DCL-10-158, CFR 54.21(b) Annual Update to the DCPP License Renewal Application and Amendment No. 34

CFR 54.21(b) Annual Update to the DCPP License Renewal Application and Amendment No. 34

ML110070143
Person / Time
Site:	Diablo Canyon
Issue date:	12/29/2010
From:	Becker J Pacific Gas & Electric Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
DCL-10-158
Download: ML110070143 (78)

Text

• Pacific Gas and Electric Company James R.Becker Diablo Canyon Power Plant Site Vice President Mail Code 104/5/601 P.Q Box 56 Avila Beach, CA 93424 805.545.3462 December 29, 2010 Internal: 691.3462 Fax: 805.545.6445 PG&E Letter DCL-1 0-158 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Docket No. 50-275, OL-DPR-80 Docket No. 50-323, OL-DPR-82 Diablo Canyon Units 1 and 2 10 CFR 54.21(b) Annual Update to the DCPP License Renewal Application and License Renewal Application Amendment No. 34

Dear Commissioners and Staff:

By letter dated November 23, 2009, Pacific Gas and Electric Company (PG&E) submitted an application to the U.S. Nuclear Regulatory Commission (NRC) for the renewal of Facility Operating Licenses DPR-80 and DPR-82, for Diablo Canyon Power Plant (DCPP) Units 1 and 2, respectively. The application included the license renewal application (LRA), and Applicant's Environmental Report -

Operating License Renewal Stage. As required by 10 CFR 54.21(b), each year following submittal of the LRA, an amendment to the LRA must be submitted that identifies any change to the current licensing basis (CLB) that materially affects the contents of the LRA, including the Final Safety Analysis Report (FSAR) supplement.

Enclosure 1 identifies DCPP LRA changes that are being made to: (1) reflect CLB that materially affect the LRA; and (2) reflect completed enhancements and commitments. Enclosure 2 contains the affected LRA pages with changes shown as electronic mark-ups (deletions crossed out and insertions underlined). The LRA update covers the period from July 1, 2009, through September 30, 2010. As a reviewer aid, all pages of the Appendix B aging manadement program section are provided, including unchanged pages, when there is a change on any of the pages in that section.

Changes to existing commitments are contained in the changes to LRA Table A4-1 in Enclosure 2.

A member of the STARS (Strategic Teaming and Resource Sharing) AlLiance Catlaway

• Comanche Peak e Diabto Canyon a Palo Verde s San Onofre ° South Texas Project

• WoLf Creek

Document Control Desk PG&E Letter DCL-1 0-158 December 29, 2010

.1 8"' Page 2 In PG&E Letter DCL-1 0-133, dated October 27, 2010 (Accession Number ML103050133), PG&E committed to revising LRA Chapters 2 and 3 Tables regarding the fire water storage and transfer tank intended functions. Based on further evaluation, PG&E concluded that no additional changes to LRA Chapters 2 and 3 are required.

If you have any questions regarding this response, please contact Mr. Terence L. Grebel, License Renewal Project Manager, at (805) 545-4160.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on December 29, 2010.

Sincer ly, James R. ker Site Vice President gwh/50362751 Enclosures cc: Diablo Distribution cc/enc: Elmo E. Collins, NRC Region IV Regional Administrator Nathanial B. Ferrer, NRC Project Manager, License Renewal Kimberly J. Green, NRC Project Manager, License Renewal Michael S. Peck, NRC Senior Resident Inspector Alan B. Wang, NRC Licensing Project Manager A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Caltaway

• Comanche Peak

• Diablo Canyon

• Palo Verde e San Onofre

• South Texas Project

• Wolf Creek

Enclosure 1 PG&E Letter DCL-10-158 Page 1 of,3 DCPP License Renewal Application (LRA) Changes Reflected in the Annual LRA Update Amendment 34 Affected LRA Section Reason for Change Section 2.3.3.1 Reflect the removal of the Unit 1 missile shield hoist from Section 4.7.1 containment during the sixteenth refueling outage beginning Table 4.7-1 October 2010. The Unit 2 missile shield hoist was removed Table A4-1, #26 during the fifteenth refueling outage beginning October 2009.

Section 4.3.2.2 Update to reflect the installation of the replacement reactor Table 4.3-4 vessel closure head (RRVCH) Unit 1.

Section 4.7.2 Appendix A1.5 All components penetrating the RRVCHs and welded to the inner Appendix A3.2.1.2 surfaces of the RRVCHs including the head vent piping and Table A4-1, #28, 29 elbows have been replaced with Alloy 690.

Appendix B2.1.5 Appendix B2.1.37 DCPP Unit 1 and 2 CRDM pressure housings, the core exit thermocouple nozzle assemblies, and the thermocouple nozzles have been replaced with the RRVCHs.

The replacement components have been qualified through the period of extended operation.

The design codes for the original RRVCH and associated components were deleted and Unit 1 was added to the design codes for the RRVCH and associated components.

Table A4-1 #18 Update to reflect correct U2 switchyard breakers 542/642.

Appendix B2.1.38 Table A4-1 #40, 41, 42 Calculation No. 2305C, including its acceptance criteria, was revised to be consistent with the latest revision of Procedure NDE VT 3C-1. The acceptance criteria are now consistent with ACI 349.3R Chapter 5 detailed quantitative acceptance criteria.

Table 2.3.1-2 Aluminum tape that was installed on the seams of the Unit 1 RMI Section 3.1.2.1.2 insulation panels of the pressurizer loop seals was removed Table 3.1.2-2 during the Unit 1 sixteenth refueling outage and the pressurizer Table A4-1 #47 relief valves were modified to steam seats eliminating reliance on safety related insulation.

Table 3.3.2-18 DCPP Feedwater System 03 does not specify flow accelerated corrosion (FAC) AMR lines (VIII.D1-9) for susceptible feedwater piping. Some feedwater piping is high temperature and pressure and wall thinning/FAC is an applicable aging effect/aging mechanism. Upon review of other systems, some components in the 05 system were also identified which should have FAC as an aging mechanism.

Section 2.3.4.5 To provide an updated list of boundary drawings for the Auxiliary Feedwater System.

Section 3.5.2.1.14 To revise aging effect for lubrite

Enclosure 1 PG&E Letter DCL-10-158 Page 2 of 3 Affected LRA Section Reason for Change Table 3.5.2-14 Table 3.4.2-1 To add an aging evaluation line for carbon steel piping in atmosphere/weather for the Main Steam System Section 3.3.2.1.14 To revise priming pump material from PVC to PPS for the Diesel Table 3.3.2-14 Generator System Table 2.3.3-5 LRA Tables 2.3.3-5 and 3.3.2-5 were revised to add the filter and Table 3.3.2-5 pressure boundary functions to the strainers and the filter Table A4-1, #49 function to the screens. LRA Appendix B2.1.13 has been Appendix B2.1.13 updated to reflect the PM of the strainers and screens managed by this program.

PG&E Letter DCL-10-128 dated October 12, 2010, evaluated components that support long term cooling for additional component intended functions. In the letter, PG&E indicated that other components in long term cooling paths will be evaluated to ensure additional components and intended functions are managed by the Fire Water System Aging Management Program B2.1.13.

All components in the condensate, makeup water, and fire protection systems that support the long term cooling function were evaluated for additional component intended functions.

Strainers in the makeup water system that support long term cooling and firewater inventory were identified. These strainers are currently cleaned and inspected on a 24-month-frequency controlled by the Diablo Canyon PM program. Debris screens on the Raw Water Storage Reservoir (RWSR) are in the flowpath which feeds long term cooling and the firewater system. These screens will be visually inspected on a 24-month frequency.

These PM activities will be performed as part of the Fire Water System Aging Management Program, B2.1.13.

Section 3.5.2.2.2.7 The responses to RAI sets 19, 21, and 25 require changes to the Table 3.1.2-1 TLAA report and corresponding TLAA sections.

Table 3.1.2-3 Table 3.1.2-4 Table 3.5.1 Table 3.5.2.14 Section 2.1.2.3.5 . Update to reflect correct 230-kV switchyard disconnects Figure 2.1-2 Section 2.5 Update to include aluminum to metal enclosed bus construction Section 3.6.2.1.6 material. Clarified in Table 3.6.1 that non-segregated metal Table 3.6.1 enclosed bus is consistent with NUREG-1801 and define Table 3.6.2-1 exceptions for Isolated Phase Bus.

Table A4-1, #45, 48, 53 Aligned the Implementation Schedule with the commitment statement.

Enclosure 1 PG&E Letter DCL-10-158 Page 3 of 3 Affected LRA Section Reason for Change Table 2.3.3-15 Update based on changes to the plant component data that was Section 3.2.2.1.1 used to develop the original LRA submitted on November 23, Table 3.2.2-1 2009.

Table 3.2.2-4 Section 3.3.2.1.2 Section 3.3.2.1.5 Table 3.3.2-2 Table 3.3.2-5 Table 3.3.2-12 Table 3.3.2-15 Table A4-1 #37 Added a note to indicate the commitment was deleted in PG&E Letter DCL-1 0-151.

E'nclosure 2 PG&E Letter DCL-10-158 Page 1 of 73 LRA Amendment 34 Affected LRA Sections, Tables, and Figures Section 2.1.2.3.5 Figure 2.1-2 Section 2.3.3.1 Section 2.3.4.5 Table 2.3.1-2 Table 2.3.3-5 Table 2.3.3-15 Section 2.5.

Section 3.1.2.1.2 Table 3.1.2-1 Table 3.1.2-2 Table 3.1.2-3 Table 3.1.2-4 Section 3.2.2.1.1 Table 3.2.2-1 Table 3.2.2-4 Section 3.3.2.1.2 Section 3.3.2.1.5 Section 3.3.2.1.14 Table 3.3.2-2 Table 3.3.2-5 Table 3.3.2-12 Table 3.3.2-14 Table 3.3.2-15 Table 3.3.2-18 Table 3.4.2-1 Section 3.5.2.1.14 Section 3.5.2.2.2.7 Table 3.5.1 Table 3.5.2-14 Section 3.6.2.1.6 Table 3.6-1 Table 3.6.2-1 Section 4.3.2.2 Table 4.3-4 Section 4.7.1 Table 4.7-1 Section 4.7.2 Appendix A1.5

PG&E Letter DCL-10-158 Page 2 of 73 LRA Amendment 34 Affected LRA Sections, Tables, and Figures Appendix A3.2.1.2 Table A4-1, #18, 26, 28, 29, 37, 40, 41,42, 45, 47, 48, 49, and 53.

Appendix B2.1.5 Appendix B2.1.13 Appendix B2.1.37 Appendix B2.1.38 Section 2.1 PG&E Letter DCL-10-158 SCOPING AND SCREENING METHODOLOGY Page 3 of 73 2.1.2.3.5 Station Blackout Criterion 10 CFR 54.4(a)(3) requires that plant SSCs within the scope of license renewal include all SSCs relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the regulations for SBO (10 CFR 50.63).

The NRC issued a supplemental safety evaluation report (SSER) in 1992 that concluded that PG&E's revised response to the SBO (10 CFR 50.63) for Units 1 and 2 is acceptable. The DCPP SBO analysis is discussed in FSAR Section 8.3.1.6. The SBO recovery path is identified on Figure 2.1-2, Station Blackout Recovery Path.

The DCPP SBO analysis was performed using the guidance provided in NUMARC 87-00, Rev. 0 and the coping time (the postulated maximum SBO duration) was determined to be four hours. During an SBO event, the*SBO analysis demonstrated that the plant could be safely shutdown utilizing either Buses G or H and their normally connected EDGs (Emergency AC (EAC) sources) and, thereby, the third EDG and its Bus F were declared the Alternate AC (AAC) source. However, during an SBO event, any of the three EDGs may be used as the AAC source. The SBO analysis takes credit for the hydraulic interconnection of the auxiliary saltwater systems between Unit 1 and 2 by manually opening FCV-601.

PG&E has committed to the "10 minute AAC" option, therefore a "coping assessment" is not required.

The 230 kV switchyard provides primary offsite power to each unit through the unit startup transformers 11 and 21. Startup transformers 11 and 21 are connected to the 230 kV switchyard through disconnect 211-1, 211-2, an4-211,3 and 213. Disconnects 211-1 and 211-23 areis connected to switchyard buses 1 and 2 via switchyard breaker 212 and disconnects 211, 213, 217, and 219. Switchyard breaker 212 has a bypass disconnect 215 which is also included in the primary recovery path. The startup ,

transformers, the overhead transmission lines, the disconnects, the switchyard breaker and the switchyard breaker control cables and connections are within the scope of license renewal.

The 500 kV switchyard provides backup offsite power to each unit through the unit main transformers 1 and 2 and auxiliary transformers 12 and 22. Unit auxiliary transformer 12 is connected to the Unit 1 main transformer via the Unit 1 isophase bus. The Unit 1 main transformer connects to the 500 kV switchyard through disconnects 533 and 631 via switchyard circuit breakers 532 and 632. Unit auxiliary transformer 22 is connected to the Unit 2 main transformer via the Unit 2 isophase bus. The Unit 2 main transformer connects to the 500 kV switchyard through disconnects 543 and 641 via switchyard circuit breakers 542 and 642. The unit auxiliary transformers, the unit main transformers, the isophase buses, the overhead transmission lines, the disconnects, the switchyard breakers and the switchyard breaker control cables and connections are within the scope of license renewal.

Section 2.1 PG&E Letter DCL-1 0-158 SCOPING AND SCREENING METHODOLOGY Page 4 of 73 A position paper was created to summarize the results of a review of the SBO documentation for DCPP. The position paper identifies the SSCs credited with coping and recovering from a SBO. The SSCs identified in the SBO position paper were used in scoping evaluations to identify SSCs that demonstrate compliance with 10 CFR 50.63.

SSCs classified as satisfying criterion 10 CFR 54.4(a)(3) related to SBO were identified as within the scope-of license renewal.

