned by NRC, Add Vol.. Supp.. Rev..

NRCMD 3.7 and Addendum Number, If any.)

BIBLIOGRAPHIC DATA SHEET

(See hstuctions on the reverse) NUREG-1796

2. TITLE AND SUBTITLE 3. DATE REPORT PUBLISHED

Safety Evaluation Report MONTH YEAR

Related to the License Renewal of Dresden Nuclear Power Station, Units 2 and 3 and Quad

Cities Nuclear Power Station, Units I and 2 October 2004

4. FIN OR GRANT NUMBER

5. AUTHOR(S) 6. TYPE OF REPORT

Tae J. Kim final

Rajender Auluck final

7. PERIOD COVERED (tndusve Dates)

Jan. 3, 2003 - Oct. 8, 2004

8. PERFORMING ORGANIZATION -NAME AND ADDRESS (II NRC, pro.vid *Disin Ofttce orfRegin. U.S. NudearRegufatory Commisson. and maiai address; iFcontractor.

provide name and mafing address)

Division of Regulatory Improvement Programs

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

9. SPONSORING ORGANIZATION - NAME AND ADDRESS (If NRC, type Same as above Kcontractor, provide NRC Division. Office orRegion. U.S. NudearRegutatWyComnission. and mailing address.)

Same as above

10. SUPPLEMENTARY NOTES

11. ABSTRACT (200 wrds orlss)

This safety evaluation report (SER) documents the technical review of the Dresden Nuclear Power Station (DNPS). Units 2

and 3 and Quad Cities Nuclear Power Station (QCNPS), Units 1 and 2, license renewal application (LRA) by the U.S. Nuclear

Regulatory Commission (NRC) staff (staff). By letter dated January 3, 2003, Exelon Generation Company (Exelon or the

applicant) submitted the LRA for Dresden and Quad Cities (D/QCNPS) in accordance with Title 10, Part 54 of the Code of

Federal Regulations (10 CFR Part 54 or the Rule). Exelon requests renewal of the operating licenses for DNPS Unit 2

(LicenseNo. DRP-1 9), DNPS Unit 3 (UcenseNo. DRP-25), QCNPS Unit I (LicenseNo. DRP-29). and QCNPS Unit 2

(UcenseNo. DRP-30) for a period of 20 years beyond the current license expirations of midnight, December 22, 2009; January

12, 2011; December 14, 2012; and December 14, 2012, respectively.

DNPS is located in Grundy County, Illinois, on the shore of a man-made cooling lake, with the Illinois River to the north and

the Kankakee River to the east. The QCNPS is located in Rock Island County, IL, on the east bank of the Mississippi River

opposite the mouth of the Wapsipinicon River, and about 3 miles north of Cordova, IL. DNPS, Units I and 2, and QCNPS,

Units 2 and 3, each consist of a General Electric boiling-water reactor (BWR/3) authorized to operate individually at a steady

state reactor power level not to exceed 2957 megawatts-thermal, or approximately 850 megawatts-electric.

This SER presents the status of the staff's review of information submitted to the NRC through June 22, 2004, the cutoff

date for consideration in the SER. The staff identified open items and confirmatory items that had to be resolved before the

staff could make a final determination on the application. Sections 1.5 and 1.6 of this report summarize these items and their

resolutions. Section 6 provides the staffs final conclusion of its review of the DIQCNPS LRA.

12. KEY WORDSIDESCRIPTORS (List woos orphreses at Vwssist researchers Ih bocaaing the report.) 13. AVAILABILITY STATEMENT

10 CFR 54, license renewal, Dresden, Quad Cities, scoping and screening, aging management, unlimited

time-limited aging analysis, TLAA, safety evaluation report 14. SECURITY CLASSIFICATION

(This Page)

unclassified

(Mhs Report)

unclassified

15. NUMBER OF PAGES

16. PRICE

NRC FORM 335 (9-20(4) PRINTED ON RECYCLED PAPER
I

Printed i

n recycled

pape

Federal Recycling Program I
l-- .---.-- '-~o.-- . . . -~.-." -----. . -,- ..-

. UNITED STATES

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

OFFICIAL BUSINESS

.-... ___..__ J