Section 2.1 PG&E Letter DCL-1 0-158 SCOPING AND SCREENING METHODOLOGY Page 5 of 73 Figure 2.1-2 Station Blackout Recovery Path Section 2.3 PG&E Letter DCL-1 0-158 SCOPING AND SCREENING RESULTS:

Page 6 of 73 MECHANICAL SYSTEMS 2.3.3.1 Cranes and Fuel Handling System

System Description

Cranes Overhead load handling systems provide lifting and maneuvering capability in various buildings and structures (e.g. auxiliary, containment, fuel, turbine and intake structures) on the site. These systems are composed of cranes, crane-rails hoists, elevators, monorails, and trolleys.

Crane supports are evaluated with their appropriate structure in Section 2.4.

The following cranes, monorails and trolleys are within the scope of license renewal:

Component Name Fuel Handling Building Overhead Crane (including rails)

Fuel Handling Building Overhead Crane Trolley (including rails)

Intake Structure Gantry Crane (including rails)

Intake Structure Gantry Crane Trolley (including rails)

Building Heater Reboiler 0-1 Monorail Motor Aux Feedwater Pump 1/2-2 Monorail RHR Heat Exchanger 1/2-1, 1/2-2 Monorail Motor-Gen Set 1/2-1 Monorail Motor-Gen Set 1/2-2 Monorail Spent Fuel Area Bridge Crane (Dual Hoist) (including rails)

RHR Pump 1/2-1, 1/2-2 Monorail Hoists CCW Pump 1/2-1, 1/2-2, 1/2-3 Monorail Charging Pump 1/2-1, 1/2-2 Monorail Charging Pump 1/2-3/Cont Spray Pump Monorail Safety Injection Pump 1/2-1, 1/2-2 Monorail Containment Polar Crane (including rails)

Containment Polar Crane Trolley (including rails)

Reactor Cavity Manipulator Crane 1/2-1 (including rails)

Reactor Cavity Manipulator Crane 1/2-1 Trolley (including rails)

Containment Dome Service Crane Reactor Cavity Service Jib Crane Head Stud Tensioner Monorail Missile Shield Hoi.*

Containment Equipment Hatch Monorail Moisture Separator Reheater 1/2-2A Monorail Turbine Building Bridge Crane (including rails)

Turbine Building Bridge Crane Trolley (including rails)

Monorail for Electrical Pull Box Covers BPO14 Through BP020 Section 2.3 PG&E Letter DCL-10-158 SCOPING AND SCREENING RESULTS:

Page 7 of 73 MECHANICAL SYSTEMS 2.3.4.5 Auxiliary Feedwater System License Renewal Boundary Drawings The license renewal boundary drawings for the auxiliary feedwater system are listed below:

LR-DCPP-03B-106703-03 LR-DCPP-03B-106703-04 LR-DCPP-03B-107703-03 LR-DCPP-03B-107703-04 Section 2.3 PG&E Letter DCL-1 0-158 SCOPING AND SCREENING RESULTS:

Page 8 of 73 MECHANICAL SYSTEMS Table 2.3.1-2 Reactor Coolant System Component Type I Intended Function IR6Ui atiGR Insulate (MI "hanial)

Section 2.3 PG&E Letter DCL-1 0-158 SCOPING AND SCREENING RESULTS:

MECHANICAL SYSTEMS Page 9 of 73 Table 2.3.3-5 Makeup Water System (Continued)

Component Type I Intended FunctionI Strainer Filter Leakage Boundary (spatial)

PressureBoundary Section 2.3 PG&E Letter DCL-10-158 SCOPING AND SCREENING RESULTS:

MECHANICAL SYSTEMS Page 10 of 73 Table 2.3.3-15 Lube Oil System Piping Component Type [ Intended Function Leakage Boundary (spatial)

Pressure Boundary Valve Leakage Boundary (spatial)

Pressure Boundary Section 2.5 PG&E Letter DCL-1 0-158 SCOPING AND SCREENING RESULTS:

Page 11 of 73 ELECTRICAL AND INSTRUMENTATION AND CONTROLS 2.5 SCOPING AND SCREENING RESULTS: ELECTRICAL AND INSTRUMENTATION AND CONTROL SYSTEMS The scoping and screening results for electrical and instrument and control system components consist of a list (Table 2.5-1, Electrical and I&C Component Groups Requiring Aging Management Review) of component types that require AMR.

Using the plant "spaces" approach, all electrical and instrument and control components were reviewed as a group regardless of the system assigned to each component. Bounding environmental conditions were used to evaluate the identified aging effect(s) with respect to component function(s) to determine the passive component groups that require AMR. This methodology is discussed in Section 2.1.3.3 and is consistent with the guidance in NEI 95-10.

The interface of electrical and instrument and control components with other types of components and the assessments of these interfacing components are provided in the appropriate mechanical or structural sections. The evaluation of electrical racks, panels, frames, cabinets, cable trays, conduit, manhole, duct banks, transmission towers and their supports is provided in the structural assessment documented in Section 2.4.

The following electrical component groups were evaluated to determine the groups that require AMR:

• Cable Connections (metallic parts)

• Connectors (exposed to borated water)

" Fuse Holders (not part of a larger assembly)

• High Voltage Insulators

" Insulated Cable and Connections (includes the following):

0 Electrical cables and connections not subject to 10 CFR 50.49 EQ requirements 0 Electrical cables and connections used in instrumentation circuits not subject to 10 CFR 50.49 EQ requirements that are sensitive to reduction in conductor insulation resistance 0 Inaccessible Medium-Voltage Electrical Cables not subject to 10 CFR 50.49 EQ requirements 0 Metal Enclosed Bus (includes the following):

Section 2.5 PG&E Letter DCL-10-158 SCOPING AND SCREENING RESULTS:

Page 12 of 73 ELECTRICAL AND INSTRUMENTATION AND CONTROLS o Non-segregated Phase Bus 0 Bus bar and connections 0 Bus enclosure 0 Bus Insulation and insulators o Isolated Phase Bus

" Bus bar and connections

" Bus enclosure

" Bus insulators

" Switchyard Bus and Connections

" Terminal Blocks (not part of a larger assembly)

• Transmission Conductors and Connections

• Lightning Rods

• Electrical equipment subject to 10 CFR 50.49 environmental qualification (EQ) requirements

• Penetrations, Electrical

• Grounding conductors

" Cable Tie Wraps A license renewal boundary drawing (LR-DCPP-ELEC-5021 10) was created from the plant one-line diagram. The plant one-line diagram schematically shows the portions of the plant AC electrical distribution system, including the SBO recovery path, that are included within the scope of license renewal.

Section 3.1 PG&E Letter DCL-1 0-158 AGING MANAGEMENT OF REACTOR VESSEL, Page 13 of 73 INTERNALS, AND REACTOR COOLANT SYSTEM 3.1.2.1.2 Reactor Coolant System Materials The materials of construction for the reactor coolant system component types are:

• Carbon Steel eInsulation FibIrglass

• Stainless Steel

• Stainless Steel Cast Austenitic Environment The reactor coolant system component types are exposed to the following environments:

• Borated Water Leakage

• Closed-Cycle Cooling Water

• Demineralized Water

• Dry Gas

• Plant Indoor Air

• Reactor Coolant

• Treated Borated Water Aging Effects Requiring Management The following reactor coolant system aging effects require management:

• Cracking

• Loss of fracture toughness

• Loss of material

• Loss of preload

• Reduction of heat transfer Section 3.1 AGING MANAGEMENT OF REACTOR VESSEL, PG&E Letter DCL-10-158 INTERNALS, AND REACTOR COOLANT SYSTEM Page 14 of 73 Table 3.1.2-1 Reactor Vessel, Internals, and Reactor Coolant System - Summary of Aging Management Evaluation -

Component Type Intended Material Environment Aging Effect Aging Management Program NUREG- Table 1 Notes Function IIRequiring 11801 Vol. Item RVNozzle Suppor S eabo P indoor_

ACManagement _3.1.1tem.07 2IV._-2-_ _A PRV Nozzle Support S Carbon Plant indoor Air Cumulative Time Limited Aging Analysis IV.A2- 3.1.1.0407 GA Pads Steel (Ext) Fatigue evaluated for the period of 2nC2-10

____ _ ____ __ Damag 111 extended operation -

RVI Core Barrel DF, Stainless Reactor Cumulative Time Limited Aging Analysis IV.B2-31 3.1.1.05 A Assembly SHSLD, Steel Coolant (Ext) Fatigue evaluated for the period of

_SS I Damage extended operation __1-__2 2_ _

RV Core Support SS Nickel Reactor Cumulative Time Limited Aging Analysis IV.B2- 3.1.1.059 GA Lugs Alloys Coolant (Ext) Fatigue evaluated for the period of 34A2-21 I IDamage extended operation Section 3.1 PG&E Letter DCL-1 0-158 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Page 15 of 73 Table 3.1.2-2 Reactor Vessel, Internals, and Reactor Coolant System - Summary of Aging Management Evaluation-Section 3.1 PG&E Letter DCL-10-158 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Page 16 of 73 Table 3.1.2-3 Reactor Vessel, Internals,and Reactor Coolant System - Summary of Aging Management Evaluation-Section 3.1 PG&E Letter DCL-1 0-158 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Page 17 of 73 Table 3.1.2-4 Reactor Vessel, Internals, and Reactor Coolant System - Summary of Aging Management Evaluation-Steam Generators(Continued)

Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.

Management 2 Item SG Feedwater ODF Carbon Steel Secondary Water Cumulative Time Limited Aging IV.D1-11 3.1.1.07 CD Ring (Ext) Fatigue Damage lAnalysis evaluated for the period of extended opeýration SG Feedwater DF Nickel Alloy Secondary Water Cumulative Time Limited Aging IV.D1-21 3.1.1.06 C Ring (intExt) Fatigue Damage- Analysis evaluated for

!the period of extended operation SG Primary PB Carbon Steel Borated Water- Cumulative Time Limited Aging IV.C2-10 3.1.1.07 C, 6 Man way Leakage (Ext) Fatigue Damage Analysis evaluated for Covers the period of extended operation i i SG Primary jPB Stainless Reactor Coolant Cumulative Time Limited Aging IV.D1-98 3.1.1.10 AG, 5 Manway Steel (ex-tExt) Fatigue Damage Analysis evaluated for Covers the period of extended operation SG Secondary PB Nickel Alloys jSecondary Water Cumulative Time Limited Aging IV.D1-21 3.1.1.06 C, 4 Manway and (e-lnt) Fatigue Damage Analysis evaluated for Handhole the period of extended operation Covers 4 S SG Secondary PB Carbon Steel PlantIndoor Air Cumulative Time Limited Aging IV. C2- 10 3.1.1.07 C, 7 Manway and (Ext) Fatigue Damage Analysis evaluated for Handhole the period of extended Covers operation 4'

______ 4- 4- 4 SG Tubes !T4-HT, PB Nickel Alloy Reactor Coolant Cumulative Time-limited Aging IV.D1-21 14.2.2.06 jA (Int) fatigue damage Analysis evaluated. for Ithe period of extended

____________ operation Section 3.1 PG&E Letter DCL-1 0-158 AGING MANAGEMENT OF REACTOR VESSEL, INTERNALS, AND REACTOR COOLANT SYSTEM Page 18 of 73 Table 3.1.2-4 Reactor Vessel, Internals,and Reactor Coolant System - Summary of Aging Management Evaluation -

Steam Generators(Continued)

Component Intended Material Environment Aging Effect Aging Management NUREG- Table 1 Item Notes Type Function Requiring Program 1801 Vol.

___ Management 2 Item SG Tubes T-4HT, PB NickelAlloy SecondaryWater Cumulative Time-limited Aging IV.D1-21 4.2.2.06 A (Ext) fatigue damage Analysis evaluated for the period of extended operation 4 Component Is secondary manway or handhole pads.

5 Component is the primary manway insert plates.

6 Component is the primary manway cover.

7 Component is secondary manway or handhole cover.

Section 3.2 PG&E Letter DCL-1 0-158 AGING MANAGEMENT OF EGGINEERED SAFETY FEATURES Page 19 of 73 3.2.2.1.1 Safety Injection System Materials The materials of construction for the safety injection system component types are:

Carbon Steel Carbon Steel with Stainless Steel Cladding Cast Iron Copper Alloy (> 15 percent Zinc)

Elastomer Glass Stainless Steel Stainless Steel Cast Austenitic Environment The safety injection system components are exposed to the following environments:

Borated Water Leakage Closed-Cycle Cooling Water Demineralized Water Dry Gas Encased in Concrete Lubricating Oil Plant Indoor Air Reactor Coolant Treated Borated Water Ventilation Atmosphere Aging Effects Requiring Management The following safety injection system aging effects require management:

Cracking Hardeningand loss of strength Loss of fracture toughness Section 3.2 PG&E Letter DCL-10-158 AGING MANAGEMENT OF EGGINEERED SAFETY FEATURES.

Page 20 of 73 Table 3.2.2-1 Engineered Safety Features- Summary of Aging Management Evaluation - Safety Injection System (Continued)

Component Intended Material Environment Aging Effect Aging Management Program NUREG- Table I Notes Type Function Requiring 1801 Vol. Item Management 2 Item

[ inn Iopl9r=Mrr Pilnf InrlrqrrAir PI-Iqrfininn and I Fternal.Surface.s Mnnitnrinr V1 I F2-7 i3 3' 1 11f V.*ml.I 1 Joint 4 (Ext) loss of strength Program(B2.1.20) I Expansion PB iElastomer Ventilation 1Hardening and Inspection of Internal Surfaces in VII. F2-7 3.3.1.11 Joint _ _Atmosphere (Int) loss of strength Miscellaneous Piping and Ducting Components (B2.1.22)

-,J Section 3.2 PG&E Letter DCL-1 0-158 AGING MANAGEMENT OF EGGINEERED SAFETY FEATURES Page 21 of 73 Table 3.2.2-4 Engineered Safety Features- Summary of Aging Management Evaluation - ContainmentHVAC System (Continued)

Component Intended Material Environment Aging Effect Aging Management Program NUREG- Table 1 Type Function Requiring 1801 Vol. Item Management 2 Item Damper Stainless PlantIndoor None None V1.J-15 13.3.1.94 Damper I7-Ss Ss iSteel Stainless F

Air (Ext)

Ventilation

,

None 4

None 4

Vll.J-15 13.3.1.94 Steel Atmosphere (Int)

Plant Specific Notes:

8 The component is a SS damperhousing with an internalenvironment of ventilation atmosphere. The component is located inside containment. Operating temperatureis normally well above dew point. Condensationinside the component is not expected. Therefore, plant indoorair (uncontrolled)is used interchangeablywith ventilation atmosphere (internal).

Section 3.3 PG&E Letter DCL-10-158 AGING MANAGEMENT OF AUXILIARY SYSTEMS Page 22 of 73 3.3.2.1.2 Spent Fuel Pool Cooling System Materials The materials of construction for the spent fuel pool cooling system component types are:

Carbon Steel Carbon Steel with Stainless Steel Cladding Elastomer Glass Stainless Steel Stainless Steel Cast Austenitic Environment The spent fuel pool cooling system component types are exposed to the following environments:

Borated Water Leakage Closed-Cycle Cooling Water Demineralized Water Encased in Concrete LubricatingOil Plant Indoor Air Treated Borated Water Aging Effects Requiring Management The following spent fuel pool cooling system aging effects require management:

Hardening and loss of strength Loss of material Loss of preload Reduction of heat transfer Aging Management Programs The following aging management programs manage the aging effects for the spent fuel pool cooling system component types:

Section 3.3 PG&E Letter DCL-1 0-158 AGING MANAGEMENT OF AUXILIARY SYSTEMS Page 23 of 73 Bolting Integrity (B2.1.7)

Boric Acid Corrosion (B2.1.4)

Closed-Cycle Cooling Water System (B2.1.10)

External Surfaces Monitoring Program (B2.1.20)

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)

Lubricating Oil Analysis (B2.1.23)

One-Time Inspection (B2.1.16)

Water Chemistry (B2.1.2)

Section 3.3 PG&E Letter DCL-10-158 AGING MANAGEMENT OF AUXILIARY SYSTEMS Page 24 of 73 3.3.2.1.5 Makeup Water System Materials The materials of construction for the makeup water system component types are:

Asbestos Cement Carbon Steel Carbon Steel (Galvanized)

Cast Iron Cast Iron (Gray Cast Iron)

Copper Alloy Elastomer Polyvinyl Chloride (PVC)

Stainless Steel Stainless Steel Cast Austenitic Environment The makeup water system components are exposed to the following environments:

Atmosphere/ Weather Buried Demineralized Water Encased in Concrete LubricatingOil Plant Indoor Air Potable Water Raw Water Sodium Hydroxide Sulfuric Acid Aging Effects Requiring Management The following makeup water system aging effects require management:

Hardening and loss of strength Loss of material Section 3.3 PG&E Letter DCL-10-158 AGING MANAGEMENT OF AUXILIARY SYSTEMS Page 25 of 73 Loss of material, cracking and changes in material properties Loss of preload Aging Management Programs The following aging management programs manage the aging effects for the makeup water system component types:

Bolting Integrity (B2.1.7)

Buried Piping and Tanks Inspection (B2.1.18)

External Surfaces Monitoring Program (B2.1.20)

Fire Water System (B2.1.13)

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22)

Lubricating Oil Analysis (B2.1.23)

One-Time Inspection (B2.1.16)

Selective Leaching of Materials (B2.1.17)

Water Chemistry (B2.1.2)

Section 3.3 PG&E Letter DCL-10-158 AGING MANAGEMENT OF AUXILIARY SYSTEMS Page 26 of 73 3.3.2.1.14 Diesel Generator System Materials The materials of construction for the diesel generator system component types are:

Aluminum Carbon Steel Cast Iron Copper Alloy Ductile Iron Glass Polyvi nyl Chloride (PVC)Polyphenylene Sulfide (PPS)

Stainless Steel Section 3.3 PG&E Letter DCL-1 0-158 AGING MANAGEMENT OF AUXILIARY SYSTEMS Page 27 of 73 Thhlt*..' .i 2-2 Auinliary Syste~ms - Summarv of Aaina Manaaement Evaluation- Sne~nt FuelI Pool Coolina Systdem Table 3 3-- ..... .. - .......... IV, n"'a-n- - ... Fuel P o l-- S Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.

I Management 2 Item I I Piping LBS Stainless Lubricating Oil (Int) Loss of Material Lubricating Oil Analysis VII.E1-15 3.3.1.33 B Steel (B2.1.23) and One-Time Inspection (B2.1.16)

Piping LBS, PB Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 A Steel (Ext)

Valve LBS Stainless Lubricating Oil (Int) Loss of material Lubricating Oil Analysis VII.El-15 3.3.1.33 - B Steel

__________

________

______ ________________________Inspection (B2.1.23) and (B2.One-Time 1.16) ______ ____

Valve LBS Stainless Plant IndoorAir None None VII.J-15 3.3.1.94 A ISteel (Ext) I I I Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS PG&E Letter DCL-1 0-158 Page 28 of 73 Table 3.3.2-5 Auxiliarv Systems - Summarv of Aa*inca Manaaement Evaluation - Makeun Water Svstem (Cnntinui.d)

TablI - teee ux 'r M a.vteria - SEnvironment u m r f i a M n eff nt Mn - Mtlaia e W t r v t m Co t n e l Component Intended Material Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.

Management 2 Item Piping PB Stainless Lubricating Oil (Int) Loss of material Lubricating Oil Analysis VII. C2-12 3.3.1.33 B Steel (B2.1.23) and One-Time _

Inspection (B2.1.16) _

Screen FIL Stainless Raw Water (Ext) Loss of material Fire Water System VII. G- 19 3.3.1.69 B

...... Steel (B2.1.13) _

Strainer FIL, LBS, Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 'A PB _ Stee (Ext) ................... __

Strainer FIL, LBS, Stainless Raw Water (Int) Loss of material Fire Water System VII.G-19 3.3.1.69 B PB Steel __(B2.1.13)

Valve PB Stainless Lubricating Oil (Int) Loss of material Lubricating Oil Analysis VII. C2-12 3.3.1.33 B Steel

_ _ _ _ I . _ _ __ _

(B2.1.23) and One-Time

. Inspection (B2.1.16)

__ _ .

_

_ _ _1 _

Section 3.3 AGING MANAGEMENT OF AUXILIARY SYSTEMS PG&E Letter DCL-1 0-158 Page 29 of 73 Table 3.3.2-12 Auxiliary Systems - Summary of Acring Management Evaluation - Fire ProtectionSystem (Continued)

Component Intended Material Environment Aging Effect Aging Management Program NUREG- Table 1 Notes Type Function Requiring 1801 Vol. Item Management 2 Item Valve Castlron DryGas(Int) None None VILJ-23 13.3.1.97 fA

Enclosure 2 Section 3.3 PG&E Letter DCL-1 0-158 AGING MANAGEMENT OF AUXILIARY SYSTEMS Page 30 of 73 Table 3.3.2-14 Auxiliary Systems - Summary of Aling Management Evaluation - Diesel GeneratorSystem Component Intended Material Environment Aging Effect Aging Management NUREG- Table 1 Item Notes Type Function Requiring Program 1801 Vol.

Management 2 Item

• Pump LBS, SIA Polyvinyl, Fuel Oil (Int) INone None None None F, 2

{PG}I Ghletide-Polyphenylene SSufide (PPS)

Pump LBS, SIA Povinyl FPlant Indoor Air None None None None F, 2 Chlorde- Ext) 4PVG}

Polyphenylene Sufide.PPS.

Notes for Table 3.3.2-14:

Plant Specific Notes:

2 PPS is a thermoplastic and has been evaluated for ionizing radiation,ozone, UV, thermal exposure, and loss of material due to aggressive chemical attack. No aging effects are expected for this material relative to its operatingenvironment.

Section 3.3 PG&E Letter DCL-10-158 AGING MANAGEMENT OF AUXILIARY SYSTEMS Page 31 of 73 Table 3.3.2-15 Auxiliary Systems - Summary of Acing Management Evaluation- Lube Oil System Component Intended Material Environment Aging Effect Aging Management NUREG- Table 1 Item Notes Type Function Requiring Program 1801 Vol.

Management 2 Item Piping LBS, PB Stainless Lubricating Oil (Int) Loss of material Lubricating Oil Analysis VII.H2-17 3.3.1.33 B Steel (B2.1.23) and One-Time F +

Inspection (B2.1.16)

Piping LBS, PB TStainless Plant Indoor Air None None VII.J-15 3.3.1.94 !A

_Steel (Ext)

Valve LBS, PB ..Stainless Lubricating Oil (Int) ILoss of material Lubricating Oil Analysis VII.H2-17 13.3.1.33 B ISteel (B2.1.23) and One-Time Inspection (B2.1.16)

Valve LBS, PB Stainless IPlant Indoor Air None None VII.J-15 13.3.1.94 A Steel L(Ext)

Section 3.3 PG&E Letter DCL-10-158 AGING MANAGEMENT OF AUXILIARY SYSTEMS Page 32 of 73 Table 3.3.2-18 Auxiliary Systems - Summary of Aging Management Evaluation - Miscellaneous Systems in scope ONLY for Criterion 10 CFR 54.4 (a)(2)

Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item Notes Type Function Requiring Program 1801 Vol.

Management 2 Item Valve LBS Carbon Steel Secondary Water Wall Thinning Flow Accelerated VIII.D1-9 3.4.1.29 B (Int) Corrosion (B2.1.6)

Valve LBS Carbon Steel Steam (Int) Wall Thinning Flow Accelerated VIII. C-5 3.4.1.29 B I__ _ _Corrosion I_ (B2.1.6) I I y

Section 3.4 AGING MANAGEMENT OF STEAM AND PG&E Letter DCL-1 0-158 POWER CONVERSION SYSTEM Page 33 of 73 Table 3.4.2-1 Steam and Power Conversion System - Summary of Aging Management Evaluation- Turbine Steam Suppl ySystem Notes Component Intended Material Environment Aging Effect Aging Management NUREG- Table 1 Item Type Function Requiring Program 1801 Vol.

Management 2 Item Piping SIA, SS Carbon Steel Atmosphere/ Loss of material Inspection of Internal VIII.BI- 3. 4.1.303B4-B Weather (Int) Surfaces in 6V!4k-H-8 .-2 Miscellaneous Piping and Ducting Components (B2.1.22)Extenal-iDr-e, rrnp*' (1*32* 33 Section 3.5 PG&E Letter DCL-10-158 AGING MANAGEMENT OF CONTAINMENTS, Page 34 of 73 STRUCTURES AND COMPONENT SUPPORTS 3.5.2.1.14 Supports Aging Effects Requiring Management The following supports aging effects require management:

Cracking Loss of material Loss of material, crackin4g Loss of mechanical function Reduction in concrete anchor capacity Section 3.5 PG&E Letter DCL-10-158 AGING MANAGEMENT OF CONTAINMENTS, Page 35 of 73 STRUCTURES AND COMPONENT SUPPORTS 3.5.2.2.2.7 Cumulative Fatigue Damage due to Cyclic Loading Analyses of fatigue in component support members, anchor bolts, and welds for Group B1.1, B1.2, and B1.3 component supports (for ASME III Class 1, 2, and 3 piping and components, and for Class MC BWR containment supports) are TLAAs as defined in 10 CFR 54.3 only if a CLB fatigue analysis exists. With the exception of the Unit 2 PressurizerValve Support Bracket discussed in Section 4.3.2.4, tThe review identified no TLAAs supporting design of these components at DCPP.

DCPP ASME Class 1 piping is designed to code editions and addenda before 1986, which therefore precede cycle limits for allowable stress in supports (see Section 4.3.2.7). DCPP ASME Class 2 and 3 piping and components require no fatigue or cycle design analysis for their supports, and no other similar analysis exist for supports for those components at DCPP.

DCPP is a PWR and does not have Class MC BWR containment supports.

Section 3.5 AGING MANAGEMENT OF CONTAINMENTS, PG&E Letter DCL-10-158 STRUCTURES AND COMPONENT SUPPORTS Page 36 of 73 Table 3.5.1 Summary of Aging Management Evaluations in Chapters II and Ill of NUREG-1801 for Containments, Structures. and Component Supports (Continued)

Item Component Type Aging Effect / Mechanism Aging Management Further Discussion Number Program Evaluation Recommended 3.5.1.42 Groups B1.1, B1.2, Cumulative fatigue damage TLAA, evaluated in Yes, TLAA and B1.3.: support (CLB fatigue analysis exists) accordance with Consistent with NUREG-members: anchor 10 CFR 54.21(c) 41801.

Er 4; , e ,, , .,,.. , ,1.

lbolts, welds v i;, -- # - -ri A A -- A-C-A  ;-

SSee further evaluation in ISection 3.5.2.2.2.7.

Section 3.5 PG&E Letter DCL-10-158 AGING MANAGEMENT OF CONTAINMENTS, STRUCTURES AND COMPONENT SUPPORTS Page 37 of 73 Table 3.5.2-14 Containments, Structures, and Component Supports - Summary of Aging Management Evaluation -

Supports (Continued)

Component Intended Material Environment Aging Effect Aging Management NUREG- Table 1 Item Notes Type Function Requiring Program 1801 Vol.

Management 2 Item Supports SS Carbon Steel Plant Indoor Air Cumulative ITime Limited Aging 1111.B1.1-12 3.5.1.42 !A, 1 ASME 1 (Structural)(Ext) Fatigue Damage !Analysis evaluated for

!the period of extended loperation Supports ES, SS Lubrite Plant Indoor Air Loss of 1ASME Section XI, 111l.B1.2-3 3.5.1.56 PA (Structural) (Ext) mechanical Subsection IWF functionL-ess-ef- (B2.1.29)

_______

- ______ _____ _______ __ ____ _______material, cracking; ___________ _____ _____ _ _ _ _

Notes for Table 3.5.2-14:

Standard Notes:

A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1801 item. for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

F Material not in NUREG-1 801 for this component.

J Neither the component nor the material and environment combination is evaluated in NUREG-1 801.

Plant Specific Notes:

None 1 TLAA is for Pressurizer Valve Support Bracket (Unit 2 only).

Section 3.6 PG&E Letter DCL-1 0-158 AGING MANAGEMENT OF ELECTRICAL AND Page 38 of 73 INSTRUMENTATION AND CONTROLS 3.6.2.1.6 Metal Enclosed Bus Materials The materials of construction for metal enclosed bus are:

0 Carbon Steel o Aluminum 0 Elastomer

• Porcelain

• Various Insulation Material (Electrical)

• Various Metals Used for Electrical Contacts Environment Metal enclosed bus is exposed to the following environments:

• Atmosphere/ Weather (Ext)

• Plant Indoor Air Aging Effects Requiring Management The following metal enclosed bus aging effects require management:

• Loosening of bolted connections

• Loss of material

• Hardening and loss of strength

• Embrittlement, cracking, melting, discoloration, swelling, or loss of dielectric strength leading to reduced insulation resistance (IR); electrical failure Aging Management Programs The following aging management program manages the metal enclosed bus:

• Metal Enclosed Bus (B2.1.36)

Section 3.6 PG&E Letter DCL-1 0-158 AGING MANAGEMENT OF ELECTRICAL AND INSTRUMENTATION AND CONTROLS Page 39 of 73 Table 3.6.1 Summary of Aaingr Management Evaluations in Chapter VI of NUREG-1801 for Electrical Components (Continued)

Item Component Type Aging Effect I Mechanism Aging Management Further Discussion Number Program Evaluation I I Recommended 3.6.1.07 Metal enclosed bus - Loosening of bolted Metal Enclosed Bus (B2.1.36) No Non-Segregated Metal Bus/connections connections due to thermal Enclosed Bus is cGonsistent cycling and ohmic heating with NUREG-1801. (solated Phase Bus takes exception

_ _for welded bus construction.

3.6.1.08 Metal enclosed bus - Reduced insulation resistance Metal Enclosed Bus (B2.1.36) No Non-Segregated Metal Insulation/insulators and electrical failure due to 3/4.

Enclosed Bus is cGonsistent various physical, thermal, with NUREG-1801. Isolated

,radiolytic, photolytic, and Phase Bus takes exception chemical mechanisms for un-insulated bus bars.

Enclosure 2 Section 3.6 PG&E Letter DCL-10-158 AGING MANAGEMENT OF ELECTRICAL AND INSTRUMENTATION AND CONTROLS Page 40 of 73 Table 3.6.2-1 Electricaland Instrument and Controls- Summary of Aging Management Evaluation- Electrical Comonents Component Intended Type Function Material T Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Vol.

2 Item Table 1 Item Notes Metal SS Aluminum Atmosphere! Loss of material Aging Management Program for None None F Enclosed Bus Weather (Ext) Metal Enclosed Bus (B2.1.36)

(Enclosure) 1Metal SS Aluminum PlantIndoor Air Loss of material Aging Management Programfor None None F Enclosed Bus (Ext) Metal Enclosed Bus (B2.1.36)

(Enclosyre Notes for Table 3.6.2-1:

Standard Notes:

A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

E Consistent with NUREG-1801 for material, environment, and aging effect, but a different aging management program is credited or NUREG-1 801 identifies a plant-specific aging management program.

F Materialnot in NUREG-1801 for this component.

J Neither the component nor the material and environment combination is evaluated in NUREG-1801.

Plant Specific Notes:

1 The Metal Enclosed Bus program (B2.1.36) is used to manage the aging effects for all metal enclosed bus components.

Section 4 PG&E Letter DCL-10-158 TIME-LIMITED AGING ANALYSES Page 41 of 73 4.3.2.2 Reactor Vessel Closure Heads and Associated Components Summary Description The reactor pressure boundary components associated with the reactor vessel closure head are the CRDM pressure housings, core exit thermocouple nozzle assemblies (CETNAs), thermocouple nozzles, and thermocouple columns. The CRDM pressure housings, the CETNAs, and the thermocouple nozzles were replaced with the replacement reactor vessel closuire head (RRVCH) in 2009 for Unit 2 and ,wll be replaced with the RRVCH in 2010 for Unit 1. Table 4.3-4 lists the applicable design codes for the original (Unit 1) and replacement (Unhit 2) reactor vessel closure heads and associated components.

Analysis The replacement reactor vessel closure heads, CRDM pressure housings, CETNAs, and thermocouple nozzles will-behave been qualified for 50 years, which will extend the design lives of the RRVCHs, CRDM pressure housings, CETNAs, and thermocouple nozzles beyond the period of extended operation.

The only reactor pressure boundary components associated with the reactor vessel closure head that will-net-behave not been replaced are the thermocouple columns.

These components were originally designed to a 40-year life. The fatigue analysis for the thermocouple column resulted in a maximum design CUF of 0.29. The design CUF was multiplied by 1.5 (60/40) to determine if the CUF would exceed 1.0.

The projection assumed the full number of the design transients during the first 40 years of operation and that the transients continue to occur at that rate during the period of extended operation. The resulting CUF for 60 years of operation is 0.435, and therefore the TLAA remains valid for the period of extended operation.

Disposition: Validation, 10 CFR 54.21(c)(1)(i); Revision, 10 CFR 54.21(c)(1)(ii)

Validation - RRVCH The Unit 1 and 2 replacement reactor vessel heads including the RRVCHs, CRDMs, CETNAs, and thermocouple nozzles will-behave been analyzed for a 50-year design life, which will extend beyond the period of extended operation. Therefore the fatigue analyses for the RRVCHs, CRDMs, CETNAs, and thermocouple nozzles will remain valid for the period of extended operation, in accordance with 10 CFR 54.21(c)(1)(i).

Revision - Thermocouple Column with Low Design Basis Usage Factors The current fatigue analyses of the thermocouple column demonstrate that the maximum 40-year usage factor is 0.29. If multiplied by 1.5 (60/40) to account for the 60-year period of extended operation, these results do not exceed 0.6, providing a large margin to the code acceptance criterion of 1.0. The analyses of these Section 4 PG&E Letter DCL-1 0-158 TIME-LIMITED AGING ANALYSES Page 42 of 73 components are therefore valid for the period of extended operation, in accordance with 10 CFR 54.21(c)(1)(ii).

Table 4.3-4 Design Codes for the .QFýiaIand-Replacement Reactor Vessel Closure Heads and Associated Components Component Code EditionlAddendum Re.ctor..e...l.C....rc H (Unit"*llASME 1' Code, Sec*tin III , Class E)Figna!4AddeRda)

Contro.. Ro.d Drive. Mechanf.isms ASM1E Code, Section !II, Class A ....... (RE)

Pressurle Hou1ings (Unit 1 or)iginal) Addenda)

Core Exit ThemoCosuple Nozzle ASSME Code, Setion I!aI 192 Edition through the assemb,-es ( 1oiginal),.2002nd Su 1982 Addenda ThermocoGuple Nozzle (Un~it 1 original) ASME Code, Sction 111 1983 Edition through the Summer 1984 Addend-a Reactor Vessel Closure Head (Units I ASME Code, Section 111, Class 1 2001 Edition th rough the and 2 replaGemw4) 2002 and 2003 Addenda Control Rod Drive Mechanisms 2001 Edition through the Pressure Housings (Units 1 and 2- ASME Code, Section Il, Class 1 2002 and 2003 Addenda repla~ernen )

Core Exit Thermocouple Nozzle 1989 Edition (no Assemblies (Units l and 2- ASME Code,Section III, Class 1 Addenda)(a)

FepaGeRmen4 Thermocouple Nozzle (Units 1 and 2- ASME Code, Section Il, Class 1 2001 Edition through the r-plae )en 2002 and 2003 Addenda Thermocouple Columns (Units 1 and ASME Code, Section 111 1983 Edition through the

2) Summer 1984 Addenda (a) Reconciled with the 2001 Edition through the 2002 and 2003 Addenda.

Section 4 PG&E Letter DCL-1 0-158 TIME-LIMITED AGING ANALYSES Page 43 of 73 4.7 PLANT-SPECIFIC TIME-LIMITED AGING ANALYSES 4.7.1 Crane Load Cycle Limits Summary Description Design guidance for cranes used to handle heavy loads over structures, systems, and components important to safety is provided in NUREG-0612, Control of Heavy Loads at NuclearPower Plants. Guideline 7, Article 5.1.1 of NUREG-0612 recommends compliance with Chapter 2 of ANSI B30.2-1976, Overhead and Gantry Cranes and Crane Manufacturers Association of America Specification Number 70 (CMAA-70), Specifications for Electric Overhead Traveling Cranesfor crane design.

The design criteria of CMAA-70 are based on the estimated number of load cycles (crane lifts) over the service life of the component and design to these criteria is therefore a TLAA in accordance with 10 CFR 54.3.

The DCPP cranes were designed to other industrial standards, before publication of these documents, as discussed in DCPP FSAR 5ection 9.1.4.2.1 and Design Criteria Memoranda (DCMs). In the response to NUREG-0612, DCPP compared these designs to the NUREG-0612 guidelines to demonstrate that the intent of Chapter 2-1 of ANSI B30.2-1976 and CMAA-70 was met. The NRC concurrence is documented in Appendix A to Supplement 27 to the DCPP Safety Evaluation Report.

DCPP cranes within the scope of NUREG-0612 carry heavy loads, i.e. loads over 1,972 Ib, over components required for plant shutdown or decay heat removal, or over irradiated fuel in the reactor vessel or spent fuel pool, and are controlled by the Heavy Loads Program described in FSAR Section 9.1.4.3.5. These are designated as Category 1 cranes. The DCPP Category 1 cranes that meet NUREG-0612 requirements and are within the scope of license renewal with a TLAA associated with their design are:

E Containment Polar Crane (one for each unit)

--*issfile Shield Hoist (one for each unit)

" Fuel Handling Area Crane

" Turbine Building Crane (one for each unit)

E Intake Structure Crane Section 4 PG&E Letter DCL-1 0-158 TIME-LIMITED AGING ANALYSES Page 44 of 73 Additional cranes used at DCPP are described in FSAR Section 9.1.4.2.1. These cranes are outside the scope of NUREG-0612 because their loads are less than the defined threshold for heavy loads of 1,972 lb. These additional cranes are:

" Reactor Cavity Manipulator Crane (one for each unit)

" Spent Fuel Pool Bridge Crane (one for each unit)

" Containment Dome Service Crane (one for each unit)

Table 4.7-1 displays DCPP crane design requirements.

Analysis The Category 1, Service Class F cranes built in accordance with AISE Standard No. 6 (Containment Polar, Fuel Handling Area, Turbine Building, and Intake Structure Cranes) were designed for more than 2,000,000 load cycles. This far exceeds the number of lifts that any of'the DCPP cranes would make over the extended life of the plant. Based on industry experience, the Spent Fuel Pool Bridge Crane 1 is the most used crane of those within the scope of license renewal.

Assuming full core offloads and subsequent reloading of the core every refueling outage, as well as loading of fuel into casks for dry cask storage, would conservatively result in approximately 53,000 lifts over a 60-year period. Applying a conservative safety factor of 1.25 would bring the estimate to 66,000 lifts, only about 3.3 percent of the 2,000,000 design cycles.

The ,..missile shield hOit cranes aRd containment dome service cranes were designed to CMAA-70, Service Class A requirements. The c.ntainment dome-ser.4ice cranes are designed to SeP~ice Class A and theimissile shield hoist cranes arc designed to an unspecified ser~ice class, so Serice Class A is assumed.

Service Class A cranes are designed for 20,000 to 100,000 maximum rated lifts (load cycles). The total number of load cycles for 60 years are well below even the lower edge of the range of 20,000 lifts. Assuming 120 refueling outages for an operating period of 60 years, it would require 166 lifts each refueling outage to reach 20,000 lifts. The containment dome service cranes typically perform less than 10 lifts per outage. The U nit 2 missile shield hoist crane was removed from containment as part of the Unit 2 replacement reactor vessel closure head (RRVCH) poet during the 15~refueling outage beginning in Oc)tober: 2009. The IUnit mins~sile shield hoist crane was Fremoved from containment as padt of the Uit RRVGH project during the 1-6" refueling outage beginning in October: 2010.

Therefore, their design WAill not be applicable during the period of extende epe~aia=on 1The Spent Fuel Pool Bridge Crane is not designed to AISE Standard No. 6. Since it is the most-limiting crane in this evaluation, its cycles are projected for 60 years only to demonstrate that the AISE Standard No. 6 cranes will not exceed the design criterion of 2,000,000 load cycles.

Section 4 PG&E Letter DCL-1 0-158 TIME-LIMITED AGING ANALYSES Page 45 of 73 The Class C, Moderate Service, requirements of EOCI Design Specification #61 do not provide a limiting number of load cycles for the crane designed to it, i.e. the Reactor Cavity Manipulator Crane. Rather, the specification states that the calculated static stress in the material, based on rated load, shall not exceed 20 percent of the assumed average ultimate strength of the material. Since the design specification does not consider the effects of aging and is not dependent upon 40 years of operation, the design of the Reactor Cavity Manipulator Crane is not a TLAA under 10 CFR 54.3(a) Criteria 2 and 3.

The Westinghouse design specifications for the Spent Fuel Pool Bridge Crane do not provide a limiting number of load cycles. The specifications state that the design load plus structural weight shall be 1/5 (20 percent) of the ultimate strength of the material. Since the design specification does not consider the effects of aging and is not dependent upon 40 years of operation, the design of the Spent Fuel Pool Bridge Crane is not a TLAA under 10 CFR 54.3(a) Criteria 2 and 3.

Disposition: Validation, 10 CFR 54.21 (c)(1)(i)

All of the DCPP cranes within the scope of license renewal either have no limiting number of loading cycles, i.e. the Reactor Cavity Manipulator and Spent Fuel Pool Bridge Cranes, in which case no TLAA exists, or are designed for more load cycles than the maximum number expected for a 60-year period of operation. The crane designs are valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

Section 4 PG&E Letter DCL-1 0-158 TIME-LIMITED AGING ANALYSES Page 46 of 73 Table 4.7-1 Crane Specifications FSAR Service Allowable Validity of the Allowable Component Name Section Design Specification Class Load Cycles Lifts for 60 Years N!A The Unit 2 crane Misswle Shield Heist (one .. 4.5702, was removed in 2009.

feF-eaeh-u if. The Unit 1 crane will be removed in 2010.

umiel hoidt rane is designcd o an unspecified seP'ice Glass level, thus the mninimum sedice Glass level, assurned 7

Section 4 PG&E Letter DCL-10-158 TIME-LIMITED AGING ANALYSES Page 47 of 73 4.7.2 TLAAs Supporting Repair of Alloy 600 Materials Summary Description Both Alloy 600 base material and Alloy 82/182 weld material have exhibited susceptibility to primary water stress corrosion cracking (PWSCC). Evaluations of these effects, or analyses in support of repairs to affected locations, can be TLAAs.

Westinghouse performed an assessment of PWSCC susceptibility for Alloy 600 components and Alloy 82/182 welds in DCPP Units 1 and 2. This assessment provided guidance to DCPP for inspection of these materials, but was not time-dependent and is therefore not a TLAA. Weld overlay repairs have only been implemented on the Unit 2 pressurizer nozzles.

Pressurizer The Unit 1 pressurizer and its nozzles and safe ends contain no Alloy 600 or Alloy 82/182 weld material.

The Unit 2 pressurizer contains Alloy 600 material only as Alloy 82/182 welds attaching the surge, spray, and relief valve nozzles to the safe ends, and the safe ends to the connecting piping. Complete Alloy 690 structural weld overlays were completed on all of these locations during Unit 2 Refueling Outage 14 (2R14, Spring 2008) to mitigate effects of primary water stress corrosion cracking (PWSCC) in the original Alloy 82/182 welds. The results of the inspection and repairs were reported to the NRC in letter DCL-08-039. The overlays were supported by fatigue crack growth analyses. These fatigue crack growth analyses were projected to the end of the period of extended operation, and are therefore valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

No base-metal corrosion analyses exist for the pressurizers, since no half-nozzle or similar repairs have exposed the base metal to reactor coolant.

Reactor Vessel There have been no mechanical stress improvement process (MSIP), mechanical nozzle seal assembly (MNSA), half-nozzle, or weld overlay repairs to reactor vessel Alloy 600 nozzle locations. Since there have been no MSIP, MNSA, half-nozzle, or weld overlay repairs to reactor vessel Alloy 600 nozzle locations, no TLAA exists supporting their installation.

Alloy 600 components previously existed in the reactor vessel heads. However, the reactor vessel head replacement was performed during Unit 2 Refueling Outage 15 (2R15, October 2009) and during is scheduled for Unit 1 Refueling Outage 16 (1R16, October 2010). All components penetrating the new reactor vessel closure heads and

Enclosure 2 Section 4 PG&E Letter DCL-10-158 TIME-LIMITED AGING ANALYSES Page 48 of 73 I welded to the inner surfaces of the reactor vessel closure heads will-behave been replaced with Alloy 690.

See Section 4.3.2.2.

Steam Generators Alloy 600 components previously existed in the steam generators, but the Unit 1 steam generators were replaced during Unit 1 Refueling Outage 15 (1 R1 5, Spring 2009) and the Unit 2 steam generators were replaced during Unit 2 Refueling Outage 14 (2R14, Spring 2008). Replacement steam generators contain no Alloy 600 or Alloy 82/182 welds.

See Section 4.3.2.5.

Alloy 600 Programand Other Locations DCPP procedural guidance provides a comprehensive Alloy 600 control program for materials in the RCS. Any repairs made to Alloy 600 locations, including mechanical stress -improvement process, mechanical nozzle seal assembly, half-nozzle, or weld overlay repairs, will be implemented in accordance with this guidance. However, other than the Unit 2 pressurizer, as discussed above, none of the locations have yet been subject to repairs. In the absence of analyses, no TLAAs exist.

The Plant Specific Nickel-Alloy Aging Management Program is discussed in Section B2.1.37.

Appendix A PG&E Letter DCL-10-158 Final Safety Analysis Report Supplement Page 49 of 73 A1.5 NICKEL-ALLOY PENETRATION NOZZLES WELDED TO THE UPPER REACTOR VESSEL CLOSURE HEADS OF PRESSURIZED WATER REACTORS The Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors program manages cracking due to primary water stress corrosion cracking and loss of material due to boric acid wastage in nickel-alloy vessel head penetration nozzles and includes the reactor vessel closure head, upper vessel head penetration nozzles and associated welds. Detection of cracking is accomplished through implementation of a combination of bare metal visual examination (external surface of head) and surface and volumetric examination (underside of head) techniques. This program was developed in response to NRC Order EA-03-009. ASME Code-Case N-729-1, subject to the conditions specified in 10 CFR 50.55a(g)(6)(ii)(D)(2) through(6), has superseded the requirements of NRC Order EA-03-009.

The original Unit 1 reactor pressure vessel (RPV) head ,,-planned to bewas replaced during the 1 6 th refueling outage e."that began in October 2010 and the Unit 2 RPV head was replaced during the 15 refueling outage that began beginning-in October 2009. RPV head replacement, i/nitial and subsequent examinations will

-,,fte, be performed in accordance with ASME Code Case N-729-1, subject to the conditions specified in 10 CFR 50.55a(g)(6)(ii)(D)(2) through(6).

Appendix A PG&E Letter DCL-10-158 Final Safety Analysis Report Supplement Page 50 of 73 A3.2.1.2 Reactor Vessel Closure Heads and Associated Components The reactor pressure boundary components associated with the reactor vessel closure head are the control rod drive mechanisms (CRDM) pressure housings, core exit thermocouple nozzle assemblies (CETNAs), thermocouple nozzles, and thermocouple columns. The Units 1 and 2 CRDMs pressure housings, the CETNAs, and the thermocouple nozzles will-behave been replaced with the replacement reactor vessel closure heads (RRVCHs). The RRVCHs, CRDM pressure housings, CETNA, and thermocouple nozzles will beare designed to ASME Code,Section III. The Unit 1 and 2 RRVCHs, CRDMs, CETNAs, and thermocouple nozzles will-behave been analyzed for a 50-year design life, and therefore will remain valid for the period of extended operation. in accordance with 10 CFR 54.21(c)(1)(i).

The only reactor pressure boundary components associated with the RRVCHs Fea.Gt9 vessel closure head that willwere not be-replaced are the thermocouple columns.

These components were designed to the ASME Code, Section II1. The current fatigue analyses of the thermocouple column demonstrate a large margin to the code acceptance. criterion of 1.0. The analyses of these components are therefore valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii).

V Appendix A Final Safety Analysis Report Supplement PG&E Letter DCL-10-158 Page 51 of 73 Table A4-1 License Renewal Commitments Item # Commitment LRA Implementation Section Schedule 18 Enhance the Transmission Conductor, Connections, Insulators and Switchyard Bus and B2.1.38 Prior to the period of Connections program procedures to: extended operation

" Identify components required to support station blackout recovery which are in the scope of license renewal aging management. In the 230 kV switchyard, these are the components between the startup transformers and disconnects 217 and 219. In the 500 kV switchyard these are the components between the main transformers and switchyard breakers 532/632 in Unit 1 and 6431641542/642 in Unit 2, and

" Include gathering and reviewing completed maintenance and inspection results, by the plant staff, to identify adverse trends, and

• Identify that an engineering evaluation will be conducted when a degraded condition is detected that considers the extent of the condition, reportability of the event, potential root causes, probably of recurrence, and the corrective actions required.

26 The missile shield hoist crane will be removed from containment during the replacement 4P-7-_ Prior to the period of reactorF vessel closure head (RRVCH) project. The Unit 2 RRVCH project was completed extended operation during the fifteenth refueling outage beginning October 2009 and Unit 1 RRVCH project isCompleted

__....planned during the sixteenth refueling outage beginninqg Gtober 2010n.- Completed 28 The Unit 1 reactorF pressure vessel (RPV) head is planned to be replaced during the-16e- 132. 1.5 Pro otepriod of refueling outa e beginning October 2010 and the Unit 2 RPV head was replaced during the 12.1 extended operation

_l. refueling outage in October 2000. All components penetrating the new reactor vessel 4.7.-2 Completed closre hadsand welded to the inner surfaces of the reactor vessel closure heads including the head vent piping and elbows will be replaced with All'y 690. Completed 29 DCPP Unit 1 and 2 CRDM pressure housings, the core exit thermocouple nozzle assemblies 4.3.2m2 Prortot prid E of (CETNAs), and the thermocouple nozzles will be replaced with the replacement reactor vessel extended operation closu~re heads (RRVCHs). The U-1nit 2 RPV head was replaced during the fifteenth refueling Completed outage beginning October 2009 and, Unit 1 RPV head is lne ob replaced during the sixteenth refueling outage beginning Otctber 2010. .The replacement co)mponents will be qualified through the peried of extended operation.Completed 37 Commitment deleted in PG&E Letter DCL-10-151.

PriorF to the period Calculation No. 2305G will be revised by November 1, 2010 to be consistent with the latest of-etended 40 revision of Prccedure NDE \V 3C ! .Completed B2.1.28 Completed Appendix A PG&E Letter DCL-10-158 Final Safety Analysis Report Supplement Page 52 of 73 Table A4-1 License Renewal Commitments Item # Commitment LRA Implementation Section Schedule CaGlculation No. 2305G acceptance criteria will be consistent with the latest revision of- Prior to the pcriod B212 f extended-41 PrOccdure NDE VT 3C 1. Any long term planning and decisions on potential repair will be 41 made On a case by case basis and based on review of trends in the inspection findings and 848 operation will be implemented via DCPP corrective action program. Completed Completed Procedure NDE VT 3C-1 and Calculation No. 2305C acceptance criteria will be revised to be Prior to the period 42 consistent with ACI 349.3R Chapter 5 detailed quantitative acceptance criteria. B2.1.28 of extended operation A one-time video inspection of the Unit 2 leak chase will be performed during the period of P-rier-tDuringthe 45 extended operation B2.1.32 period of extended operation he Fperod Aluminum tape currently in stalled on the seems of the Unit 1 RMIVlinsulation panels of tthe 47 pFessurizer lop seals

. currently scheduled to be is.reoved during the Unit 1 sixteenth .1..2..1..

refueling outage (I 2R1 6) outage, October 2010. Completed Cpeted Completed During the 10 years 48 DCPP will perform 100 percent eddy current testing of one nonregenerative heat exchanger as part B2.1.16 Prior to the period of the One-Time Inspection Program within ten years prior to the period of extended operation. . of extended operation.

DCPP will update the PM basis documents for strainers and screens inthe makeup water Prior to the period 49 system that support long term cooling and firewaterinventory to require that they are cleaned B2.1.13 of extended and inspected on a 24 month frequency during the period of extended operation. operation During the 10 years PG&E will install cathodic protection for the ASW discharge piping in contact with soil during the P-prior to the period 53 first 10 year interval period excavation and inspection prior to the period of extended operation. B2.1.18 of extended operation Appendix B PG&E Letter DCL-1 0-158 AGING MANAGEMENT, PROGRAMS Page 53 of 73 B2.1.5Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program Description The Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors program manages cracking due to Primary Water Stress Corrosion Cracking (PWSCC) and loss of material due to boric acid wastage in nickel-alloy vessel head penetration nozzles and includes the reactor vessel closure head, upper vessel head penetration nozzles and associated welds. This program was developed in response to NRC Order EA-03-009. ASME Code Case N-729-1, subject to the conditions specified in 10 CFR 50.55 a(g)(6)(ii)(D)(2) through(6),

has superseded the requirements of NRC Order EA-03-009.

Detection of cracking is accomplished through implementation of a combination of bare metal visual examination (external surface of head) and surface and volumetric.

examination (underside of head) techniques. Evidence of reactor coolant leakage may manifest itself in the form of boric acid residues on the upper head or adjacent components or in the form of corrosion products that result from rusting of the low-alloy steel materials used to fabricate the vessel. The program conducts bare metal inspections to detect leakage from PWSCC and other sources by looking for deposition of boric acid on the external surface of the reactor vessel head. These deposits can be used to help detect and identify the origin of leaks. This examination also serves to detect, leakage from other causes and sources in proximity to the top heads that may allow boric acid deposition on and subsequent corrosion of carbon steel components.

The Inservice Inspection (ISI) Program incorporates the governing inspections required by ASME Code Case N-729-1. A plant procedure conducts reactor vessel head bare metal visual inspections consistent with ASME Code Case N-729-1. Visual examiners shall be certified to at least Level II, VT-2; personnel performing the final evaluation of bare metal head examination data shall be Level Ill, VT-2.

The Nickel Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors program is a monitoring program that provides measures for detecting the aging effects prior to loss of intended function, but does not prevent degradation due to aging effects. Preventive measures for monitoring and maintaining reactor coolant water chemistry to mitigate PWSCC are consistent with the EPRI PWR Primary Water Chemistry Guidelines. The Primary Water Chemistry Program is described separately in the Water Chemistry program (B2.11.2).

The Unit 1 reactor pressure vessel (RPV) head was is planned to be replaced during the 16th refueling outage beginning in October 2010 and the Unit 2 RPV head was replaced during the 15th refueling outage beginning in October 2009. All components penetrating the new reactor vessel closure heads and welded to the inner surfaces of the reactor vessel closure heads will-beare PWSCC-resistant'material (Alloy 690). NDE Appendix B PG&E Letter DCL-10-158 AGING MANAGEMENT PROGRAMS Page 54 of 73 examinations listed in Table 1, Item Numbers B4.30 and B4.40, of Code Case N-729-1, subject to the conditions specified in 10 CFR 50.55a(g)(6)(ii)(D)(2) through(6), will initially be performed for the new Alloy 690 nozzles for the baseline and subsequent examinations.

DCPP is commfittfing to replace the reactor pressure vessel head on Unit 1 prior to the pe*ri*d of extended operatieR.

NUREG-1801 Consistency The Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors program is an existing program that is consistent with NUREG-1 801,Section XI.M11A, Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors.

Exceptions to NUREG-1801 None Enhancements

-None Operating Experience Based on a review of DCPP operating experience, the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors program has effectively managed potential degradation. In response to NRC generic correspondence, several inspections were performed and no evidence of degradation was found. A summary of inspections from the thirteenth and fourteenth refueling outages of both units are listed below.

DCPP completed Unit 1 refueling outage 1R13 in December 2005 and 1R14 in May 2007; DCPP completed Unit 2 refueling outage 2R13 in May 2006 and 2R14 in March 2008. During these refueling outages, DCPP performed bare metal visual inspections of the RPV head penetrations and visual inspection of the RPV head surface. No evidence of reactor vessel head penetration nozzle leakage or cracking, or degradation of the RPV head was identified. DCPP also performed nonvisual nondestructive volumetric examination on all 79 reactor vessel head penetration tubes. The examination detected no discontinuities or indications of boric acid leak paths, and no flaws needing disposition or corrective action were identified. DCPP also performed a visual inspection to identify potential boric acid leaks from the pressure-retaining components above the RPV head. Minor localized dry boric acid deposits on small valve packing glands were identified during refueling outages 2R13 and 2R14 and corrected. No evidence of leakage was identified from the pressure-retaining components above the RPV head during refueling outages 1R13 and 1R14.

Appendix B PG&E Letter DCL-1 0-158 AGING MANAGEMENT PROGRAMS Page 55 of 73 The Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors program, operating experience information provides objective evidence to support the conclusion that the effects of aging will be adequately managed so that the RPV head intended function will be maintained during the period of extended operation.

The DCPP operating experience findings for this program identified no uhique plant specific operating experience; therefore DCPP operating experience is consistent with NUREG-1801.

Conclusion The continued implementation of the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors program provides reasonable assurance that aging effects will be managed such that the systems and components within the scope of this program will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.

Enclosure 2 Appendix B PG&E Letter DCL-10-158 AGING MANAGEMENT PROGRAMS Page 56 of 73 B2.1.13 Fire Water System Program Description The Fire Water System program manages loss of material due to corrosion, MIC, or biofouling for water-based fire protection systems. Internal and external inspections and tests of fire protection equipment are performed in accordance with applicable National Fire Protection Association (NFPA) codes and standards. The fire water system is managed by performing routine preventive maintenance, inspections, and testing; operator rounds, performance monitoring, and reliance on the corrective action program; and system improvements to address aging and obsolescence issues.

The following are activities performed by the Fire Water System program:

Testing:

A fire water system flow test is performed at least every three years in accordance with plant procedures meeting requirements of NFPA 25. Hydraulic pump curves are obtained and compared with baseline curves to determine operability. During the Fire Water System flow test, parameters directly monitored are static pressure and velocity head.

The Fire Water System program conducts a water flow test through each open spray nozzle to verify that deluge systems provide full coverage of the equipment it protects.

The Fire Water System program will be enhanced so sprinkler heads in service for 50 years will be replaced or representative samples from one or more sample areas will be tested in accordance with NFPA 25. Test procedures will be repeated at 10-year intervals during the period of extended operation, for sprinklers that were not replaced prior to being in service for 50 years to ensure that signs of degradation, such as corrosion, are detected prior to the loss of intended function.

The Fire Water System program conducts a water flow test through each open spray nozzle of the transformer deluge system periodically to verify that each nozzle is unobstructed. Water is flowed through the test valves of the deluge system periodically to ensure freedom from blockage.

Fire water is flowed from the Raw Water Storage Reservoir periodically to verify the

.system piping is capable of delivering the design flow rate.

The portable diesel driven fire pumps are tested periodically under full load/full flow conditions.

DCPP performs a hydrostatic test of its indoor fire hoses at least every three years, while outdoor fire hoses are tested at least annually. Fire hoses that are inaccessible during normal plant operations are tested every refueling outage.

Appendix B PG&E Letter DCL-10-158 AGING MANAGEMENT PROGRAMS Page 57 of 73 Inspections:

Either periodic non-intrusive volumetric examinations or visual inspections will be performed on firewater piping. Non-intrusive volumetric examinations would detect loss of material due to corrosion, and would confirm wall thickness is within acceptable limits so that aging will be detected before the loss of intended function. Visual inspections would evaluate (1) wall thickness as it applies to avoidance of catastrophic failure, and (2) the inner diameter of the piping as it applies to the design flow of the fire protection system. The volumetric examination technique employed will be one that is generally accepted in the industry, such as ultrasonic or eddy current.

The Fire Water System program performs periodic visual inspections of main fire system piping, yard loop fire hydrants, hose reel headers, hose-stations, portable diesel driven fire pump hoses, fire hoses, gaskets, water spray headers, sprinkler system headers, water spray nozzles, and sprinkler heads to verify they are free of significant corrosion, foreign materials, biofouling, and physical damage.

DCPP performs a visual inspection of its indoor hose station gaskets once every 18 months, except hose stations in high radiation areas and the containment buildings which are tested during refueling outages. This inspection ensures that the gaskets have a satisfactory fit with no defects.

DCPPperforms a visual inspection and cleaning of strainersand screens in the make-up water system that support long term cooling and firewaterinventory once every 24 months during the period of extended operation.

Fire detection instruments located in safety related power block structures, which are accessible during plant operation, are demonstrated to be operable at least once per six months by testing and surveillance activities. For fire detection instruments located in safety related power block structures which are not accessible during plant operation, operability is demonstrated during each cold shutdown exceeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, unless performed in the last six months.

Flushes:

The Fire'Water System program performs a flush semi-annually for the yard loop and underground feeds and annually for fire hydrants. Flowing water will remove accumulated debris and sediment which may impair proper valve functioning.

The Fire Water System program acceptance criteria are 1) the ability of the fire protection system to maintain required pressure, 2) no unacceptable signs of degradation, such as loss of material due to corrosion, are observed during visual assessment of internal system conditions, and 3) no biofouling exists in the sprinkler system that could cause blockage in the sprinkler heads.

Appendix B PG&E Letter DCL-1 0-158 AGING MANAGEMENT PROGRAMS Page 58 of 73 DCPP does not have permanently installed diesel driven fire pumps. DCPP has three portable diesel driven fire pumps that may be used for fire protection. The portable diesel driven fire pumps are tested quarterly to demonstrate pump operability and annually under full load/ full flow conditions. Observation of the pump during testing demonstrates the fuel supply line is clear and not degraded. During the annual test, pressure is recorded and flow is calculated to ensure adverse performance trends are detected.

NUREG-1801 Consistency The Fire Water System program is an existing program that, following enhancement, will be consistent with exception to NUREG-1801,Section XI.M27, Fire Water System.

Exceptions to NUREG-1801 Program Elements Affected Scope of Program- Element I NUREG-1801 provides a program for managing carbon steel and cast iron components in fire water systems. The Fire Water System program also manages components, made from copper alloy and stainless steel exposed to water in the fire water system.

The fire water system includes these materials. Visual inspections, volumetric examinations, flushes and flow tests are appropriate methods for managing the aging effects for these materials and ensure the continuity of intended function.

Detection of Aging Effects - Element 4 NUREG-1801 specifies annual hydrant hose hydrostatic tests. DCPP performs a hydrostatic test of its power block fire hoses every three years. DCPP has been performing hydrostatic testing of fire hoses on a 3-year frequency for over 10 years and no degradation leading to a loss of function has occurred.

NUREG-1801 specifies annual gasket inspections. DCPP performs gasket inspections at least once every 18 months (24 months in high radiation areas). Since aging effects are typically manifested over several years, differences in inspection and testing frequencies are insignificant. DCPP has been inspecting at an 18-month frequency for over 10 years and no degradation leading to a loss of function has occurred.

Enhancements Prior to the period of extended operation, the following enhancements will be implemented in the following program elements:

Detection of Aging Effects - Element 4 The Fire Protection program will be enhanced so sprinkler heads in service for 50 years will be replaced or representative samples from one or more sample areas will be Appendix B PG&E Letter DCL-10-158 AGING MANAGEMENT PROGRAMS Page 59 of 73 tested consistent with NFPA 25, Inspection, Testing and Maintenance of Water-Based Fire Protection Systems guidance. Test procedures will be repeated at 10-year intervals during the period of extended operation, for sprinkler heads that were not replaced prior to being in service for 50 years, to ensure that signs of degradation, such as corrosion, are detected prior to the loss of intended function.

Procedures will be enhanced for either periodic, non-intrusive volumetric examinations, or visual inspections on firewater piping. Non-intrusive volumetric examinations would detect any loss of material due to corrosion to ensure that aging effects are managed, wall thickness is within acceptable limits and degradation would be detected before the loss of intended function. Visual inspections would evaluate (1) wall thickness as it applies to avoidance of catastrophic failure, and (2) the inner diameter of the piping as it applies to the design flow of the fire protection system. The volumetric examination technique employed will be one that is generally accepted in the industry, such as ultrasonic or eddy current.

Monitoring and Trending - Element 5 The Fire Protection procedures will be enhanced to state trending requirements.

Operating Experience, Operating experience at DCPP is evaluated and implemented to effectively maintain the fire protection system. This is accomplished by promptly identifying and documenting (using the Corrective Action Program) any conditions or events that could compromise operability of fire protection components and/or structures. In addition, industry operating experience, self assessments, and independent audits provide additional input to ensure that system operability is effectively maintained.

The current system health report shows corrective actions are being completed in a timely manner, with favorable performance trending. Issues which have been identified and corrected include fire hydrant and piping corrosion and leakage.

Based on a review of DCPP operation experience, several examples of degradation or corrosion of the Fire Water System have been identified. Examples include: (1) while performing a'surveillance test procedure in 2001, a fire protection valve was found frozen in the open position. The valve provides for maintenance isolation; therefore, with the valve frozen open, the system is still operable and able to perform its design function. It was determined that the position and housing indicators had corrosion and cracking and were therefore replaced. (2) During replacement of a valve on October 7, 2005, the piping between firewater storage tank 0-2 and the pump house was found to be corroded to the point of requiring repair or replacement. It was subsequently decided to replace the pipe, which was completed on October 19, 2005. (3) DCPP has replaced the main fire pumps, redesigned the transformer deluge pipe, replaced transformer deluge valve assemblies, replaced several yard loop risers, fire hydrants, flow switches, and has replaced many system valves as a result of internal inspections

Enclosure 2 Appendix B PG&E Letter DCL-10-158 AGING MANAGEMENT PROGRAMS Page 60 of 73 and valve leak problems identified during routine plant walkdowns and surveillances.

The DCPP operating experience findings for this program identified no unique plant

.specific operating experience;, therefore DCPP operating experience is consistent with NUREG-1801.

An assessment of the DCPP Fire Protection Program was performed by DCPP Quality Verification in 2000. The purpose of the assessment was to review the program against the commitments of the Operating License Conditions for both Units 1 and 2.

Overall, the assessment team found good implementation of the fire protection defense-in-depth elements, as well as compliance with 10 CFR 50, Appendix R requirements and the approved exemptions. Both the administrative and configuration control processes developed to control the program were thorough, and, in general, have been successfully implemented. The automatic sprinkler and deluge systems at DCPP were in good overall condition. Some minor variances from NFPA 13 were noted during a walkdown of the turbine building sprinkler system. However, these items were not significant and would not have affected the ability of the sprinkler systems to perform as designed.

DCPP Quality Verification also performs an assessment of maintenance activities for each refueling outage. The purpose of this assessment is to verify all outage work, including fire protection, is planned, prepared, executed, and completed in accordance with established requirements. All of the results are documented in Maintenance Activities Assessment Reports.

In accordance with NRC Generic Letter 82-21, Technical Specifications for Fire ProtectionAudits, DCPP Quality Verification performs annual, biennial, and triennial fire protection audits. The purpose of these audits is to determine if the fire protection program is satisfactorily implemented. All of the results are documented in Fire Protection Program Audit Reports.

In 2003, 2006, and 2009, NRC triennial fire protection team inspections were performed to assess the DCPP Fire Protection program for selected risk-significant fire areas. No findings of significance were identified.

The fire water system operating experience information provides objective evidence to support the conclusion that the effects of aging will be adequately managed so that the component intended functions will be maintained during the period of extended operation.

Conclusion The continued implementation of the existing Fire Water System program provides reasonable assurance that aging effects will be managed such that the systems and components within the scope of this program will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.

Appendix B PG&E Letter DCL-10-158 AGING MANAGEMENT PROGRAMS Page 61 of 73 B2.1.37 Nickel-Alloy Aging Management Program Program Description The Nickel-Alloy Aging Management program manages cracking due to primary water stress corrosion cracking (PWSCC) in reactor coolant system (RCS) locations that contain Alloy 600. Aging management requirements for nickel-alloy penetration nozzles welded to the upper reactor vessel closure head noted in the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors program (B2.1.5) are included in the DCPP Nickel-Alloy Aging Management Program and are repeated here for review convenience. The scope of the DCPP Nickel Alloy Aging Management Program consists of the following reactor coolant pressure boundary (RCPB) locations fabricated with Alloy 600: control rod drive mechaiosm (CRDM) nozzles, head ven.,inst.ument perts/spare reacGto vessel head nozzles,- bottom mounted instrumentation (BMI) penetrations, reactor vessel inlet nozzle, reactor vessel outlet nozzle, and core support lug. The term Alloy 600 is used throughout this aging management program to represent Nickel-Alloy 600 material and Nickel-Alloy 82/182 weld metal. Non-Alloy 600 nickel components (e.g. Alloy 690 or welds made of Alloy 52/152) are not included in this program but are subject to the ASME Section Xl Inservice Inspection (B2.1.1) requirements.

The Nickel-Alloy Aging Management Program, uses inspections, mitigation techniques, repair/replace activities and monitoring of operating experience to manage the aging of Alloy 600 at DCPP. Detection of indications is accomplished through a variety of examinations consistent with ASME Section Xl Subsections IWB, ASME Code Case N-729-1, ASME Code Case N-722, and EPRI Report 1010087 (MRP-139) issued under NEI 03-08 protocols. Mitigation techniques are implemented when appropriate to preemptively remove conditions that contribute to PWSCC. Repair/replacement activities are performed to proactively remove or overlay Alloy 600 material, or as a corrective measure in response to an unacceptable flaw in the material. Mitigation and repair/replace activities are consistent with those detailed in MRP-139. Operating experience was. reviewed and is continually monitored to provide improvements and modifications to the DCPP Nickel-Alloy Aging Management Program as needed.

Aging Management Program Elements The results of an evaluation of each element against the 10 elements described in Appendix A of NUREG-1800, StandardReview Plan for Review of License Renewal Applications for Nuclear Power Plants are provided below.

Scope of Program- Element 1 All Alloy 600 locations within the reactor coolant system pressure boundary (RCPB) are included within the scope of this program. Aging management requirements for nickel-alloy penetration nozzles welded to the upper reactor vessel closure head noted in the

Enclosure 2 Appendix B PG&E Letter DCL-10-158 AGING MANAGEMENT PROGRAMS Page 62 of 73 Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors program (B2.1.5) are included in the Nickel Alloy Aging Management Program and are repeated here for review convenience. The term Alloy 600 will be used throughout this program to represent nickel-alloy 600 material and nickel-alloy 82/182 weld metal.

The Nickel Alloy Aging Management Program identifies the following RCPB Alloy 600 locations:

9(CRDpM nozzles (61 CRDM nozzles including weld at nozzle t vesse o cladding l

weld. and nozzle to staoiness steel housing)

• head vent nozzle, elbow, and horizental pipe iloruding welds at nozzle to Yes cradding, nozzle to elbow, elbow to horizontal pipe, and horizgntal pipe toe staitlera steel safe endspiping Note: head vent nozzleoincludemnintrument porTsn anrd spare nozzlesy T reactor vessel inlet and outlet nozzle safe-end weld w BMI penetrations (58 BMI nozzles including welds at BMI nozzle to vessel cladding and BMI nozzle to stainless steel safe-end/piping) s core support lug including welds at core support lug attachment, core support lug inlay weld (Unit 1 only), and core support lug inlay tie-in weld (Unit 1 only)

DCPP steam generators have been replaced with steam generators fabricated with Alloy 690 material. Aging of steam generator tubes is managed by the Steam Generator Tubing Integrity program (3b2.1.8) and is not covered by this program.

The reactor vessel leakage monitoring tube isfabricated of Alloy 600 with Alloy 182 welds but is not within the RCS pressure boundary. Therefore it is not within the scope of this program.

The Unit 1 pressurizer locations are composed of stainless steel and thus not in the scope of this program. An Alloy 690 full structural overlay was performed for each Alloy 600 location of the Unit 2 pressurizer. Therefore the Alloy 600 welds are no longer credited as the pressure boundary.

The Unit 1 reactor pressure vessel (RPV) head

.planned tobews replaced during the 16th refueling outage beginning October 2010 and the Unit 2 RPV head was replaced during the 15th refueling outage in October 2009. All components penetrating the new reactor vessel closure heads and welded to the inner surfaces of the reactor vessel Iclosure heads including the head vent piping and elbows will-behave been replaced with Alloy 690.

Non-Alloy 600 nickel components (e.g. Alloy 690 or welds made of Alloy 52/152) are not included in this program but are subject to the ASME Section Xl Inservice Inspection (132. 1.1) requirements.

Appendix B PG&E Letter DCL-1 0-158 AGING MANAGEMENT PROGRAMS Page 63 of 73 Preventive Actions - Element 2 The Nickel-Alloy Aging Management Program has many potential mitigation strategies that remove one or more of the three conditions that control primary water stress corrosion cracking (susceptible material, tensile stress field, supporting environment).

Mitigation activities that have been successfully performed for at least one US PWR plant include weld overlays, replacement of Alloy 600 (as a pre-planned activity), and mechanical stress improvement process (MSIP). Full structural weld overlays may be used either as a mitigation strategy or as a repair method. This method provides structural reinforcement at the (potentially) flawed location, such that adequate load-carrying capability is provided by the overlay. Components that have full structural weld overlays comprised of Alloy 690 are considered to be Alloy 690 and no longer in the DCPP Nickel-Alloy Aging Management Program. MSIP is a mechanical process that places the component surface in contact with the primary water in a compressive state, thereby removing the tensile stresses needed for initiation of PWSCC.

Specific mitigation strategies will be determined by plant-specific and industry- operating experience. The Water Chemistry program (B2.1.2) provides preventive actions for monitoring and control of the supporting environment for PWSCC.

ParametersMonitored/Inspected- Element 3 The Nickel-Alloy Aging Management Program monitors for cracking due to PWSCC.

Loss of material due to boric acid wastage is also used as an indication of cracking due to PWSCC. PeT the .... v upper head examino tThe DCPP Nickel-Alloy Aging Management Program will utilize bare metal visual, surface, and volumetric examination techniques for early detection of PWSCC in Alloy 600 components. Visual exams are employed to detect evidence of leakage from pressure retaining components within the RCS due to cracking and/or discontinuities and imperfections on the surface of the component. Volumetric examination indicates the presence of cracking/discontinuities throughout the volume of material.

The DCPP Inservice Inspection (ISI) Program and Plan will provide visual, surface, and volumetric examinations to support the Nickel-Alloy Aging Management Program.

Detection of Aging Effects - Element 4 The Nickel-Alloy Aging Management Program utilizes various visual, surface, and volumetric examination techniques for early detection of PWSCC in Alloy 600 components:

1. VT-2 examinations, governed by ASME Section Xl, section IWA-5000, are conducted to detect evidence of leakage from pressure retaining components within the RCS.

2. Bare metal visual (BMV) examinations, similar to VT-2 examinations, are conducted to detect evidence of leakage from pressure retaining components Appendix B PG&E Letter DCL-10-158 AGING MANAGEMENT PROGRAMS Page 64 of 73 within the RCS. Unlike VT-2 examinations, removal of insulation is required for BMV examinations to allow direct access to the bare metal surface.

3. Surface and volumetric examinations indicate the presence of discontinuities throughout the volume of material. DCPP uses ultrasonic testing (UT) for volumetric examinations.

The ISI Program and Plan provides visual, surface, and volumetric examinations to support the Nickel-Alloy Aging Management Program for the components identified in Element 1.

Control Rod Drive Mechanism and Head Vents BMV, surface, and volumetric examinations are implemented consistent with the requirements of Table 1, items B4.30 and B4.40 B4.1-0-in ASME Code Case N-729-1, subject to the conditions specified in 10 CFR 50.55a(g)(6)(ii)(D)(2) through (6).

Bottom Mounted Instrument Penetrations, Reactor Vessel Inlet & Reactor Vessel Outlet Nozzle BMV examinations are implemented consistent with appropriate requirements of Table 1, item B15.80 in ASME Code Case N-722 subject to the conditions listed in 10 CFR 50.55a(g)(6)(ii)(E)(2) through (4).

Core Support Lugs VT-2 visual examinations are conducted in accordance with the Inservice Inspection (ISI) Program Plan.

Monitoring and Trending - Element 5 Control Rod Drive Mechanism and Head Vents BMV examination frequencies for ReaGt*r Vessel Upper Head inSPections are identified by the Nickel Alloy Aging Management P-ro-gam for Alloy 600Iocations, and are consistent with the requirements of Table 1, Item B4.30 a*n4.4, in ASME Code Case N-729-1. Volumetric and Surface examinations wil ,be implemented i a ,*dane-frequencies are consistent with appropriate requirements of Table 1, item B4.2040 in ASME Code Case N-729-1, subject to the conditions specified in 10 CFR 50.55a(g)(6)(ii)(D)(2) through (6).

Bottom Mounted Instrument Penetrations, Reactor Vessel Inlet and Reactor Vessel Outlet Nozzle BMV examination frequencies for BMI penetrations are identified by the Nickel-Alloy Aging Management Program for Alloy 600 locations and are consistent with ASME Code Case N-722. Examinations will be implemented in accordance with appropriate requirements of Table 1 in ASME Code Case N-722 subject to the conditions listed in Appendix B PG&E Letter DCL-10-158 AGING MANAGEMENT PROGRAMS Page 65 of 73 10 CFR 50.55a(g)(6)(ii)(E)(2) through (4). Examination frequencies for reactor vessel inlet and outlet nozzles identified by the Nickel-Alloy Aging Management Program are consistent with ASME Code Case N-722, Table 1, item B1 5.90 (outlet nozzle) and item B15.95 (inlet nozzle).

Core Support Lug The core support lug VT-2 examination frequency is in accordance with the ISI Program Plan.

Due to the repair/replace strategy implemented for indications/cracking, trending is not performed in the Nickel-Alloy Aging Management Program.

Acceptance Criteria- Element 6 Evaluations and acceptance criteria are in accordance with industry standards (e.g.,

ASME Code) or meet-the acceptance of the NRC. For components included in EPRI 1010087 (MRP-139), as listed in the Nickel-Alloy Aging Management Program, it requires that all indications found during inspections must be evaluated per ASME Section Xl requirements.

Control Rod Drive Mechanism and Head Vents Relevant flaw indications detected as a result of bare metal visual examinations are evaluated in accordance with acceptable flaw evaluation criteria provided in ASME Code Case N-729-1, Section 3140.

Relevant flaw indications detected as a result of volumetric and surface examinations will be evaluated in accordance with acceptable flaw evaluation criteria provided in ASME Code Case N-729-1, Section 3130.

Bottom Mounted Instrument Penetrations, Reactor Vessel Inlet and Reactor Vessel Outlet Nozzle For BMI penetrations relevant flaw indications detected as a result of BMV examinations are evaluated in accordance with acceptable flaw evalu ation criteria (IWB-3522) provided in ASME Code CaseN-722, subject to the conditions listed in 10 CFR 50.55a(g)(6)(ii)(E)(2) through (4).

For reactor vessel inlet and outlet nozzles relevant flaw indications detected as a result of BMV examinations will be evaluated in accordance with acceptable flaw evaluation criteria (IWB-3522) provided in ASME Code Case N-722, subject to the conditions listed in 10 CFR 50.55a(g)(6)(ii)(E)(2) through (4).

Corrective Actions - Element 7 Relevant indications failing to meet applicable acceptance criteria are repaired or -

evaluated in accordance with plant procedures. Appropriate codes and standards are Appendix B PG&E Letter DCL-1 0-1.58 AGING MANAGEMENT PROGRAMS Page 66 of 73 specified in the plant ASME Section Xl Repair/Replacement Program and Implementation procedure and design drawings. Quality assurance requirements for repair and replacement activities are also included in plant procedures.

A self assessment of the Nickel-Alloy Aging Management Program is conducted following two outages on each unit (approximately every three years).

The self assessment includes a review of pertinent industry operating experience (inspection results and any leakage or cracking found in the industry), NDE technique and tooling improvements, development of new mitigation techniques, status of planned mitigation or replacement projects, lessons learned and regulatory changes.

DCPP QA procedures, review and approval processes, and administrative controls are implemented in accordance with the requirements of 10 CFR 50, Appendix B that are acceptable in addressing corrective actions. The QA program includes elements of corrective action, confirmation process and .administrative controls and is applicable to the safety-related and nonsafety-related systems, structures and components (SSCs) that are subject to aging management review.

Confirmation Process- Element 8 DCPP site QA procedures, review and approval processes are implemented in accordance with the requirements of 10 CFR 50, Appendix B and include confirmation processes as described in DCPP FSAR Section 17.2 and provisions that specify when follow-up actions are required to be taken to verify that corrective actions are effective and those implemented to address significant conditions adverse to quality, are effective in preventing recurrence of the condition.

Administrative Controls - Element 9 DCPP site QA procedures, review and approval processes are implemented in accordance with the requirements of 10 CFR 50, Appendix B and include administrative controls as described in DCPP FSAR Section 17.2 and provisions that specify when follow-up actions are required to be taken to verify that corrective actions are effective and those implemented to address significant conditions adverse to quality, are effective in preventing recurrence of the condition.

Operating Experience - Element 10 Operating experience at DCPP is evaluated and implemented to ensure that the Nickel-Alloy Aging Management Program maintains its primary goal of ensuring the integrity of the RCS pressure boundary. This is accomplished by promptly identifying and documenting (using the corrective action program) any conditions or events that suggest Alloy 600 degradation. In addition, industry operating experience, self assessments, and independent audits provide additional assurance that the program remains effective.

Appendix B PG&E Letter DCL-1 0-158 AGING MANAGEMENT PROGRAMS Page 67 of 73 PG&E has responded to the various NRC and industry publications on Nickel-Alloy aging issues, including NRC Generic Letter 97-01, NRC Information Notice 2000-17, NRC Information Notice 2001-05, NRC Bulletin 2001-01, NRC Bulletin 2002-01, NRC Bulletin 2002-02, NRC Bulletin 2003-2 and NRC Bulletin 2003-11.

DCPP has proactively replaced Alloy 600 material with PWSCC resistant Alloy 690 material. The Unit 1 steam generators containing Alloy 600 were replaced in 1R1 5 (February 2009) and the Unit 2 steam generators containing Alloy 600 were replaced in 2R14 (February 2008). The replacement steam generators were fabricated with Alloy 690 material. For the Unit 2 pressurizer, an Alloy 690 full structural weld overlay was performed for each Alloy 600 location during refueling outage 2R14 (February 2008).

The Unit 2 reactor vessel head was replaced during 2R1 5 (October 2009) and the Unit 1 reactor vessel head replacement was replaced during is scheduled for 1Ri6 (October 2010). All components penetrating the new reactor vessel closure heads and welded to the inner surfaces of the reactor vessel closure heads will-behave been replaced with Alloy 690.

Based on a review of DCPP operating experience, the Nickel-Alloy Aging Management Program has been effective in ensuring that the RCS will continue to operate within its licensing basis. The only leaks were four leaks on stainless steel CRDM canopy seal welds (two on each unit). These leaks were identified during reactor vessel top and bottom head inspections. The leaks were repaired. These findings, coupled with the aggressive Alloy 600 replacement with PWSCC resistant Alloy 690, provide reasonable assurance that the systems, structures and components containing Nickel-Alloy at DCPP will continue to perform their intended function during the period of extended operation.

Enhancements None Conclusion The continued implementation of the Nickel-Alloy Aging Management Program provides reasonable assurance that aging effects will be managed such that the systems, structures and components within the scope of this program will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.

Appendix B PG&E Letter DCL-1 0-158 AGING MANAGEMENT PROGRAMS Page 68 of 73 B2.1.38 Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections Program Description The scope of the Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections aging management program includes the 230 kV and 500 kV components required for station blackout recovery. The 230 kV components include the overhead transmission conductors and connections from the unit startup transformers to disconnects 217 and 219, the 230 kV high voltage insulators, and the switchyard bus and connections between disconnects 217 and 219. The 500 kV components include the overhead transmission conductors and connections from the main transformers to disconnects 533/631 and 543/641, the 500 kV high voltage insulators, and the switchyard bus and connections 533/631 and 543/641 and switchyard breakers 532/632 and 542/642.

PG&E has an existing preventive maintenance program that governs overhead transmission systems. This program is in accordance with the State of California General Order 95, to ensure public safety and reliability. This program requires that all 230 kV and 500 kV transmission lines be inspected by performance of aerial, ground and climbing inspections at specified frequencies. The inspections look for, but are not limited to, insulator, conductor, connector and support degradation including corrosion, mechanical wear, and contamination. Conductors are also monitored for indications of conductor degradation including conductor strand breakage, excessive corrosion and swelling. These inspections are documented, evaluated and trended. Corrective actions for abnormal conditions and failures are performed in accordance with a priority code that is based on the observed condition and its potential to result in failure.

Inspection documentation includes who performed the inspection, date, findings of the inspection and recommended maintenance activities. These observed conditions may result in follow-up inspections such as infrared thermography inspections. The components inspected during these inspections include transmission line towers, conductors, connectors, splices and insulators. This program manages degradation of insulator quality due to contamination, loss of transmission line strength and wear.

Prior to the period of extended operation, this existing program will be enhanced by issuance of a DCPP plant procedure to define scope, responsibilities, and inspection activities for the Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections aging management program within the scope of license renewal. This procedure will describe the program, objectives, and requirements to manage transmission conductors and connections, insulators, and switchyard bus and connections. The inspections look for, but are not limited to, insulator, conductor, connector and support degradation including corrosion, mechanical wear, and contamination. Conductors are also monitored for indications of conductor degradation including conductor strand breakage, excessive corrosion and swelling. The condition of inspected equipment is evaluated for acceptability.

Appendix B PG&E Letter DCL-10-158 AGING MANAGEMENT PROGRAMS Page 69 of 73 This program considers the technical information provided in EPRI 1001997, Parametersthat influence the Aging and Degradationof Overhead Conductors.

Aging Management Program Elements The results of an evaluation of each element against the 10 elements described in Appendix A of NUREG-1800, StandardReview Plan for License Renewal Applications for NuclearPower Plants, are provided below.

Scope of Program- Element I The scope of the Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections aging management program includes the 230 kV and 500 kV components required for station blackout recovery.

The 230 kV components include the overhead transmission conductors and connections from the startup transformers to disconnects 217 and 219, the 230 kV high voltage insulators, and the switchyard bus and connections between disconnects 217 and 219.

The 500 kV components include the overhead transmission conductors and connections from the main transformers to disconnects 533/631 and 543/641, the 500 kV high voltage insulators, and the switchyard bus and connections between disconnects 533/631 and 543/641 and switchyard breakers 532/632 and 542/642.

Enhancements Prior to the period of extended operation plant procedures will be enhanced to identify components required to support station blackout recovery which are in the scope of license renewal aging management. In the 230 kV switchyard, these are the components between the startup transformers and disconnects 217 and 219. In the 500 kV switchyard these are the components between the main transformers and switchyard breakers 532/632 in Unit 1 and-543/641542/642 in Unit 2.

Preventive Actions - Element 2 The Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections aging management program does not prevent degradation due to aging effects but provides measures for monitoring to detect the degradation prior to loss of intended function.

ParametersMonitored or Inspected - Element 3 The Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections aging management program is a condition monitoring program. It considers the technical information and guidance in EPRI 1001997, Parametersthat Influence the Aging and Degradationof Overhead Conductors, and EPRI TR-1013475, Plant Support Engineering:License Renewal ElectricalHandbook.

Appendix B PG&E Letter DCL-10-158 AGING MANAGEMENT PROGRAMS Page 70 of 73 The program will monitor high voltage insulators, and their supports for evidence of contamination, corrosion, and wear.

Aluminum buses are inspected for degradation of the bus due to aging that would be evidenced by corrosion buildup or cracks at joints and connections.

Connections are inspected for indication of degraded or degrading connections in the affected or parallel conductor.

Conductors and their supports at Diablo Canyon will be inspected at connections and support points for broken strands and wear.

Detection of Aging Effects - Element 4 Transmission conductors, insulators, connections and supports, switchyard bus and connections, and insulators within the scope of this program undergo annual overhead or ground based visual and infrared thermography inspections of the components. The inspections will be conducted as specified in the Transmission Conductor,. Connections, Insulators and Switchyard Bus and Connections aging management program. The inspections look for, but are not limited to, insulator, conductor, connector and support degradation including corrosion, mechanical wear, loss of preload, and contamination.

Conductors are also monitored for indications of conductor degradation including conductor strand breakage, excessive corrosion and swelling. Detailed climbing inspections of insulators, conductors and connections will be conducted prior to the period of extended operation. The frequency of subsequent climbing inspections will be based on the results of the initial inspection. Inspection results are summarized for-consistent engineering criteria evaluation of degraded conditions such as insulator contamination and switchyard bus corrosion, or mechanical wear. Corrective actions will be based on the observed degradation and will be as specified in plant procedures.

These are adequate inspection periods to detect aging effects before a loss of component intended function since experience has shown that aging degradation is a slow process. The first inspection for license renewal is to be completed prior to the period of extended operation. These frequencies will provide multiple data points during a 20-year period, which can be used to characterize the degradation rate.

Monitoring and Trending - Element 5 Monitoring of high voltage insulators, conductors, and supports for contamination, corrosion and wear or switchyard buses for corrosion and degraded connections can aid in establishing rates of degradation to ensure corrective actions prior to loss of intended function.

Visual inspection techniques and infrared thermography inspection on an annual frequency are appropriate based on industry experience. The trending of results from inspection to inspection will provide a basis for timely corrective action prior to loss of intended function.

Appendix B PG&E Letter DCL-1 0-158 AGING MANAGEMENT PROGRAMS Page 71 of 73 Infrared thermography inspection of connections provides the capability to identify increased resistance and loss of preload in the connection. Early identification provides for timely corrective actions prior to loss of function.

Enhancements Prior to the period of extended operation plant procedures will be enhanced to include gathering and reviewing completed maintenance and inspection results, by the plant staff, to identify adverse trends.

Acceptance Criteria - Element 6 Visual inspections for contamination of insulators and corrosion of switchyard bus and transmission conductors will result in consistent qualitative criteria for identifying, over time, any degradation due to aging. Corrective actions will be based on the observed degradation and will be as specified in plant procedures. The results of the inspections will be documented providing the ability to predict extent of future degradation.

Connection increased resistance, detected by infrared thermography inspection, could be evidence of connector corrosion, degradation, or loss of preload. Acceptance criteria will be based on temperature rise above a reference temperature. The reference temperature will be ambient temperature or a baseline temperature based on data from the same type of connection being tested.

Cracking of bus welds or broken cable strands will be evaluated by engineering. The evaluation will consider the extent of the condition, reportability of the event, potential root causes, probability of recurrence, and corrective actions required.

Corrective Actions - Element 7 An engineering evaluation of the results of the inspections will be conducted as specified in plant procedures when evidence of aging as described above is found. The evaluation considers the extent of condition; reportability of the event, potential root causes, the probability of recurrence, and the corrective action required. Comparison to previous inspection results for contamination, corrosion, and wear will aid in identifying degradation. Corrective actions will be performed in accordance with plant procedures and may include, but are not limited to increased inspection/hot wash frequency, replacement or repair. When an unacceptable condition or situation is identified, a determination is made as to whether the same condition or situation is applicable to other in-scope switchyard or transmission components.

DCPP site QA procedures, review and approval process, and administrative controls are implemented in accordance with the requirements of 10 CFR 50 Appendix B and are acceptable in addressing corrective actions. The QA program includes elements of corrective action, confirmation process and administrative controls and is applicable to the safety-related and non-safety related systems, structures and components (SSCs) that are subject to aging management review.

Appendix B PG&E Letter DCL-10-158 AGING MANAGEMENT PROGRAMS Page 72 of 73 Enhancements Prior to the period of extended operation plant procedures will be enhanced to identify that an engineering evaluation will be conducted when a degraded condition is detected that considers the extent of the condition, reportability of the event, potential root causes, probability of recurrence, and the corrective actions required.

Confirmation Process - Element 8 DCPP site QA procedures, review and approval process, and administrative controls are implemented in accordance with the requirements of 10 CFR 50 Appendix B and are acceptable in addressing confirmation process. The QA program includes elements of corrective action, confirmation process and administrative controls and is applicable to the safety-related and non-safety related systems, structures and components (SSCs) that are subject to aging management review.

Administrative Controls - Element 9 DCPP site QA procedures, review and approval process, and administrative controls are implemented in accordance with the requirements of 10 CFR 50 Appendix B and are acceptable in addressing administrative controls. The QA program includes elements of corrective action, confirmation process and administrative controls and is applicable to the safety-related and nonsafety-related systems, structures and components (SSCs) that are subject to aging management review.

Operating Experience - Element 10 Industry operating experience illustrates the potential for loss of insulator quality due to salt deposits on switchyard insulators. Demonstration that this aging management program will be effective is achieved through objective evidence that shows the aging effect of degradation of insulation quality caused by the presence of salt deposits is being adequately managed. The following examples of operating experience provide objective evidence that the Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections aging management program will be effective in assuring that the intended function of high voltage insulators will be maintained consistent with the current licensing basis for the period of extended operation.

In March 1993, (IN 93-95) Crystal River Unit 3 experienced a loss of the 230 kV switchyard (normal offsite power to safety-related buses) when a light rain caused arcing across salt-laden 230 kV insulators and opened switchyard breakers. In March 1993, Brunswick (LR SER) Unit 2 switchyard experienced a flashover of some high-voltage insulators attributed to a winter storm. Since 1982, Pilgrim (LR SER) experienced several losses of offsite power when ocean storms deposited salt on the 345 kV switchyard, causing the insulator to arc to ground.

Infrared thermography inspections are performed regularly on switchyard components to detect connections indicating increased resistance. These inspections have Appendix B PG&E Letter DCL-10-158 AGING MANAGEMENT PROGRAMS Page 73 of 73 occasionally detected thermal anomalies at connections resulting in activities to correct the condition prior to failure of the connection or loss of function. Continuation of annual infrared thermography inspections of connections during the period of extended operation through the Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections aging management program will assure the intended functions will be maintained consistent with the current licensing basis for the period of extended operation.

Diablo Canyon is a coastal plant subject to frequent and persistent wind, which produces salt spray that can result in -insulator contamination. Instances of corrosion resulting from the exposure of base metal on galvanized components have been observed. During the replacement Iof 500 kV insulators, it was noted that an insulator had degraded. Although corrosion was the prominent and evident degradation, some mechanical wear in the zinc galvanized coating would likely have preceded the degradation in order to expose the base metal. In May of 2007, DCPP experienced a loss of off site power, which was attributed to an insulator failure in the DCPP-Morro Bay 230 kV transmission line, which is not in the scope of license renewal. While implementing corrective actions, to!replace similar insulators, transmission line maintenance personnel noted excessive wear on insulator and conductor support hardware. The degraded hardware I was replaced with the installation of new insulators.

The transmission lines from the plant to the switchyard traverse mountainous terrain, which exposes them to persistent, and frequent high wind conditions. The plant schedules and, if necessary, conducts hot washes of the 500 kV high voltage insulators on a six-week frequency and ground or overhead infrared thermography inspections of the 230 and 500 kV insulators at least annually. Operating history has shown this process is effective in managing contamination.

Industry experience indicates failures of switchyard bus or transmission conductors are rare. The Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections aging management program will assure that the results of the inspections receive an evaluation for aging to'ensure the intended functions will be maintained consistent with the current licensing basis for the period of extended operation.

Conclusion The continued implementation of tlhe Transmission Conductor, Connections, Insulators and Switchyard Bus and Connections aging management program provides reasonable assurance that aging effects will be adequately managed such that the systems and components within the scope of license renewal will continue to perform their intended functions consistent with the current licensing basis during the period of extended operation.